Cleco Corporate 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3) Registration No. 333-238743

Prospectus

 

Cleco Corporate Holdings LLC

Offer to Exchange
up to $300,000,000 3.375% Senior Notes due 2029
which have been registered under the Securities Act
for
up to $300,000,000 3.375% Senior Notes due 2029
which have not been registered under the Securities Act

The Exchange Offer:

• We will exchange all Outstanding Notes that are validly tendered and not validly withdrawn for an equal principal amount of Exchange Notes that are freely tradable.

• You may withdraw tenders of Outstanding Notes at any time prior to the expiration date of the exchange offer.

• The exchange offer expires at 5:00 p.m., New York City time, on July 9, 2020, unless we extend the exchange offer. We currently do not intend to extend the expiration date of the exchange offer.

• The exchange of Outstanding Notes for Exchange Notes in the exchange offer generally will not be a taxable event to a holder for United States federal income tax purposes.

• We will not receive any proceeds from the exchange offer.

• The exchange offer is subject to customary conditions, including the condition that the exchange offer not violate applicable law or any applicable interpretation of the staff of the Securities and Exchange Commission.

The Exchange Notes:

• The Exchange Notes are being offered in order to satisfy certain of our obligations under the registration rights agreement entered into in connection with the private offering of the Outstanding Notes.

• The terms of the Exchange Notes to be issued in the exchange offer are substantially identical to the terms of the Outstanding Notes, except that the Exchange Notes will be freely tradable and will not contain provisions relating to additional interest relating to our registration obligations.

• We do not intend to apply for listing of the Exchange Notes on any securities exchange or to arrange for such Exchange Notes to be quoted on any quotation system.

Broker-Dealers

• Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer must acknowledge by way of the letter of transmittal that it will deliver a prospectus in connection with any resale of the Exchange Notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, such broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”).

• This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Outstanding Notes where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities.

• We have agreed that, until December 7, 2020, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

See “Risk Factors” beginning on page 14 for a discussion of certain risks that you should consider before participating in the exchange offer.

Neither the Securities and Exchange Commission (the “SEC” or the “Commission”) nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

YOU SHOULD READ THIS ENTIRE DOCUMENT AND THE ACCOMPANYING LETTER OF TRANSMITTAL AND RELATED DOCUMENTS AND ANY AMENDMENTS OR SUPPLEMENTS CAREFULLY BEFORE MAKING YOUR DECISION TO PARTICIPATE IN THE EXCHANGE OFFER.

The date of this prospectus is June 10, 2020

TABLE OF CONTENTS

CERTAIN DEFINITIONS	ii
WHERE YOU CAN FIND MORE INFORMATION	vii
FORWARD-LOOKING STATEMENTS	viii
SUMMARY	1
SUMMARY OF THE EXCHANGE OFFER	4
SUMMARY OF THE TERMS OF THE EXCHANGE NOTES	8
SUMMARY CONSOLIDATED FINANCIAL INFORMATION	12
RISK FACTORS	14
USE OF PROCEEDS	31
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
BUSINESS	69
PROPERTIES	84
LEGAL PROCEEDINGS	86
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	87
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	89
MANAGEMENT	90
EXECUTIVE COMPENSATION	98
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	124
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE	124
THE EXCHANGE OFFER	125
DESCRIPTION OF THE EXCHANGE NOTES	133
REGISTRATION RIGHTS AGREEMENT	151
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENCES	153
PLAN OF DISTRIBUTION	155
LEGAL MATTERS	156
EXPERTS	156
EXCHANGE AGENT	156
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	F-1

This prospectus is part of a registration statement we filed with the SEC. In making your decision whether to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the letter of transmittal accompanying this prospectus. We have not authorized any person to provide you with additional or different information. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. If you receive any unauthorized information, you must not rely on it. This prospectus may only be used where it is legal to exchange the Outstanding Notes for the Exchange Notes, and this prospectus is not an offer to exchange or a solicitation to exchange the Outstanding Notes for the Exchange Notes where such an offer, solicitation or exchange would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.

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CERTAIN DEFINITIONS

In this prospectus, except as the context otherwise requires or as otherwise noted, “Cleco,” the “Company,” the “Issuer,” “we,” “us” and “our” refer to Cleco Corporate Holdings LLC and its subsidiaries, except with respect to the Outstanding Notes and the Exchange Notes, in which case such terms refer only to Cleco Corporate Holdings LLC; the term “Outstanding Notes” refers to Cleco’s outstanding 3.375% Senior Notes due 2029; the term “Exchange Notes” refers to Cleco’s 3.375% Senior Notes due 2029 registered under the Securities Act and offered hereby; and the term “Notes” refers to both the Outstanding Notes and the Exchange Notes. Certain other defined terms shall have the meanings set forth below:

DEFINED TERM	DEFINITION
2016 Merger	Merger of Merger Sub with and into Cleco Corporation pursuant to the terms of the Merger Agreement which was completed on April 13, 2016
2016 Merger Commitments	Cleco Partners’, Cleco Group’s, Cleco Holdings’, and Cleco Power’s 77 commitments to the LPSC as defined in Docket No. U-33434 of which a performance report must be filed annually by October 31 for the 12 months ending June 30
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 LIBOR plus 1.0%
Acadia	Acadia Power Partners, LLC, previously a wholly owned subsidiary of Midstream. Acadia Power Partners, LLC was dissolved effective August 29, 2014
Acadia Unit 1	Cleco Power’s 580-MW, combined cycle power plant located at the Acadia Power Station in Eunice, Louisiana
Acadia Unit 2	Entergy Louisiana’s 580-MW, combined cycle power plant located at the Acadia Power Station in Eunice, Louisiana, which is operated by Cleco Power
ADIT	Accumulated Deferred Income Tax
AFUDC	Allowance for Funds Used During Construction
Amended Lignite Mining Agreement	Amended and restated lignite mining agreement effective December 29, 2009
Acquisition Term Loan Facility	A term loan facility in an aggregate principal amount of $100 million entered into in connection with the closing of the Cleco Cajun Transaction
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
Attala	Attala Transmission LLC, a wholly owned subsidiary of Cleco Holdings
BCI	British Columbia Investment Management Corporation
Brame Energy Center	A facility consisting of Nesbitt Unit 1, Rodemacher Unit 2, and Madison Unit 3
Bridge Facility	A bridge term loan facility in an aggregate principal amount of $300 million entered into in connection with the closing of the Cleco Cajun Transaction
CAA	Clean Air Act
CCR	Coal combustion by-products or residual
CECL	Current Expected Credit Losses

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DEFINED TERM	DEFINITION
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CIP	Critical Infrastructure Protection
Cleco	Cleco Holdings and its subsidiaries
Cleco Cajun	Cleco Cajun LLC (formerly Cleco Energy LLC, a wholly owned subsidiary of Cleco Holdings) and its subsidiaries
Cleco Cajun Transaction	The transaction between Cleco Cajun and NRG Energy in which Cleco Cajun acquired all the membership interest in South Central Generating, which closed on February 4, 2019, pursuant to the Purchase and Sale Agreement, which includes the Cottonwood Sale Leaseback
Cleco Corporation	Pre-2016 Merger entity that was converted to a limited liability company and changed its name to Cleco Corporate Holdings LLC on April 13, 2016
Cleco Group	Cleco Group LLC, a wholly owned subsidiary of Cleco Partners
Cleco Holdings	Cleco Corporate Holdings LLC, a wholly owned subsidiary of Cleco Group
Cleco Katrina/Rita	Cleco Katrina/Rita Hurricane Recovery Funding LLC, a wholly owned subsidiary of Cleco Power
Cleco Partners	Cleco Partners L.P., a Delaware limited partnership that is owned by a consortium of investors, including funds or investment vehicles managed by MIRA, BCI, John Hancock Financial, and other infrastructure investors
Cleco Power	Cleco Power LLC and its subsidiaries, a wholly owned subsidiary of Cleco Holdings
Como 1	Como 1, L.P., currently known as Cleco Partners
CO2	Carbon dioxide
Consent Decree	The Consent Decree, entered March 5, 2013, in Civil Action No. 09-100-JJB-DLD, United States District Court for the Middle District of Louisiana, by and among the EPA, the LDEQ, and Louisiana Generating relating to Big Cajun II, Unit 1 located in New Roads, Louisiana
Cottonwood Energy	Cottonwood Energy Company LP, a wholly owned subsidiary of Cleco Cajun. Prior to the closing of the Cleco Cajun Transaction on February 4, 2019, Cottonwood Energy was an indirect subsidiary of South Central Generating
Cottonwood Plant	Cleco Cajun’s 1,263-MW, natural-gas-fired generating station located in Deweyville, Texas
Cottonwood Sale Leaseback	A lease agreement executed and delivered between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy pursuant to which NRG Energy will lease back the Cottonwood Plant and will operate it until no later than May 2025
Coughlin	Cleco Power’s 775-MW, combined-cycle power plant located in St. Landry, Louisiana
COVID-19	Novel coronavirus disease 2019 and the related global outbreak that was subsequently declared a pandemic by the World Health Organization in March 2020
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule

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DEFINED TERM	DEFINITION
DHLC	Dolet Hills Lignite Company, LLC, a wholly owned subsidiary of SWEPCO
Diversified Lands	Diversified Lands LLC, a wholly owned subsidiary of Cleco Holdings
Dolet Hills	A facility consisting of Dolet Hills Power Station, the Dolet Hills mine, and the Oxbow mine
Dolet Hills Power Station	A 650-MW generating unit at Cleco Power’s plant site in Mansfield, Louisiana. Cleco Power has a 50% ownership interest in the capacity of Dolet Hills
EAC	Environmental Adjustment Clause
EAF	Equivalent Availability Factor
EBITDA	Earnings before interest, taxes, depreciation, and amortization
EGU	Electric Generating Unit
EFORd	Equivalent Forced Outage Rate on demand
EMT	Executive Management Team
Entergy Gulf States	Entergy Gulf States Louisiana, LLC
Entergy Louisiana	Entergy Louisiana, LLC
EPA	United States Environmental Protection Agency
ERO	Electric Reliability Organization
Evangeline	Cleco Evangeline LLC, a wholly owned subsidiary of Midstream
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, a credit rating agency
FTR	Financial Transmission Right
FRP	Formula Rate Plan
GAAP	Generally Accepted Accounting Principles in the United States
GO Zone	Gulf Opportunity Zone Act of 2005 (Public Law 109-135)
IRC	Internal Revenue Code of 1986, as amended
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
kWh	Kilowatt-hour(s)
LCFC	Lost Contribution to Fixed Cost
LDEQ	Louisiana Department of Environmental Quality
LIBOR	London Interbank Offered Rate
LMP	Locational Marginal Price
Louisiana Generating	Louisiana Generating, LLC, a wholly owned subsidiary of South Central Generating
LPSC	Louisiana Public Service Commission

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DEFINED TERM	DEFINITION
LTIP	Long-Term Incentive Compensation Plan
LTSA	Long-Term Parts and Service Agreement between Cottonwood Energy and a third party, dated January 19, 2001, that Cleco Cajun assumed as a result of the Cleco Cajun Transaction to provide maintenance services related to the Cottonwood Plant
Madison Unit 3	A 641-MW generating unit at Cleco Power’s plant site in Boyce, Louisiana
MATS	Mercury and Air Toxics Standards
Merger Agreement	Agreement and Plan of Merger, dated as of October 17, 2014, by and among Cleco Partners, Merger Sub, and Cleco Corporation relating to the 2016 Merger
Merger Sub	Cleco MergerSub Inc., previously an indirect wholly owned subsidiary of Cleco Partners that was merged with and into Cleco Corporation, with Cleco Corporation surviving the 2016 Merger, and Cleco Corporation converting to a limited liability company and changing its name to Cleco Holdings
Midstream	Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco Holdings
MIRA	Macquarie Infrastructure and Real Assets Inc.
MISO	Midcontinent Independent System Operator, Inc.
MMBtu	One million British thermal units
Moody’s	Moody’s Investors Service, a credit rating agency
MW	Megawatt(s)
MWh	Megawatt-hour(s)
N/A	Not Applicable
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NMTC	New Markets Tax Credit
Not Meaningful	A percentage comparison of these items is not statistically meaningful because the percentage difference is greater than 1,000%
NO2	Nitrogen dioxide
NOx	Nitrogen oxide
NRG Energy	NRG Energy, Inc.
NRG South Central	NRG South Central Generating LLC
Other Benefits	Includes medical, dental, vision, and life insurance for Cleco’s retirees
Oxbow	Oxbow Lignite Company, LLC, 50% owned by Cleco Power and 50% owned by SWEPCO
PCB	Polychlorinated biphenyl
Perryville	Perryville Energy Partners, L.L.C., a wholly owned subsidiary of Cleco Holdings
ppb	Parts per billion

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DEFINED TERM	DEFINITION
Predecessor	Pre-merger activity of Cleco. Cleco has accounted for the 2016 Merger transaction by applying the acquisition method of accounting. The predecessor period is not comparable to the successor period
Purchase and Sale Agreement	Purchase and Sale Agreement, dated as of February 6, 2018, by and among NRG Energy, South Central Generating, and Cleco Cajun
Registrants	Cleco Holdings and/or Cleco Power
Rodemacher Unit 2	A 523-MW generating unit at Cleco Power’s plant site in Boyce, Louisiana. Cleco Power has a 30% ownership interest in the capacity of Rodemacher Unit 2
ROE	Return on Equity
ROIC	Return on Invested Capital
ROU	Right of Use
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Services, a credit rating agency
SAIDI	System Average Interruption Duration Index
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
South Central Generating	South Central Generating LLC, formerly NRG South Central Generating LLC
SSR	System Support Resource
START	Strategic Alignment and Real-Time Transformation
STIP	Short-Term Incentive Plan
Successor	Post-merger activity of Cleco. Cleco has accounted for the 2016 Merger transaction by applying the acquisition method of accounting. The successor period is not comparable to the predecessor period
Support Group	Cleco Support Group LLC, a wholly owned subsidiary of Cleco Holdings
SWEPCO	Southwestern Electric Power Company, an electric utility subsidiary of American Electric Power Company, Inc.
TCJA	Federal tax legislation commonly referred to as the Tax Cuts and Jobs Act of 2017
Teche Unit 3	A 359-MW generating unit at Cleco Power’s plant site in Baldwin, Louisiana

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Commission a registration statement on Form S-4 under the Securities Act with respect to the Exchange Notes offered hereby. For further information with respect to us and the Exchange Notes offered hereby, we refer you to the registration statement, including the exhibits and schedules filed therewith.

We have not authorized anyone to provide you with information other than that provided in this prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should not assume that the information in this prospectus is accurate as of any date other than the date of this prospectus.

This prospectus contains summaries of certain agreements that we have entered into in connection with the issuance and sale of the Outstanding Notes and the exchange offer, such as the indenture that will govern the Exchange Notes. The descriptions contained in this prospectus of these agreements do not purport to be complete and are subject to, or qualified in their entirety by reference to, the definitive agreements. Copies of the definitive agreements will be made available without charge to you in response to a written request to us. Any such request should be directed to us at Cleco Corporate Holdings LLC, P.O. Box 5000, Pineville, Louisiana 71361-5000, Telephone: (318) 484-7400, Attention: Corporate Secretary.

We file reports and other information with the Commission. The Commission also maintains a website on the Internet that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission, and such website is located at http://www.sec.gov. You may request a copy of these filings at no cost, by writing or calling us at the following address: Cleco Corporate Holdings LLC, P.O. Box 5000, Pineville, Louisiana 71361-5000, Telephone: (318) 484-7400, Attention: Corporate Secretary.

To obtain timely delivery of any of these documents, you must request them no later than five business days before the date you must make your investment decision. Accordingly, if you would like to request any documents, you should do so no later than July 1, 2020 in order to receive them before the expiration of the exchange offer.

Pursuant to the indenture under which the Exchange Notes will be issued (and the Outstanding Notes were issued), we have agreed that, whether or not we are required to do so by the rules and regulations of the Commission, for so long as any of the Notes remain outstanding, we (not including our subsidiaries) will furnish to the holders of the Notes copies of all quarterly and annual financial information that would be required to be contained in a filing with the Commission on Forms 10-Q and 10-K if we were required to file such forms and all current reports that would be required to be filed with the Commission on Form 8-K if we were required to file such reports, in each case within the time periods specified in the Commission’s rules and regulations. In addition, following the consummation of the exchange offer, whether or not required by the rules and regulations of the Commission, we will file a copy of all such information and reports with the Commission for public availability within the time periods specified in the Commission’s rules and regulations (unless the Commission will not accept such a filing) and make such information available to securities analysts and prospective investors upon request.

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FORWARD-LOOKING STATEMENTS

Certain statements included in this prospectus may be “forward-looking statements” within the meaning of the Securities Act and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Words such as “may,” “should,” “expects,” “intends,” “projects,” “plans,” “believes,” “estimates,” “targets,” “anticipates” and similar expressions are used to identify these forward-looking statements. Forward-looking statements are based upon assumptions about future events that may not be accurate. These statements are not guarantees of future performance and involve risks, uncertainties and assumptions that are difficult to predict. Actual outcomes and results may differ materially from what is expressed or forecasted in these forward-looking statements. Any forward-looking statement speaks only as of the date on which it is made, and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

Specific factors that could cause actual results to differ materially from forward-looking statements include, but are not limited to, those set forth below and other important factors disclosed previously and from time-to-time in our other filings with the SEC:

• the result of the exchange offer;

• the COVID-19 pandemic and its effect on Cleco, Cleco’s operations, business, and financial condition, and the communities it serves, United States and world financial markets and supply chains, potential regulatory actions, changes in customer and stakeholder behaviors, and impacts on and modifications to Cleco’s operations, business, and financial condition relating thereto;

• the effects of the Cleco Cajun Transaction and the 2016 Merger on Cleco’s business relationships, operating results, and business generally;

• the ability to successfully remediate underlying causes of identified material weaknesses in internal control over financial reporting;

• regulatory factors, such as changes in rate-setting practices or policies; political actions of governmental regulatory bodies; adverse regulatory ratemaking actions; recovery of investments made under traditional regulation; recovery of storm restoration costs; the frequency, timing, and amount of rate increases or decreases; the impact that rate cases or requests for FRP extensions may have on operating decisions of Cleco Power; the results of periodic NERC, LPSC, and FERC audits; participation in MISO and the related operating challenges and uncertainties, including increased wholesale competition relative to additional suppliers; and compliance with the ERO reliability standards for bulk power systems by Cleco Power;

• Cleco Power’s ability to recover fuel costs through the FAC;

• the ability to successfully integrate the assets acquired in the Cleco Cajun Transaction into Cleco’s operations;

• factors affecting utility operations, such as unusual weather conditions or other natural phenomena; catastrophic weather-related damage caused by hurricanes and other storms or severe drought conditions; pandemic illnesses, specifically COVID-19; unexpected delays in capital projects; unscheduled generation outages; unanticipated maintenance or repairs; unanticipated changes to fuel costs or fuel supply costs, shortages, solid fuel and natural gas transportation problems, or other developments; decreased customer load; environmental incidents and compliance costs; and power transmission system constraints;

• reliance on third parties for determination of Cleco’s commitments and obligations to markets for generation resources and reliance on third-party fuel transportation and transmission services;

• global and domestic economic conditions, including the negative impact of COVID-19, the ability of customers to continue paying their utility bills, related growth and/or down-sizing of businesses in Cleco’s service area, monetary fluctuations, and inflation rates;

• political uncertainty in the United States, including uncertainty relating to the United States. federal government budget and debt ceiling, and volatility and disruption in global capital and credit markets;

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• the ability of the lignite reserves at Dolet Hills to provide sufficient fuel to the Dolet Hills Power Station to meet projected dispatch needs;

• the timing and costs associated with the potential early closure of Dolet Hills, including the ability to recover those costs;

• Cleco’s ability to maintain its right to sell wholesale power at market-based rates within its control area;

• Cleco’s dependence on energy from sources other than its facilities and future sources of such additional energy;

• reliability of Cleco’s generating facilities;

• the imposition of energy efficiency requirements or increased conservation efforts of customers;

• the impact of current or future environmental laws and regulations, including those related to CCRs, greenhouse gases, and energy efficiency that could limit or terminate the operation of Cleco’s generating units, increase costs, or reduce customer demand for electricity;

• the ability to recover costs of compliance with environmental laws and regulations, including those through Cleco Power’s EAC;

• financial or regulatory accounting principles or policies imposed by FASB, the SEC, FERC, the LPSC, or similar entities with regulatory or accounting oversight;

• changing market conditions and a variety of other factors associated with physical energy, financial transactions, COVID-19, and energy service activities, including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, interest rates, and warranty risks;

• changes in commodity prices and transportation costs;

• legal, environmental, and regulatory delays and other obstacles associated with acquisitions, reorganizations, investments in joint ventures, or other capital projects;

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

• the availability and use of alternative sources of energy and technologies, such as wind, solar, battery storage, and distributed generation;

• changes in federal, state, or local laws (including the TCJA and other tax laws), changes in tax rates, disallowances of tax positions, or changes in other regulatory policies that may result in a change to tax benefits or expenses;

• the restriction on the ability of Cleco Power to make distributions to Cleco Holdings in certain instances, as a result of the 2016 Merger Commitments;

• Cleco’s ability to remain in compliance with the commitments made to the LPSC in connection with the Cleco Cajun Transaction;

• Cleco Holdings’ dependence on the earnings, dividends, or distributions from its subsidiaries to meet its debt obligations;

• 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;

• the ability to successfully modify or transition Cleco’s legacy enterprise business applications into new systems;

• credit ratings of Cleco Holdings and Cleco Power;

• Cleco Holdings’ and Cleco Power’s ability to remain in compliance with their respective debt covenants;

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

• workforce factors, including aging workforce, changes in management, impact of pandemic illnesses, specifically COVID-19, and unavailability of skilled employees; and

• other factors we discuss in this prospectus.

We urge you to consider these factors and to review carefully the section captioned “Risk Factors” in this prospectus for a more complete discussion of the risks associated with an investment in the Exchange Notes. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the applicable cautionary statements. The forward-looking statements included in this prospectus are made only as of their respective dates, and we undertake no obligation to update these statements to reflect subsequent events or circumstances.

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SUMMARY

This summary highlights certain information about our business and about the exchange of Outstanding Notes for Exchange Notes in the exchange offer. This is a summary of information contained elsewhere in this prospectus, is not complete and does not contain all of the information that may be important to you. You should read the following summary together with the more detailed information and consolidated financial statements and the notes to those statements included in this prospectus. You should read carefully this prospectus, including the matters set forth under the caption “Risk Factors,” before making a decision whether to participate in the exchange offer.

Overview

Cleco is a public utility holding company that holds investments in several subsidiaries, including:

• Cleco Power, which is a wholly owned subsidiary of Cleco that engages primarily in the generation, transmission, distribution and sales of electricity. Cleco Power is a regulated electric utility company that, as of March 31, 2020, owns 10 generating units with a total nameplate capacity of 3,360 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi; and

• Cleco Cajun (f/k/a Cleco Energy LLC), which is a wholly owned unregulated subsidiary of Cleco that owns eight generating assets with a rated capacity of 3,555 MW, and supplies wholesale power and capacity to nine Louisiana cooperatives, three municipalities across Arkansas, Louisiana and Texas and one investor-owned utility. Seven of the generating assets are managed by Cleco, while the Cottonwood plant in Texas is temporarily leased to NRG Energy. Cleco acquired these assets from NRG Energy in February 2019. See “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations” for more information.

Since a substantial portion of our operations are conducted through Cleco Power, a primary source of funds for the repayment of our indebtedness, including the Exchange Notes, is distributions and dividends from Cleco Power, which is subject to numerous restrictions on its ability to make such distributions and dividends, including from state corporate law, Cleco Power’s indentures and credit agreements, and state and local regulations. Cleco Power has also made certain regulatory commitments that restrict its ability to make distributions and dividends to us.

Cleco was incorporated as “Cleco Corporation” on October 30, 1998 as a corporation organized under the laws of the State of Louisiana. On April 13, 2016, Cleco MergerSub Inc., previously an indirect, wholly owned subsidiary of Cleco Partners, merged with and into Cleco Corporation, with Cleco Corporation surviving the merger. Thereafter, Cleco Corporation converted into a limited liability company organized under the laws of the State of Louisiana and changed its name to Cleco Corporate Holdings LLC, a direct, wholly owned subsidiary of Cleco Group and an indirect, wholly owned subsidiary of Cleco Partners. See “Business — General” for more information. Cleco, 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, as amended.

Cleco’s principal executive office is located at 2030 Donahue Ferry Road, Pineville, Louisiana 71360, and its telephone number is (318) 484-7400. Cleco’s website is located at www.cleco.com. Cleco’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 or furnished to the SEC. Information on Cleco’s website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Recent Developments

COVID-19

On March 11, 2020, the World Health Organization declared the current COVID-19 outbreak to be a global pandemic, and on March 13, 2020, the United States declared a national emergency. In response to these declarations and the rapid spread of COVID-19, federal, state and local governments have imposed varying

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degrees of restrictions on business and social activities to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory. Cleco has modified some of its business operations, as these restrictions have significantly impacted many sectors of the economy, including record levels of unemployment, with businesses, nonprofit organizations, and governmental entities modifying, curtailing, or ceasing normal operations. Cleco has also modified certain business practices to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. For example, since March 13, 2020, Cleco temporarily closed all customer service offices, temporarily suspended disconnects and late fees, restricted access to its administrative offices, implemented remote work arrangements, prohibited all non-critical travel for Cleco business, prohibited in-person gatherings of more than 10 people at Cleco work locations, and required all meetings to be held virtually or via telephone.

Cleco provides a critical service to its customers which means that it is paramount that it keeps its employees who operate its business safe and informed and has taken and continues to take and update precautions for that purpose. In addition, Cleco assessed and updated its existing business continuity plans for its business units in the context of the COVID-19 pandemic. The LPSC has issued a moratorium on disconnects of customers for non-payment, and accordingly Cleco has taken steps to assure its customers that disconnections for non-payment as well as late fees are temporarily suspended. Cleco is also working with its suppliers to understand the potential impacts to its supply chain. This is a rapidly evolving situation and could lead to extended disruption of economic activity in Cleco’s service territory. Cleco will continue to monitor developments affecting its workforce, customers, and suppliers and take additional precautions as Cleco believes are warranted.

The first priority in Cleco’s response to this crisis has been the health and safety of its employees and those of its customers and other business counterparties. Cleco has implemented preventative measures and developed corporate response plans to minimize unnecessary risk of exposure and prevent infection, while supporting its customers’ operations to the best of its ability in the circumstances. Cleco has an Emergency (Crisis) Response Team for health, safety, and environmental matters and personnel issues, and has established a Pandemic Plan Team to address various impacts of COVID-19 as they have been developing. This team provides leadership and guidance for planning, risk management, and any policy changes. The team ensures that areas of Cleco plan, manage, and safely execute the pandemic plan set forth by management. Cleco employees are required to report daily to their manager or supervisor any changes to the employee’s health, the employee’s family’s health, and travel plans. This is reported to the Pandemic Plan Team at a minimum of three times per week. The results are then communicated on a weekly update call to all employees. Proper measures are taken for any employee at risk of having COVID-19 and measures are taken to protect any employees with which the at-risk employee had been in contact. Cleco also has modified certain business practices, including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences, to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other federal, state, and local governmental and regulatory authorities. Cleco is continuing to address concerns to protect the health and safety of its employees and those of its customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, Cleco, its suppliers, and other business counterparties to experience operational delays.

In addition, Cleco has implemented certain measures that it believes will provide financial flexibility and maintain liquidity. On March 23, 2020, Cleco Holdings made an $88.0 million draw on its credit facility, and Cleco Power made a $150.0 million draw on its credit facility. While Cleco continues to assess the COVID-19 situation, at this time Cleco cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the markets will have on its business, cash flows, liquidity, financial condition, and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities,

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including the LPSC and FERC, Cleco’s customers and suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding certain risks associated with the COVID-19 pandemic, see “Risk Factors — COVID-19.”

Credit Facility Amendments

On May 15, 2020, Cleco Holdings entered into amendments to its revolving credit facility and its two outstanding term loan facilities (collectively, the “Cleco Holdings Amendments”). Also, on May 15, 2020, Cleco Power entered into an amendment to its revolving credit facility (the “Cleco Power Amendment” and, together with the Cleco Holdings Amendments, the “Amendments”). The Amendments extend the terms of each facility through June 28, 2022. The current borrowing costs under the amended Cleco Holdings revolving credit facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. Cleco Holdings’ amended $300.0 million term loan bears interest at an interest rate of LIBOR plus 1.875% and Cleco Holdings’ amended $30.0 million term loan bears interest at an interest rate of LIBOR plus 1.875%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and additional interest of 0.50% under any of the Cleco Holdings Amendments. The current borrowing costs under the amended Cleco Power revolving credit facility are equal to LIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees of 0.150%. If Cleco Power’s credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of 0.125% under the Cleco Power Amendment. The Amendments also include customary LIBOR-transition provisions.

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SUMMARY OF THE EXCHANGE OFFER

On September 11, 2019, we issued $300,000,000 aggregate principal amount of unregistered 3.375% Senior Notes due 2029. On the issuance date for the Outstanding Notes, we entered into a registration rights agreement in which we agreed, among other things, to use our reasonable best efforts to complete an exchange offer for the Outstanding Notes. The following summary contains basic information about the exchange offer and is not intended to be complete. For a more detailed description of the Exchange Notes, please refer to the section entitled “Description of the Exchange Notes” in this prospectus.

General

In connection with the private offering of the Outstanding Notes, we entered into a registration rights agreement with the initial purchasers of the Outstanding Notes in which we agreed to deliver this prospectus to you and to use our reasonable best efforts to complete an exchange offer for the Outstanding Notes.

Exchange Offer

We are offering to exchange $300.0 million aggregate principal amount of Outstanding Notes for up to $300.0 million aggregate principal amount of Exchange Notes. The Outstanding Notes may be exchanged only in denominations of $2,000 and integral multiples of $1,000.

Resale of the Exchange Notes

Based on the position of the staff of the Division of Corporation Finance of the Commission in certain interpretive letters issued to third parties in other transactions, we believe that the Exchange Notes acquired in the exchange offer may be freely traded without compliance with the provisions of the Securities Act, if:

•
you are acquiring the Exchange Notes in the ordinary course of your business,

•
you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the Exchange Notes, and

•
you are not our affiliate as defined in Rule 405 of the Securities Act.

If you fail to satisfy any of these conditions, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the Exchange Notes.

Broker-dealers that acquired Outstanding Notes directly from us, but not as a result of market-making activities or other trading activities, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the Exchange Notes. See “Plan of Distribution.”

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer in exchange for Outstanding Notes that it acquired as a result of market-making or other trading activities must

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deliver a prospectus in connection with any resale of the Exchange Notes and provide us with a signed acknowledgement of this obligation.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on July 9, 2020, unless we decide to extend it.

Conditions to the Exchange Offer

The exchange offer is subject to limited, customary conditions, which we may waive.

Procedures for Tendering Outstanding Notes

If you wish to accept the exchange offer, you must deliver to the exchange agent, before the expiration of the exchange offer:

•
either a completed and signed letter of transmittal or, for Outstanding Notes tendered electronically, an agent’s message from The Depository Trust Company (“DTC”), Euroclear Bank S.A./N.V., as operator of the Euroclear System (“Euroclear”), or Clearstream Banking, société anonyme (“Clearstream”), stating that the tendering participant agrees to be bound by the letter of transmittal and the terms of the exchange offer,

•
your Outstanding Notes, either by tendering them in physical form or by timely confirmation of book-entry transfer through DTC, Euroclear or Clearstream, and

•
all other documents required by the letter of transmittal.

If you hold Outstanding Notes through DTC, Euroclear or Clearstream, you must comply with their standard procedures for electronic tenders, by which you will agree to be bound by the letter of transmittal.

By signing, or by agreeing to be bound by, the letter of transmittal, you will be representing to us that:

•
you will be acquiring the Exchange Notes in the ordinary course of your business,

•
you have no arrangement or understanding with any person to participate in the distribution of the Exchange Notes, and

•
you are not our affiliate as defined under Rule 405 of the Securities Act.

See “The Exchange Offer — Procedures for Tendering.”

Guaranteed Delivery Procedures for Tendering Outstanding Notes

None.

Special Procedures for Beneficial Holders

If you beneficially own Outstanding Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to

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tender in the exchange offer, you should contact that registered holder promptly and instruct that person to tender on your behalf. If you wish to tender in the exchange offer on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Notes, either arrange to have the Outstanding Notes registered in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

Acceptance of Outstanding Notes and Delivery of Exchange Notes

We will accept any Outstanding Notes that are properly tendered for exchange before 5:00 p.m., New York City time, on the day the exchange offer expires. The Exchange Notes will be delivered promptly after expiration of the exchange offer.

Exchange Date

We will notify the exchange agent of the date of acceptance of the Outstanding Notes for exchange.

Withdrawal Rights

If you tender your Outstanding Notes for exchange in the exchange offer and later wish to withdraw them, you may do so at any time before 5:00 p.m., New York City time, on the day the exchange offer expires.

Consequences of Failure to Exchange Outstanding Notes

Outstanding Notes that are not tendered in the exchange offer or are not accepted for exchange will continue to bear legends restricting their transfer. You will not be able to sell the Outstanding Notes unless:

•
an exemption from the requirements of the Securities Act is available to you,

•
we register the resale of Outstanding Notes under the Securities Act, or

•
the transaction requires neither an exemption from nor registration under the requirements of the Securities Act.

After the completion of the exchange offer, we will no longer have any obligation to register the Outstanding Notes, except in limited circumstances.

Accrued Interest on the Outstanding Notes

Any interest that has accrued on an Outstanding Note before its exchange in the exchange offer will be payable on the Exchange Note on the first interest payment date after the completion of the exchange offer.

United States Federal Income Tax Consequences

The exchange of the Outstanding Notes for the Exchange Notes generally will not be a taxable event for United States federal income tax purposes. See “Certain United States Federal Income Tax Consequences.”

Exchange Agent

Regions Bank

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Use of Proceeds

We will not receive any cash proceeds from the exchange offer. See “Use of Proceeds.”

Registration Rights Agreement

When we issued the Outstanding Notes on September 11, 2019, we entered into a registration rights agreement with the initial purchasers of the Outstanding Notes. Under the terms of the registration rights agreement, we agreed to use our reasonable best efforts to file and to cause to become effective a registration statement within 365 days after the closing of the issuance of the Outstanding Notes, with respect to an offer to exchange the Outstanding Notes for other freely tradable notes issued by us and that are registered with the Commission and that have substantially identical terms as the Outstanding Notes by certain specified dates. Under the terms of the registration rights agreement, we may become obligated to pay additional interest on the Outstanding Notes depending on the effective date of the registration statement, of which this prospectus forms a part. See “Registration Rights Agreement.”

Accounting Treatment

We will not recognize any gain or loss for accounting purposes upon the completion of the exchange offer in accordance with GAAP. See “The Exchange Offer — Accounting Treatment.”

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SUMMARY OF THE TERMS OF THE EXCHANGE NOTES

The form and terms of the Exchange Notes will be identical in all material respects to the form and terms of the Outstanding Notes except that:

• the Exchange Notes will be registered under the Securities Act and therefore will not bear legends restricting their transfer; and

• specified rights under the registration rights agreement, including the provisions providing for registration rights and the payment of additional interest in specified circumstances, will be limited or eliminated.

The Exchange Notes will evidence the same principal amount of debt and interest as the corresponding Outstanding Notes, and the same indenture will govern both the Outstanding Notes and the Exchange Notes. For a more complete understanding of the Exchange Notes, please refer to the section of this prospectus entitled “Description of Exchange Notes.”

Issuer

Cleco Corporate Holdings LLC

Notes Offered

$300,000,000 aggregate principal amount of 3.375% Senior Notes due 2029.

Interest Rate

The Exchange Notes bear interest at 3.375% per annum.

Maturity Date

The Exchange Notes will mature on September 15, 2029.

Interest Payment Dates

Interest is payable on the Exchange Notes semi-annually in arrears on March 15 and September 15 of each year. No interest will be paid on either the Exchange Notes or the Outstanding Notes at the time of exchange. Interest on the Exchange Notes will accrue from March 15, 2020. Assuming the Exchange Notes are issued prior to September 15, 2020, holders of Outstanding Notes that are accepted for exchange in the exchange offer will be deemed to have waived the right, if any, to receive any payment in respect of interest accrued on the Outstanding Notes from March 15, 2020 until the date of the issuance of the Exchange Notes. Holders of the Exchange Notes will receive the same interest payments that they would have received had their Outstanding Notes not been accepted for exchange in the exchange offer.

Optional Redemption

At any time and from time to time prior to June 15, 2029, we may, at our option, redeem the Exchange Notes in whole or in part, at a redemption price equal to the greater of (a) 100% of the principal amount of the Exchange Notes then outstanding to be redeemed and (b) the applicable “make-whole” amount based on United States treasury rates as specified in this prospectus under “Description of the Exchange Notes — Optional Redemption,” plus, in each case, accrued and unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date.

At any time and from time to time on or after June 15, 2029, we may redeem the Exchange Notes at our option in whole or in part by paying 100% of the principal amount to be redeemed plus accrued and

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unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date. For additional information, please see “Description of the Exchange Notes — Optional Redemption.”

Ranking

The Exchange Notes will be the Issuer’s senior unsecured obligations and will:

•
rank pari passu in right of payment with all of the Issuer’s existing and future senior unsecured and unsubordinated indebtedness;

•
be effectively subordinated to all existing and future secured indebtedness of the Issuer to the extent of the value of the collateral securing such indebtedness;

•
be senior in right of payment to any of the Issuer’s future subordinated indebtedness; and

•
be structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of the Issuer’s subsidiaries, including Cleco Power and Cleco Cajun.

As of March 31, 2020, the Issuer had $1.77 billion of senior unsecured and unsubordinated indebtedness outstanding, including outstanding borrowings of $88.0 million under its revolving credit facility, and no secured indebtedness. As of March 31, 2020, our subsidiaries had $1.53 billion of indebtedness outstanding, including outstanding borrowings of $150.0 million under Cleco Power’s revolving credit facility. At March 31, 2020, Cleco had two separate revolving credit facilities, one for the Issuer in the amount of $175.0 million and one for Cleco Power in the amount of $300.0 million.

Change of Control

Upon the occurrence of a Change of Control Repurchase Event, each holder of the Exchange Notes will have the right, at the holder’s option, to require us to repurchase all or any part of the holder’s Exchange Notes at a purchase price in cash equal to 101% of the principal thereof, plus accrued and unpaid interest, including additional interest, if any, to the date of such purchase in accordance with the procedures set forth in the indenture. See “Description of the Exchange Notes — Purchase of Notes Upon Change of Control Repurchase Event.”

Events of Default

For a discussion of events that may result in the acceleration of the payment of the principal of, and accrued interest on, the Exchange Notes, see “Description of the Exchange Notes — Events of Default.”

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Reopening of Exchange Notes

We may from time to time, without the consent of the existing holders of the Outstanding Notes or the Exchange Notes, “reopen” the Exchange Notes which means we can create and issue additional Exchange Notes (any such Exchange Notes, “Additional Notes”) having the same terms and conditions as the Exchange Notes in all respects (except for the offering price and issue date); provided that such Additional Notes are fungible with the previously issued and outstanding Exchange Notes for United States federal income tax purposes. Additional Notes will be consolidated with, and form a single series with, the previously outstanding Exchange Notes for all purposes under the indenture.

No Guarantees or Credit Support

The obligations to pay the principal of, premium, if any, and interest on the Exchange Notes are solely the obligations of the Issuer, and none of Cleco Partners, the members of the consortium that own Cleco Partners, or any of our subsidiaries or other affiliates will guarantee or provide any credit support for the Exchange Notes.

Minimum Denominations

$2,000 and integral multiples of $1,000 in excess thereof.

Book-Entry Delivery and Settlement

The Exchange Notes will be issued in fully registered book-entry form and will be represented by one or more global certificates, which will be deposited with or on behalf of DTC and registered in the name of DTC’s nominee. Beneficial interests in global certificates will be shown on, and transfers thereof will be effected only through, records maintained by DTC and its direct and indirect participants, and your interest in any global certificate may not be exchanged for certificated Exchange Notes, except in limited circumstances described herein. See “Description of the Exchange Notes — Book-Entry Delivery and Settlement.”

Certain Covenants

The indenture governing the Exchange Notes contains certain covenants that, among other things, restrict our ability to merge, consolidate or transfer or lease all or substantially all of our assets or create or incur liens. These covenants are subject to important exceptions and qualifications as described in this prospectus under the caption “Description of the Exchange Notes — Certain Covenants.”

No Public Market

We do not intend to list the Exchange Notes on any securities exchange or automated dealer quotation system. The Exchange Notes will be new securities for which there currently is no public market.

Trustee

Regions Bank

Governing Law

The Exchange Notes and the indenture will be governed by the laws of the State of New York.

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Use of Proceeds

The issuance of the Exchange Notes will not provide us with any new proceeds. We are making the exchange offer solely to satisfy our obligations under the registration rights agreement.

Risk Factors

You should refer to the section entitled “Risk Factors” for a discussion of material risks that you should carefully consider before deciding to invest in the Exchange Notes.

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SUMMARY CONSOLIDATED FINANCIAL INFORMATION

The following table shows summary consolidated financial information at the dates and for the periods indicated. The summary consolidated balance sheets of Cleco Corporate Holdings LLC and its subsidiaries (the “Successor” or the “Company”) as of December 31, 2019, 2018, 2017 and 2016 and related summary consolidated statements of income and cash flows for the years ended December 31, 2019, 2018 and 2017 and for the period April 13, 2016 to December 31, 2016 are derived from our audited consolidated financial statements included in this prospectus. The summary consolidated balance sheet of Cleco Corporation and its subsidiaries (the “Predecessor”) as of December 31, 2015 and related summary consolidated statements of income and cash flows for the period January 1, 2016 to April 12, 2016 and for the year ended December 31, 2015 are derived from the Predecessor’s audited consolidated financial statements not included in this prospectus.

The summary consolidated balance sheets of the Company as of March 31, 2020 and related summary consolidated statements of income and cash flows for the three months ended March 31, 2020 and March 31, 2019 have been derived from our unaudited condensed consolidated financial statements included in this prospectus. The unaudited financial data presented have been prepared on a basis consistent with our audited consolidated financial statements. In the opinion of management, such unaudited financial data reflect all adjustments, consisting only of normal and recurring adjustments necessary for a fair presentation of the results for those periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

The summary consolidated financial information provided below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Successor						Predecessor
	For the Three Months Ended March 31,		Fiscal Year Ended December 31,			Apr. 13 – Dec. 31,	Jan. 1 – Apr. 12,	Fiscal Year Ended December 31,
	2020	2019	2019	2018	2017	2016	2016	2015
	(in thousands)
Income statement data:
Operating revenue, net	$347,572	$344,186	$1,639,605	$1,231,044	$1,175,646	$853,005	$299,870	$1,209,402
Operating expenses	292,907	293,600	1,324,711	986,487	910,419	808,096	276,060	922,063
Operating income	54,665	50,586	314,894	244,557	265,227	44,909	23,810	287,339
Net income (loss)	6,328	20,557	152,665	94,437	138,080	(24,113)	(3,960)	133,669
Cash flow statement data:
Net cash provided by operating activities	60,206	108,129	430,119	317,761	265,428	69,890	129,780	361,022
Net cash used in investing activities	(65,413)	(892,661)	(1,115,423)	(288,160)	(203,554)	(135,261)	(41,658)	(167,951)
Net cash (used in) provided by financing activities	226,796	770,599	687,813	(41,717)	20,757	(5,999)	(40,885)	(169,248)

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	Successor					Predecessor
	As of March 31,	As of December 31,
	2020	2019	2018	2017	2016	2015
	(in thousands unless otherwise indicated)
Balance sheet and other data:
Cash and cash equivalents	350,231	116,292	110,175	119,040	23,077	68,246
Total assets	7,676,195	7,476,298	6,436,814	6,278,382	6,343,144	4,323,354
Long-term debt and finance lease, net (1)	3,113,239	3,064,679	2,874,485	2,836,105	2,738,571	1,267,703
Member’s equity	2,649,748	2,643,006	2,124,740	2,096,357	2,046,763	1,674,841

(1)
Represents long-term debt plus fair value of long-term debt related to the 2016 Merger adjustments, net of unamortized discount, debt issuance costs and amounts due within one year.

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RISK FACTORS

The exchange offer and an investment in the Exchange Notes involves risks. In deciding whether to participate in the exchange offer, you should carefully consider the risks and uncertainness described below, which could cause our operating results and financial condition to be materially adversely affected, as well as other information and data included in this prospectus.

The risks and uncertainties described below are not the only ones that we face. Additional risks and uncertainties, including those generally affecting the industry in which we operate, risks that are unknown to us or that we currently deem immaterial and risks and uncertainties generally applicable to companies that have recently undertaken transactions similar to the exchange offer, may also impair our business, the value of your investment and our ability to pay interest on, and repay or refinance, the Exchange Notes.

If any of the following risks or uncertainties actually were to occur, our business, financial condition, results of operations or cash flow could be affected materially and adversely. In that case, you could lose all or part of your investment in or fail to achieve the expected return on the Exchange Notes.

RISKS RELATED TO THE EXCHANGE OFFER

If you fail to tender and exchange your Outstanding Notes, you will continue to hold Outstanding Notes subject to existing transfer restrictions and the market value of your unexchanged Outstanding Notes may be adversely affected because they may be more difficult to sell.

If you fail to exchange your Outstanding Notes for Exchange Notes in the exchange offer, you will continue to be subject to the existing transfer restrictions on your Outstanding Notes. In general, the Outstanding Notes may not be offered or sold unless the offer and sale are registered or exempt from registration under the Securities Act and applicable state securities laws. Except in connection with the exchange offer or as required by the registration rights agreement, we do not intend to register the offer and sale of any Outstanding Notes or any resales of any Outstanding Notes.

Any tenders of Outstanding Notes in the exchange offer will reduce the principal amount of the Outstanding Notes. Due to the corresponding reduction in liquidity, this may have an adverse effect upon, and increase the volatility of, the market price of any Outstanding Notes that you continue to hold following completion of the exchange offer.

You must comply with the exchange offer procedures to receive Exchange Notes.

Delivery of Exchange Notes in exchange for Outstanding Notes tendered and accepted for exchange pursuant to the exchange offer will be made only after timely receipt by the exchange agent of the following:

• certificates for Outstanding Notes or a book-entry confirmation of a book-entry transfer of Outstanding Notes into the exchange agent’s account at DTC, New York, New York as a depository, including an agent’s message, as defined in this prospectus, if the tendering holder does not deliver a letter of transmittal;

• a complete and signed letter of transmittal, or facsimile copy, with any required signature guarantees, or, in the case of a book-entry transfer, an agent’s message in place of the letter of transmittal; and

• any other documents required by the letter of transmittal.

Therefore, holders of Outstanding Notes who would like to tender Outstanding Notes in exchange for Exchange Notes should be sure to allow enough time for the necessary documents to be timely received by the exchange agent. We are not required to notify you of defects or irregularities in tenders of Outstanding Notes for exchange. Outstanding Notes that are not tendered, or that are tendered but we do not accept for exchange, will, following consummation of the exchange offer, continue to be subject to the existing transfer restrictions under the Securities Act and will no longer have the registration and other rights under the registration rights agreement. See “The Exchange Offer — Procedures for Tendering” and “The Exchange Offer — Consequences of Failures to Properly Tender Outstanding Notes in the Exchange.”

The exchange offer may be cancelled or delayed.

Our obligation to accept Outstanding Notes tendered in the exchange offer is subject to certain closing conditions. Please read “The Exchange Offer — Conditions to the Exchange Offer.” We may, at our option and in our sole discretion, assert or waive these conditions. Even if the exchange offer is completed, the exchange

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offer may not be completed on the schedule described in this prospectus. Accordingly, holders participating in the exchange offer may have to wait longer than expected to receive their Exchange Notes, during which time those holders of Outstanding Notes will not be able to effect transfers of their Outstanding Notes tendered for exchange.

Some holders who exchange their Outstanding Notes may be deemed to be underwriters, and these holders will be required to comply with the registration and prospectus delivery requirements in connection with any resale transaction.

If you exchange your Outstanding Notes in the exchange offer for the purpose of participating in a distribution of the Exchange Notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. Any broker-dealer that will receive Exchange Notes for its own account in exchange for Outstanding Notes that were acquired as a result of market-making activities or other trading activities may be a statutory underwriter and must deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such Exchange Notes.

RISKS RELATING TO THE EXCHANGE NOTES

The Exchange Notes will be structurally subordinated to claims of creditors of Cleco Power, Cleco Cajun and our other subsidiaries.

The Exchange Notes will be structurally subordinated to indebtedness and other liabilities of Cleco Power, Cleco Cajun and our other subsidiaries. As of March 31, 2020, our subsidiaries had $1.53 billion of indebtedness outstanding, including outstanding borrowings of $150.0 million under the Cleco Power revolving credit facility. At March 31, 2020, Cleco Power had a $300.0 million revolving credit facility. Any right that we have pursuant to our equity interest in Cleco Power and Cleco Cajun to receive any assets of such subsidiary upon the liquidation or reorganization of such subsidiary, and the consequent rights of holders of the Exchange Notes to realize proceeds from the sale of such subsidiary’s assets, will be subordinated to the claims of such subsidiary’s creditors, including trade creditors. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our subsidiaries, including Cleco Power and Cleco Cajun, such subsidiary will pay the holders of its indebtedness and its trade creditors before it will be able to distribute any of its assets to us on account of our equity interest in such subsidiary.

Although the Exchange Notes are designated as “Senior,” a holder’s right to receive payment on the Exchange Notes will be unsecured and effectively subordinated to any future secured debt of Cleco, to the extent of the value of the collateral therefor.

The Exchange Notes will be general senior unsecured obligations and therefore will be effectively subordinated to Cleco’s future secured indebtedness, to the extent of the value of the collateral therefor. If Cleco defaults on the Exchange Notes or certain other indebtedness, or becomes bankrupt, liquidates or reorganizes, any secured creditors could use the value of the collateral securing that debt to satisfy their secured indebtedness before a holder of the Exchange Notes would receive any payment on the Exchange Notes. If the value of such collateral is not sufficient to pay any secured indebtedness in full, Cleco’s secured creditors would share the value of Cleco’s other assets, if any, with holders of the Exchange Notes and the holders of other claims against us which rank equally with the Exchange Notes.

As of March 31, 2020, Cleco Holdings had $1.77 billion of indebtedness, including outstanding borrowings of $88.0 million under its revolving credit facility, and no secured indebtedness. At March 31, 2020, Cleco Holdings had a $175.0 million revolving credit facility.

The indenture permits us to incur additional debt.

The indenture governing the Exchange Notes does not place any limitation on the amount of debt that may be incurred by Cleco or any of our subsidiaries, including Cleco Power or Cleco Cajun. We may therefore incur a significant amount of additional debt. Cleco Power and Cleco Cajun may also incur additional debt, which could affect their ability to pay dividends to us. The incurrence of additional debt may have important consequences for holders of the Exchange Notes, including making it more difficult for us to satisfy our obligations with respect to the Exchange Notes, a loss in the trading value of the Exchange Notes, if any, and a risk that the credit rating of the Exchange Notes is lowered or withdrawn.

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We may not be able to repurchase the Exchange Notes upon a change in control or upon the exercise of the holders’ options to require repurchase of the Exchange Notes.

Upon the occurrence of specific types of change in control events, holders will have the right to require us to repurchase the Exchange Notes at a purchase price in cash equal to 101% of the principal amount of the Exchange Notes, plus accrued and unpaid interest, including additional interest, if any. In the event that we experience a change in control and the holders of the Exchange Notes require us to repurchase Exchange Notes, we may not have sufficient financial resources to satisfy all of our obligations under the Exchange Notes. In addition, restrictions under the senior unsecured credit facilities may not allow us to repurchase the Exchange Notes or otherwise refinance such indebtedness to satisfy our obligations.

Our principal equityholder’s interests may conflict with yours.

Cleco Partners has current voting ownership of all of the outstanding equity interest of Cleco and the ability to control the operations of Cleco. Cleco Partners and its affiliates may invest in entities that directly or indirectly compete with us, or companies in which they currently invest may begin competing with us. The interests of Cleco Partners could conflict with your interests. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of Cleco Partners might conflict with your interests as a holder of the Exchange Notes. Cleco Partners may also have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its respective judgment, could enhance its equity investment, even though such transactions might involve risks to you as a holder of the Exchange Notes.

The credit ratings assigned to the Exchange Notes may not reflect all risks of an investment in the Exchange Notes.

The credit ratings assigned to the Exchange Notes reflect the rating agencies’ assessments of our ability to make payments on the Exchange Notes when due. Consequently, real or anticipated changes in these credit ratings will generally affect the market value of the Exchange Notes. These credit ratings, however, may not reflect the potential impact of risks related to structure, market or other factors related to the value of the Exchange Notes.

An active trading market for the Exchange Notes may not develop.

There is currently no public market for the Exchange Notes, and we do not currently plan to list the Exchange Notes on any securities exchange or automated dealer quotation system. In addition, the liquidity of any trading market in the Exchange Notes, and the market price quoted for the Exchange Notes, may be adversely affected by changes in the overall market for such securities and by changes in our financial performance or prospects. A liquid trading market in the Exchange Notes may not develop.

Transfer of the Exchange Notes will be restricted.

We have not registered the offering or sale of the Exchange Notes under the Securities Act or any state or foreign securities laws. Until we register the Exchange Notes or complete the exchange of registered notes for the Exchange Notes in our exchange offer, you may not offer or sell the Exchange Notes in the United States or to a United States person, as defined in Regulation S under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. We are obligated to use our commercially reasonable efforts to commence an offer to exchange the Exchange Notes for equivalent notes registered under the United States securities laws or, in certain circumstances, register the reoffer and resale of the Exchange Notes under the United States securities laws, but we cannot assure you that we will be successful in having any such registration statement declared effective by the SEC. You should read the discussions under the headings “The Exchange Offer — Resale of Exchange Notes” and “Registration Rights Agreement” for further information about these transfer restrictions. It is your obligation to ensure that your offers and sales of Exchange Notes comply with applicable securities laws. See “The Exchange Offer — Resale of Exchange Notes.”

The Exchange Notes will mature after a substantial portion of our other indebtedness.

A substantial portion of our existing indebtedness will mature prior to the maturity date of the Exchange Notes. Additionally, upon approval of the Cleco Cajun Transaction, Cleco made a commitment to the LPSC to repay by December 31, 2024 $400.0 million of Cleco Holdings’ debt, of which $63.3 million is required to be repaid

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in 2020. Therefore, we will be required to repay a substantial portion of our other creditors before we are required to repay the principal of the Exchange Notes. As a result, we may not have sufficient cash to repay all amounts owing on the Exchange Notes at maturity. There can be no assurance that we will have the ability to borrow or otherwise raise the amounts necessary to repay or refinance such amounts.

RISK RELATING TO OUR BUSINESS AND OPERATIONS

Structural Risks

Holding Company

Cleco Holdings is a holding company and its ability to meet its debt obligations is dependent on the cash generated by its subsidiaries.

Cleco Holdings is a holding company and conducts its operations primarily through its subsidiaries. Accordingly, Cleco Holdings’ ability to meet its debt obligations is largely dependent upon the cash generated by these subsidiaries. Cleco Holdings’ subsidiaries are separate and distinct entities and have no obligations to pay any amounts due on Cleco Holdings’ debt or to make any funds available for such payment. In addition, Cleco Holdings’ subsidiaries’ ability to make dividend payments or other distributions to Cleco Holdings may be restricted by their obligations to holders of their outstanding securities and to other general business creditors. Substantially all of Cleco’s consolidated assets are held by either Cleco Power or Cleco Cajun. Cleco Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if Cleco Holdings were a creditor of any subsidiary, its rights as a creditor would be effectively subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary ranking senior to that held by Cleco Holdings. Cleco Power is subject to regulation by the LPSC. The 2016 Merger Commitments also provide for limitations on the amount of distributions that may be paid from Cleco Power to Cleco Holdings, depending on Cleco Power’s common equity ratio and its corporate credit/issuer ratings. As a result, Cleco Power may be prohibited from making distributions to Cleco Holdings.

Operational Risks

COVID-19

Cleco faces risks related to COVID-19 and other health epidemics and outbreaks, including economic, regulatory, legal, workforce, and cyber-security risks, which could have a material adverse impact on the results of operations, financial condition, cash flows or liquidity of Cleco.

The recent outbreak of COVID-19 is a rapidly evolving situation that is adversely affecting current global economic activities and conditions. An extended slowdown of economic growth, decreased demand for commodities and/or material changes in governmental or regulatory policy in the United States could result in lower growth and reduced demand for and usage of electricity in Cleco’s service territory as businesses and facilities continue to close or remain closed. The ability of Cleco’s customers, contractors, and suppliers to meet their obligations to Cleco, including payment obligations, could also be negatively affected under the current economic conditions.

The LPSC has issued a moratorium on disconnects of customers for non-payment. Accordingly, Cleco has taken steps to assure customers that disconnections for non-payment and late fees are temporarily suspended, which in turn could negatively impact Cleco’s revenue. Additionally, the LPSC, in response to a federal mandate or otherwise, could impose restrictions on the rates Cleco charges to provide its services, including the inability to implement approved rates, or delay actions with respect to Cleco’s rate cases and filings. In addition, the COVID-19 outbreak may affect Cleco’s ability to timely satisfy regulatory requirements such as recordkeeping and/or timely reporting requirements. As the EPA and many state environmental agencies have issued enforcement discretion policies for such issues, it is unclear whether the effect of any possible noncompliance due to COVID-19 will be material.

In the event a substantial portion of Cleco’s workforce were to be impacted by COVID-19 for an extended period of time, Cleco may face challenges with respect to its services or operations and it may not be able to execute its capital plan as anticipated. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines,

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shelter-in-place orders, and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, Cleco, its suppliers, and other business counterparties to experience operational delays. Cleco has modified certain business and workforce practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access Cleco’s facilities or customer sites could adversely affect its operations. Also, Cleco has a limited number of highly skilled employees for some of its operations. If a large proportion of Cleco’s employees in those critical positions were to contract COVID-19 at the same time, Cleco would rely upon its business continuity plans in an effort to continue operations at its facilities, but there is no certainty that such measures will be sufficient to mitigate the adverse impact to Cleco’s operations that could result from shortages of highly skilled employees.

As many of Cleco’s employees and third-party service providers work remotely in accordance with government mandates, Cleco faces heightened cyber-security risks related to unauthorized system access, aggressive social engineering tactics, and adversaries attacking the information technology systems, network infrastructure, technology and facilities used to conduct its businesses. Cleco will continue to monitor developments affecting its employees, customers, and operations.

While the impact on Cleco’s business from the recent outbreak of COVID-19 is unknown at this time and difficult to predict, various aspects of its business could be adversely affected by COVID-19. While there are many unknowns as to the duration and severity of the COVID-19 outbreak, as of the date of this prospectus, it has caused significant volatility in global markets and has had an adverse impact on the operations of some of Cleco’s customers and suppliers, which could affect Cleco’s operations and its ability to access capital. The continued spread of COVID-19 and efforts to contain COVID-19, such as the imposition of additional quarantines or closures or reduced operations of businesses and other institutions, could result in an economic slowdown, which could adversely affect customer demand and consumption, cause delayed payments or uncollectible accounts, disrupt supply chains and markets, cause potential delays in the timing of completion of capital projects, or cause other unpredictable events. These impacts could ultimately result in a downgrade of Cleco’s credit ratings. Any of the foregoing events or other unforeseen consequences of COVID-19 could have a material adverse effect on the results of operations, financial condition, cash flows, or liquidity of Cleco.

Cleco Cajun

The success of the Cleco Cajun Transaction depends, in part, on Cleco’s ability to manage the acquired business, realize anticipated benefits, and continue an effective integration process.

On February 4, 2019, Cleco acquired all of the membership interests of South Central Generating upon the closing of the Cleco Cajun Transaction. The success of the Cleco Cajun Transaction will depend, in part, on Cleco’s ability to manage and operate an unregulated business through service to nine electric Louisiana cooperative customers and other wholesale customers. Additionally, the integration process may result in the following challenges, among others:

• unanticipated challenges integrating financial and accounting, information technology, communications and other systems;

• potential inconsistencies in procedures, practices, policies, controls, and standards;

• possible differences in compensation arrangements, management perspectives, and corporate culture; and

• meeting LPSC commitments relating to the transaction.

Even with the successful integration of the businesses, Cleco may not achieve the expected results or economic benefits. Any of the factors addressed above could decrease or delay the projected neutral or accretive effect of the Cleco Cajun Transaction. Failure to fully realize the anticipated benefits could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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Transmission Constraints

Transmission constraints could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Energy prices in the MISO market are based on LMP, which includes a component directly related to congestion on the transmission system. Pricing zones with greater transmission congestion may have a higher LMP. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power and Cleco Cajun’s pricing zones. Cleco Power and Cleco Cajun are awarded and/or purchase FTR’s in auctions facilitated by MISO. However, insufficient FTR allocations or increased FTR costs due to negative congestion flows may result in an unexpected increase in energy costs to Cleco’s customers. For Cleco Power, if a disallowance of additional fuel costs associated with congestion is ordered by the LPSC resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Future Electricity Sales

Cleco Power’s future electricity sales and corresponding base revenue and cash flows and Cleco Cajun’s future wholesale revenue and cash flows could be negatively affected by adverse macroeconomic conditions.

Adverse macroeconomic conditions resulting in low economic growth can negatively impact the businesses of Cleco Power’s residential, commercial, wholesale, and industrial customers, and Cleco Cajun’s wholesale customers resulting in decreased power consumption, which causes a corresponding decrease in base revenue for Cleco Power and revenue for Cleco Cajun. Reduced production or the shutdown of any of these customers’ facilities could substantially reduce Cleco Power’s base revenue and Cleco Cajun’s revenue.

Energy conservation, energy efficiency efforts, and other factors that reduce energy demand could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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 customers switching to alternative sources of energy, such as solar and wind, on-site power generation, and retail customers purchasing less electricity due to increased conservation efforts or expanded energy efficiency measures. Declining usage could result in an under-recovery of fixed costs at Cleco Power’s rate regulated business. An increase in energy conservation, energy efficiency efforts, and other efforts that reduce energy demand could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Technology and Terrorism Threats

The operational and information technology systems on which Cleco relies to conduct its business and serve customers could fail to function properly due to technological problems, cyber attacks, physical attacks on Cleco’s assets, acts of terrorism, severe weather, solar events, electromagnetic events, natural disasters, the age and condition of information technology assets, human error, or other reasons that could disrupt Cleco’s operations and cause Cleco to incur unanticipated losses and expense.

The operation of Cleco’s extensive electrical systems relies on evolving operational and information technology systems and network infrastructures that are becoming extremely complex as new technologies and systems are implemented to more safely and reliably deliver electric services. Cleco’s business is highly dependent on its ability to process and monitor, on a real-time daily basis, a large number of tasks and transactions, many of which are highly complex. The failure of Cleco’s operational and information technology systems and networks due to a physical or cyber attack, or other event would significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; result in damage to Cleco’s assets or operations, or those of third parties; and subject Cleco to claims by customers or third parties, any of which could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco’s systems, including its financial information, operational, advanced metering, and billing systems, require constant maintenance, monitoring, security patches, modification or configuration of systems, and update and upgrade of systems, which can be costly and increase the risk of errors and malfunction. Any disruptions or deficiencies in existing systems, or disruptions, delays, or deficiencies in the modification, transition to, or

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implementation of new systems, could result in increased costs, the inability to track or collect revenues and the diversion of management’s and employees’ attention and resources, and could adversely affect the effectiveness of Cleco’s control environment, and/or its ability to accurately or timely file required regulatory reports.

Despite implementation of security and mitigation measures, all of Cleco’s technology systems and those of Cleco’s vendors are vulnerable to inoperability, impaired operations, or failures due to cyber or physical attacks on the facilities and equipment needed to operate the technology systems, viruses, human errors, acts of war or terrorism, and other events. If Cleco’s or its vendor’s information technology systems or network infrastructure were to fail, Cleco might be unable to fulfill critical business functions and serve its customers, which could have a material adverse effect on the financial conditions, results of operations, or cash flows of Cleco.

In addition, in the ordinary course of its business, Cleco collects and retains sensitive information including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data could subject Cleco to both penalties for violation of applicable privacy laws and claims from third parties, or harm Cleco’s reputation. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

Cleco’s Generation, Transmission, and Distribution Facilities

Cleco’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. Aging equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to operate at peak efficiency, or to comply with environmental permits. Newer equipment can also be subject to unexpected failures. Accordingly, Cleco may incur more frequent unplanned outages, higher than anticipated operating and maintenance expenditures, higher replacement costs of purchased power, increased fuel costs, MISO related costs, and the loss of potential revenue related to competitive opportunities. The costs of such repairs, maintenance, and purchased power may not be fully recoverable in rates and could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco’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, decreased regional supply, production shortages, weather-related disturbances, railroad constraints, waterway levels, labor strikes, or lack of transportation capacity. If suppliers are unable to deliver the contracted volume of fuel and associated inventories are depleted, Cleco Power may be unable to operate generating units which may cause Cleco Power to operate at higher overall energy costs, which would increase the cost to customers. Cleco Power’s fuel and MISO-procured/settled energy expenses, which are recovered from its customers through the FAC, are 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. Placement of drilling rigs and pipelines for developing oil and gas reserves can preclude access to lignite in the same areas. 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. Access to lignite reserves or the liability for impacts on reclaimed lands may not be recoverable in rates and could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

The construction of, and capital improvements to, power generation and transmission and distribution facilities involve substantial risks. Should construction or capital improvement efforts be significantly more expensive than planned, the financial condition, results of operations, or liquidity of Cleco could be materially affected.

Cleco’s ability to complete construction of, or capital improvements to, power generation and transmission and distribution facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include 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 set forth under their contracts, changes in the scope and timing

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of projects, inaccurate cost estimates, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel or material costs, changes in the economy, changes in laws or regulations, including environmental compliance requirements, and other events beyond the control of Cleco may materially affect the schedule and cost of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Cleco could incur additional costs including termination payments, face increased risk of potential write-off of the investment in the project, or Cleco Power may not be able to recover such costs in rates. Furthermore, failure to maintain various levels of generating unit availability or transmission and distribution reliability may result in various disallowances of Cleco Power’s investments.

Weather Sensitivity

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

Weather conditions directly influence the demand for electricity, particularly with respect to residential customers. In Cleco’s service territory, demand for power typically peaks during the hot summer months. As a result, Cleco’s financial results may fluctuate on a seasonal basis. In addition, Cleco 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 effect on the results of operations, financial condition, or cash flows of Cleco.

Severe weather, including hurricanes and winter storms, can affect transportation of fuel to plant sites and can be destructive, causing outages and property damage that can potentially result in additional expenses, lower revenue, and additional capital restoration costs. 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 changes could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

If climate changes occur that result in warmer temperatures in Cleco’s service territories, it could result in one or more physical risks, such as an increase in sea level, wind and storm surge damages, 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, or could affect Cleco’s operations. Cleco’s 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 generating facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on Cleco’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change would adversely impact the economic health of a region or result 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 adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Litigation

Cleco is subject to litigation related to the 2016 Merger.

In connection with the 2016 Merger, four actions were filed in the 9th Judicial District Court for Rapides Parish, Louisiana and three actions were filed in the Civil District Court for Orleans Parish, Louisiana. One of the actions filed in Rapides Parish has been dismissed. The remaining three actions in Rapides Parish have been consolidated. The three actions in Orleans Parish have been transferred to Rapides Parish and consolidated with the other litigation in Rapides Parish. The actions were filed against Cleco Corporation and, among others, Cleco Partners, Merger Sub, and members of the Board of Directors of Cleco Corporation. The petitions generally alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process, agreeing to the 2016 Merger at a price that allegedly undervalues Cleco, and failing to disclose material information about the 2016 Merger. The

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petitions also alleged that Cleco Partners, Cleco, and Merger Sub and, in some cases, certain of the investors in Cleco Partners either aided and abetted or entered into a civil conspiracy to advance those supposed breaches of duty. The petitions seek various remedies, including monetary damages, which includes attorneys’ fees and expenses. In September 2016, the District Court granted the exceptions filed by Cleco and dismissed all claims asserted by the former shareholders. The plaintiffs appealed the District Court’s ruling, and in December 2017, the Louisiana Third Circuit Court of Appeal issued an order reversing and remanding the case back to the District Court for further proceedings. In January 2018, Cleco filed a writ with the Louisiana Supreme Court seeking review of the Third Circuit Court of Appeal’s decision. In March 2018, the Louisiana Supreme Court denied the writ. Cleco filed writs of exception of res judicata and no cause of action in the District Court seeking dismissal of the case. On January 14, 2019, the District Court denied the writs. A hearing on plaintiffs’ request for certification of a class was scheduled for August 26, 2019; however, prior to the hearing, the parties reached an agreement to certify a limited class.

It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to seek monetary relief from Cleco. Cleco is not able to predict the outcome of these actions, or others, nor can Cleco predict the amount of time and expense that will be required to resolve the actions. In addition, the cost to Cleco of defending the actions, even if resolved in Cleco’s favor, could be substantial. Such actions could also divert the attention of Cleco’s management and resources from day-to-day operations.

The outcome of legal proceedings cannot be predicted. An adverse finding could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco is party to various litigation matters arising out of the ordinary operations of their business. 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 Cleco 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 results of operations, financial condition, or cash flows of Cleco.

Workforce

Failure to attract and retain an appropriately qualified workforce could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Certain events, such as an aging workforce without appropriate replacements, lack of equivalent or enhanced skill sets to fulfill future needs, or unavailability of contract resources, may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate Cleco’s businesses. If Cleco is unable to successfully attract and retain an appropriately qualified workforce, the results of operations, financial condition, or cash flows of Cleco could be materially adversely affected.

Alternative Generation Technology

Changes in technology may have a material adverse effect on the value of Cleco Power and Cleco Cajun’s generating 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 wind turbines, photovoltaic cells, and other solar generated power. Many companies and organizations conduct research and development activities to seek improvements in alternative technologies. 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 generating assets. As a result, the value of Cleco Power and Cleco Cajun’s generating facilities could be reduced.

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Insurance

Cleco’s insurance coverage may not be sufficient.

Cleco currently has property, casualty, cybersecurity and liability insurance policies in place to protect its employees, directors, and assets in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles. Insurance coverage may not be available in the future at current costs, on commercially reasonable terms, or at all, 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 a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Like other utilities that serve coastal regions, Cleco Power 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 Power 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 Power may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Regulatory Risks

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 Cleco’s business or result in significant additional costs.

Cleco’s business is subject to extensive federal, state, and local energy, environmental, and other laws and regulations. The LPSC regulates Cleco Power’s retail operations and FERC regulates Cleco’s wholesale operations. The construction, planning, and siting of Cleco Power’s power plants and transmission lines are also 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 United States Bureau of Land Management, the United States Fish and Wildlife Services, the United States Department of Energy, the United States Coast Guard, the United States Army Corps of Engineers, the United States Department of Homeland Security, the Occupational Safety and Health Administration, the United States Department of Transportation, the United States Department of Agriculture, the United States Bureau of Economic Analysis, 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, the Louisiana Department of Agriculture, the Louisiana Bureau of Economic Analysis, regional water quality boards, and various local regulatory districts.

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 material adverse effect on Cleco’s business or result in significant additional costs.

As a result of the 2016 Merger, Cleco Holdings and Cleco Power made the 2016 Merger Commitments to the LPSC including, but not limited to, the extension of Cleco Power’s current FRP for an additional two years, maintaining employee headcount, salaries, and benefits for ten years, and a limitation from incurring additional long-term debt, excluding non-recourse debt, unless certain financial ratios are achieved. Additionally, upon approval of the Cleco Cajun Transaction, Cleco made commitments to the LPSC including, but not limited to, holding Cleco Power retail customers harmless for any adverse impacts, increased costs of debt or equity, and credit rating downgrades attributable to the Cleco Cajun Transaction; the repayment of $400.0 million of Cleco Holdings’ debt by 2024; and a $4.0 million annual reduction to Cleco Power’s retail customer rates.

In April 2016, the LPSC issued Docket No. R-34026 to investigate the double leveraging issues for all LPSC-jurisdictional utilities whereby double leveraging is utilized to fund a utility’s capital structure, and to consider whether any costs associated with such double leveraging should be included in the rates paid by the utility’s retail ratepayers. Cleco Power has intervened in this proceeding, along with other Louisiana utilities. In April 2016, the LPSC also issued Docket No. R-34029 to investigate the tax structure issues for all LPSC-jurisdictional utilities to consider whether only the state and federal taxes included in a utility’s retail rate

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will be those that do not exceed the utility’s share of the actual taxes paid to those federal and state taxing authorities. Cleco Power filed a motion to intervene in this proceeding along with other Louisiana utilities. If the LPSC were to disallow such costs incurred by the utility to be included in retail rates, such disallowance could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

LPSC Audits

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

Generally, Cleco Power’s cost of fuel used for electric generation and cost of purchased power are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to its customers substantially all such charges. Recovery of FAC costs is subject to periodic fuel audits by the LPSC. The LPSC FAC General Order issued in November 1997, in Docket No. U-21497 provides that an audit will be performed at least every other year.

Cleco Power has FAC filings for January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. If a disallowance of fuel costs is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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

In 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides Cleco Power an EAC to recover from customers certain costs of environmental compliance. 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. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. These expenses are eligible for recovery through Cleco Power’s EAC and subject to periodic review by the LPSC.

Cleco Power has EAC filings for January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. If a disallowance of environmental costs is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

FERC Audit

FERC conducts audits that could result in Cleco Power making refunds of previously recorded revenue.

Generally, Cleco Power records wholesale transmission revenue through approved formula rates, Attachment O of the MISO tariff, and certain grandfathered agreements. The calculation of the rate formulas, as well as FERC accounting and reporting requirements, are subject to periodic audits by FERC. In March 2018, the Division of Audits and Accounting within the Office of Enforcement of FERC initiated an audit of Cleco Power for the period of January 1, 2014, through June 30, 2019. On September 27, 2019, Cleco Power received the final audit report, which indicated 12 findings of noncompliance with a combination of FERC accounting and reporting requirements and computation of revenue requirements along with 59 recommendations associated with the audit period. Cleco Power submitted a plan for implementing the audit recommendations on October 28, 2019. Cleco Power also submitted the refund analysis on November 7, 2019, which resulted in an estimated refund of $3.5 million related to the FERC audit findings, pending final assessment by the FERC Division of Audits and Accounting. Management is unable to predict the timing of future audits and whether or not the outcome of such future audits will have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

MISO

MISO market operations could have a material adverse effect on the results of operations, generation revenues, energy supply costs, financial condition, or cash flows of Cleco.

Cleco is a member of the MISO market region referred to as “MISO South,” which encompasses parts of Arkansas, Louisiana, Mississippi, and Texas. Dispatch of generation resources and generation volumes to the

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market is determined by MISO. Costs in the MISO South region are heavily influenced by commodity fuel prices, transmission congestion, dispatch of the generating assets owned not only by Cleco, but by all market participants in the MISO South region, and the overall demand and generation availability in the region.

MISO evaluates forced outage rates to assess generating unit capacity for planning reserve margins. If Cleco is subject to a significant amount of forced outages, Cleco may not possess sufficient planning reserves to serve its needs and could be forced to purchase capacity from the MISO resource adequacy auction. For Cleco Power, the costs of such capacity may not be recoverable in its rates and could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco. Using MISO’s unforced capacity method for determining generating unit capacity, Cleco Power’s fleet provided for 546 MW of capacity in excess of its peak, coincident to MISO’s peak, in 2019.

TCJA

Changes in taxation due to uncertain effects of the TCJA could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

The budget reconciliation act commonly referred to as the TCJA was signed into law on December 22, 2017. Proposed rulemakings issued by the IRS subsequent to the TCJA could have a material adverse effect on the results of operations, financial conditions, or cash flows of Cleco. Cleco continues to assess the regulatory treatment of the TCJA, which could also have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

On July 10, 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT, resulting from the enactment of the TCJA, in Cleco Power’s application for its next FRP, which was filed on June 28, 2019. The anticipated new rates will be effective July 1, 2020. At March 31, 2020, Cleco Power had a regulatory liability of $375.0 million for the portion of the net reduction to ADIT subject to regulatory treatment.

Reliability and CIP Standards Compliance

Cleco is subject to mandatory reliability and CIP 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 CIP 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 Cleco Cajun separately, which may result in increased capital expenditures and operating expenses. Failure to comply with these standards can result in the imposition of material fines and civil penalties.

The SERC Reliability Corporation Regional Entity conducts a NERC Reliability Standards audit and a NERC CIP audit every three years on Cleco Power and Cleco Cajun separately. Cleco Cajun’s NERC CIP audit occurred in June 2019. The preliminary findings have been received by Cleco Cajun.

Management is unable to predict the final financial outcome of the current Cleco Power NERC Reliability Standards audit, the current Cleco Cajun NERC CIP audit, or any future audits. Management is also unable to predict whether any findings will have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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 Cleco.

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. As a

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result, some of Cleco’s EGUs could be rendered uneconomical to maintain or operate and could prompt early retirement of certain generation units. 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 fuel for new and existing EGUs. Cleco will evaluate potential solutions to comply with such regulations and monitor rulemaking and any legal matters impacting the proposed regulations. Cleco may incur significant capital expenditures or additional operating costs to comply with such revisions, reinterpretations, and new requirements. If Cleco were to fail 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 timing or the outcome of pending or future legislative and rulemaking proposals.

Cleco Power may request from its customers recovery 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 results of operations, financial condition, or cash flows of Cleco.

Cleco Power’s Rates

The LPSC and FERC regulate the retail rates and wholesale transmission tariffs, respectively, that Cleco Power can charge its customers.

Cleco Power’s ongoing financial viability depends on its ability to recover its costs in a timely manner from its LPSC-jurisdictional customers through LPSC-approved rates and its ability to recover its FERC-authorized revenue requirements from its FERC-jurisdictional wholesale transmission customers. 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 results of operations, financial condition, or cash flows of Cleco could be materially adversely affected.

Cleco Power’s revenues and earnings are substantially affected by regulatory proceedings known as rate cases or, in some cases, a request for extension of an FRP. During those cases, the LPSC 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 customers through its rates. In some instances, the outcome of a rate case or request for extension of an FRP may impact wholesale decisions of Cleco Power. 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. Rate cases generally have timelines of approximately one year, and decisions are typically subject to appeal, potentially leading to additional uncertainty. The transmission tariffs of Cleco Power are regulated by FERC with its own regulatory proceedings. Both the LPSC and FERC regulatory proceedings can involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, all of whom have differing concerns but who have the common objective of limiting rate increases or reducing rates.

Transmission rates that MISO transmission owners may collect are regulated by FERC. On November 21, 2019, FERC voted to adopt new methodology for evaluating base ROE for public utilities under the Federal Power Act, as amended. Cleco Power is unable to determine when a binding FERC order will be issued. Any reduction to the ROE component of the transmission rates could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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 ROE. 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 results of operations, financial condition, or cash flows of Cleco.

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Wholesale Electric Service

Cleco’s business practices are regulated by FERC, and the wholesale rates of both Cleco Power and Cleco Cajun are subject to FERC’s triennial market power analysis. Cleco Power and/or Cleco Cajun could lose the right to sell wholesale generation at market-based rates.

FERC conducts a review of Cleco’s generation market power every three years in addition to each time generation capacity changes. Cleco’s next triennial market power analysis is expected to be filed during the fourth quarter of 2020. In the future, if FERC determines Cleco Power and/or Cleco Cajun possesses generation market power in excess of certain thresholds, Cleco Power and/or Cleco Cajun could lose the right to sell wholesale generation at market-based rates, which could result in a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Financial Risks

Controls and Procedures

Cleco has identified material weaknesses in internal control over financial reporting. If these material weaknesses are not remediated, they could result in material misstatements in Cleco’s financial statements.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. As disclosed in “Managements’ Reports on Internal Control Over Financial Reporting,” Cleco identified a material weakness related to the design and operation of certain information technology general controls for information systems that are relevant to the preparation of Cleco’s financial statements. Cleco also identified a material weakness in the design and operating effectiveness of controls over the completeness and accuracy of billed and unbilled revenue from contracts with customers. As a result of these material weaknesses, management concluded that Cleco did not maintain effective disclosure controls and procedures as of March 31, 2020.

Cleco is taking steps to remediate the underlying cause of these material weaknesses, but Cleco cannot assure that the remediation of the material weaknesses will be successful or that additional material weaknesses in internal controls will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties encountered in implementation, could result in additional material weaknesses, or could result in material misstatements in Cleco’s financial statements. These misstatements could result in restatements of Cleco’s financial statements, failure to meet reporting obligations, or cause stakeholders to lose confidence in reported financial information of Cleco.

Commodity Prices

Cleco Power and Cleco Cajun’s financial performance could be exposed to fluctuations in commodity prices and other factors, which could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco Power

Cleco Power may enter into fuel cost hedging transactions to mitigate the volatility in fuel costs passed through to its retail customers. When transactions expire or are offset through liquidation, actual gains or losses are deferred and included in the FAC in the month the physical contract settles. 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 Cajun

Cleco Cajun is exposed to uncertain market prices of electricity, natural gas, coal, and other commodities that can impact costs of fuel supply for generation, generation revenue, cost to serve its contracted wholesale electricity customers, and revenue from these customers. Energy costs and revenues are also subject to volumetric risk due to fluctuations related to unexpected plant outages and uncertain customer load.

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Commodity Hedging and Commercial Transactions

Cleco may enter into fuel supply contracts and/or commercial transactions, including sales to wholesale customers and physical and financial hedges. If these transactions are not managed effectively, they may have a material adverse effect on the liquidity, results of operations, and financial condition of Cleco.

Cleco may enter into physical or financial transactions during its normal course of business. Cleco may also enter into transactions to hedge its exposure to commodity price risk of all or some of its customer supply agreements, natural gas, solid fuel requirements (coal), power, and other commodities, inclusive of transmission and transportation. Transactions are executed within board approved risk management guidelines, including transactions that qualify as derivatives contracts in accordance with accounting guidance.

The accounting treatment for Cleco Cajun’s hedging activities may increase the volatility in Cleco’s financial results.

Cleco Cajun engages in transactions to economically hedge forward commodity market price risk exposure utilizing both physical and financial commodity purchases and sales commitments. Some of these contracts are accounted for as derivatives, which require Cleco to record the fair value of the commitment on the balance sheet with changes in the fair value of all derivatives reflected within current period earnings. As a result, Cleco is unable to accurately predict the effect that these transactions may have on its results of operations, financial condition, or cash flows.

Counterparty Risk and Guarantees

Cleco is exposed to the risk that counterparties may not meet their performance obligations, which could have a material adverse effect on the operating and financial performance of Cleco.

Counterparties may fail to perform on their physical or financial obligations. Currently, some master agreements with counterparties contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Cleco, or specifically to Cleco Power or Cleco Cajun. If the counterparties to these arrangements fail to perform, Cleco may enforce and recover the proceeds from the credit support provided; however, in the event of a default, credit support may not always be adequate to cover the related obligations. In such event, Cleco may incur losses in excess of amounts already paid, if any, to the counterparties or due to an adverse replacement cost of the transaction.

The credit commitments of Cleco’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources. In no case would Cleco Power bear any commodity or credit risk of Cleco Cajun.

Cleco may be required to provide credit support to its counterparties, which could have a material adverse effect on Cleco’s liquidity ratios and liquidity.

Cleco may guarantee the performance of all or some of its commercial transaction obligations and may also be required to provide counterparty credit support to secure all or part of those obligations. Downgrades in Cleco’s credit quality or changes in the market prices of transaction-related energy commodities could increase the collateral required to be on deposit with the counterparty or clearing house. The required credit support or increase in credit support could have a material adverse effect on Cleco’s liquidity ratios and liquidity.

Global Economic Environment and Uncertainty; Access to Capital

Adverse capital market performance could result in reductions in the fair value of benefit plan assets and increase Cleco’s liabilities related to such plans. Sustained declines in the fair value of the plan’s assets or sustained increases in plan liabilities could result in significant increases in funding requirements, which could adversely affect Cleco’s liquidity and results of operations.

Performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under Cleco’s defined benefit pension plan. Sustained adverse market performance could result in lower rates of return for these assets than projected by Cleco and could increase Cleco’s funding requirements related to the pension plan. Additionally, changes in interest rates affect the present value of Cleco’s liabilities under the pension plan. Adverse changes in assumptions or adverse actual events could cause additional minimum contributions.

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Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

Amounts drawn under Cleco’s current debt agreements may bear interest at rates based on LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on Cleco’s financial condition, results of operations, and cash flows.

Inflation

Annual inflation rates, as measured by the United States Consumer Price Index, have averaged 2% during the three years ended December 31, 2019. Under established regulatory practice, historical costs have traditionally formed the basis for recovery from customers. As a result, Cleco Power’s future cash flows designed to provide recovery of historical plant costs may not be adequate to replace property, plant, and equipment in future years.

Disruptions in the capital and credit markets may adversely affect Cleco’s cost of capital and ability to meet liquidity needs or access capital to operate and grow the business.

Cleco’s business is capital intensive and dependent upon Cleco’s abilities to access capital at reasonable rates and other terms. Cleco’s liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster or when there are spikes in the price for natural gas and other commodities. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel, purchased power, or storm restoration costs; higher than expected required pension contributions; an acceleration of payments or decreased credit lines; less cash flow from operations than expected; or other unexpected events, could cause the financing needs of Cleco to increase materially.

Events beyond Cleco’s control, such as political uncertainty in the United States (including the ongoing debates related to the United States federal government budget and debt ceiling), 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. Additionally, upon approval of the Cleco Cajun Transaction, Cleco made commitments to the LPSC including, but not limited to, holding Cleco Power retail customers harmless for any adverse impacts, increased costs of debt or equity, and credit rating downgrades attributable to the Cleco Cajun Transaction; the repayment of $400.0 million of Cleco Holdings’ debt by 2024; and a $4.0 million annual reduction to Cleco Power’s retail customer rates. Cleco may be 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 Cleco is unable to access the credit and capital markets on terms that are reasonable, it 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 effect on Cleco’s ability to fund capital expenditures or to service debt, or on Cleco’s flexibility to react to changing economic and business conditions.

Cleco Credit Ratings

A downgrade in Cleco Holdings’ or Cleco Power’s credit ratings could result in an increase in their respective borrowing costs, a reduced pool of potential investors and funding sources, and a restriction on Cleco Power making distributions to Cleco Holdings.

Neither Cleco Holdings 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. If S&P, Moody’s, or Fitch were to downgrade Cleco Holdings’ or Cleco Power’s long-term ratings, particularly below investment grade, the value of their debt securities would be adversely affected. Downgrades of either Cleco Holdings’ or Cleco Power’s credit ratings could result in additional fees and higher interest rates for borrowings under their respective credit facilities. In addition, Cleco Holdings or Cleco Power, as the case may be, would likely be required to pay higher interest rates in future debt financings, may be subject to more onerous debt covenants, and their pool of potential investors and funding sources could decrease. In addition, the

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2016 Merger Commitments provide for limitations on the amount of distributions that may be paid from Cleco Power to Cleco Holdings, depending on Cleco Power’s common equity ratio and its corporate credit/issuer ratings. As a result, Cleco Power may be prohibited from making distributions to Cleco Holdings in the event of a ratings downgrade below investment grade.

Taxes

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco makes judgments regarding the utilization of existing income tax credits and the potential tax effects of various financial transactions and results of operations to estimate their obligations to taxing authorities. Tax obligations include income, franchise, property, sales and use, and employment-related taxes. These judgments may 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 Cleco could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the Exchange Notes pursuant to the exchange offer. The exchange offer is intended to satisfy our obligations under the registration rights agreement, which we entered into in connection with the issuance and sale of the Outstanding Notes, for which we received $297.9 million in net proceeds that were used to repay the then-remaining amounts due under the Bridge Facility and pay a portion of the Acquisition Term Loan Facility. See “Registration Rights Agreement.”

In consideration for issuing the Exchange Notes as contemplated in this prospectus, we will receive in exchange a like principal amount of Outstanding Notes. The form and terms of the Exchange Notes are identical in all material respects to the form and terms of the Outstanding Notes, except the offer and exchange of the Exchange Notes have been registered under the Securities Act and the Exchange Notes will not have restrictions on transfer, registration rights or provisions for additional interest. The Outstanding Notes surrendered in exchange for the Exchange Notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the Exchange Notes will not result in any change in our capitalization.

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

RECENT EVENTS

COVID-19

On March 11, 2020, the World Health Organization declared the current COVID-19 outbreak to be a global pandemic, and on March 13, 2020, the United States declared a national emergency. In response to these declarations and the rapid spread of COVID-19, federal, state and local governments have imposed varying degrees of restrictions on business and social activities to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory. Cleco has modified some of its business operations, as these restrictions have significantly impacted many sectors of the economy, including record levels of unemployment, with businesses, nonprofit organizations, and governmental entities modifying, curtailing, or ceasing normal operations. Cleco has also modified certain business practices to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. For example, since March 13, 2020, Cleco temporarily closed all customer service offices, temporarily suspended disconnects and late fees, restricted access to its administrative offices, implemented remote work arrangements, prohibited all non-critical travel for Cleco business, prohibited in-person gatherings of more than 10 people at Cleco work locations, and required all meetings to be held virtually or via telephone.

Cleco provides a critical service to its customers which means that it is paramount that it keeps its employees who operate its business safe and informed and has taken and continues to take and update precautions for that purpose. In addition, Cleco assessed and updated its existing business continuity plans for its business units in the context of the COVID-19 pandemic. The LPSC has issued a moratorium on disconnects of customers for non-payment, and accordingly Cleco has taken steps to assure its customers that disconnections for non-payment as well as late fees are temporarily suspended. Cleco is also working with its suppliers to understand the potential impacts to its supply chain. This is a rapidly evolving situation and could lead to extended disruption of economic activity in Cleco’s service territory. Cleco will continue to monitor developments affecting its workforce, customers, and suppliers and take additional precautions as Cleco believes are warranted.

The first priority in Cleco’s response to this crisis has been the health and safety of its employees and those of its customers and other business counterparties. Cleco has implemented preventative measures and developed corporate response plans to minimize unnecessary risk of exposure and prevent infection, while supporting its customers’ operations to the best of its ability in the circumstances. Cleco has an Emergency (Crisis) Response Team for health, safety, and environmental matters and personnel issues, and has established a Pandemic Plan Team to address various impacts of COVID-19 as they have been developing. This team provides leadership and guidance for planning, risk management, and any policy changes. The team ensures that areas of Cleco plan, manage, and safely execute the pandemic plan set forth by management. Cleco employees are required to report daily to their manager or supervisor any changes to the employee’s health, the employee’s family’s health, and travel plans. This is reported to the Pandemic Plan Team at a minimum of three times per week. The results are then communicated on a weekly update call to all employees. Proper measures are taken for any employee at risk of having COVID-19 and measures are taken to protect any employees with which the at-risk employee had been in contact. Cleco also has modified certain business practices, including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences, to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other federal, state, and local governmental and regulatory authorities. Cleco is continuing to address concerns to protect the health and safety of its employees and those of its customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, Cleco, its suppliers, and other business counterparties to experience operational delays.

In addition, Cleco has implemented certain measures that it believes will provide financial flexibility and maintain liquidity. On March 23, 2020, Cleco Holdings made an $88.0 million draw on its credit facility, and Cleco Power made a $150.0 million draw on its credit facility. While Cleco continues to assess the COVID-19 situation, at this time Cleco cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being

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experienced in the markets will have on its business, cash flows, liquidity, financial condition, and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities, including the LPSC and FERC, Cleco’s customers and suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding certain risks associated with the COVID-19 pandemic, see “Risk Factors — COVID-19.”

Credit Facility Amendments

On May 15, 2020, Cleco Holdings entered into the Cleco Holdings Amendments. Also, on May 15, 2020, Cleco Power entered into the Cleco Power Amendment. The Amendments extend the terms of each facility through June 28, 2022. The current borrowing costs under the amended Cleco Holdings revolving credit facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. Cleco Holdings’ amended $300.0 million term loan bears interest at an interest rate of LIBOR plus 1.875% and Cleco Holdings’ amended $30.0 million term loan bears interest at an interest rate of LIBOR plus 1.875%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and additional interest of 0.50% under any of the Cleco Holdings Amendments. The current borrowing costs under the amended Cleco Power revolving credit facility are equal to LIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees of 0.150%. If Cleco Power’s credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of 0.125% under the Cleco Power Amendment. The Amendments also include customary LIBOR-transition provisions.

OVERVIEW

Cleco is a regional energy company that, prior to the close of the Cleco Cajun Transaction, conducted substantially all of its business operations through its primary subsidiary, Cleco Power. As a result of the Cleco Cajun Transaction, Cleco now conducts substantially all of its business operations through its two primary subsidiaries:

• Cleco Power, a regulated electric utility company that owns 10 generating units with a total nameplate capacity of 3,360 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi; and

• Cleco Cajun, an unregulated electric utility company that owns eight generating assets with a rated capacity of 3,555 MW and supplies wholesale power and capacity in Arkansas, Louisiana, and Texas. Upon the closing of the Cleco Cajun Transaction, Cottonwood Energy entered into the Cottonwood Sale Leaseback.

Cleco Cajun Transaction

Upon completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a reportable segment and is reflected as such in this prospectus. For more information on the Cleco Cajun Transaction, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations.” Cleco’s unaudited condensed consolidated financial statements for the quarter ended March 31, 2019, include the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, until March 31, 2020.

Cleco Power

Many factors affect Cleco Power’s primary business of generating, delivering, and selling electricity. These factors include weather and the presence of a stable regulatory environment, which impacts cost recovery and the ROE, 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; the ability to reliably deliver power to its jurisdictional customers; the ability to comply with increasingly stringent regulatory and environmental standards; and the ability to successfully perform in MISO while subject to the related operating challenges and uncertainties, including increased wholesale competition. Cleco Power’s current key initiatives are continuing construction on the Bayou Vista to Segura Transmission project; continuing the DSMART project; and maintaining and growing its wholesale and retail business. These initiatives are discussed below.

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Bayou Vista to Segura Transmission Project

The Bayou Vista to Segura Transmission project includes the construction of 48 miles of 230kV transmission line, a 230/138kV substation and three substation expansions in south Louisiana. The project is expected to cost approximately $136.7 million. The project is expected to increase reliability, provide transmission system redundancy, and provide hurricane hardening for customers in south Louisiana. Cleco Power received MISO approval for the project in December 2017. Construction has begun on expansions to existing substations, with the northern phase expected to be completed in the first quarter of 2021 and the southern phase expected to be completed in the fourth quarter of 2021. As of March 31, 2020, Cleco Power had spent $15.6 million on the project.

DSMART Project

The DSMART project includes modernization of Cleco Power’s distribution system by replacing or upgrading distribution line equipment utilizing new and emerging technologies to facilitate automatic fault isolation, service restoration, and fault location. The project is expected to provide savings through a reduction in outage restoration time, time to locate faults, and improved operational efficiencies. The project is also expected to improve safety and reliability of Cleco Power’s distribution assets by minimizing outage patrols and improving situational awareness in the distribution operations center. The total estimated project cost is $90.2 million. The project implementation will be completed in phases and management expects the total project will be completed by the end of 2025. In January 2019, Cleco Power began the first phase of the project. As of March 31, 2020, Cleco Power had spent $2.7 million on the project.

Other

Cleco Power is working to secure load growth opportunities that include renewing existing franchises and wholesale contracts, pursuing new wholesale contracts and franchises, and adding new retail load opportunities with large industrial, commercial, and residential load. The retail opportunities include sectors such as agriculture, oil and gas, chemicals, metals, national accounts, government and military, wood and paper, health care, information technology, transportation, and other manufacturing.

RESULTS OF OPERATIONS

Use of Estimates

The preparation of financial statements 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.

Comparison of the Three Months Ended March 31, 2020, and 2019

Cleco
	FOR THE THREE MONTHS ENDED MAR. 31,
			FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2020	2019	VARIANCE	CHANGE
Operating revenue, net	$347,572	$344,186	$3,386	1.0%
Operating expenses	292,907	293,600	693	0.2%
Operating income	54,665	50,586	4,079	8.1%
Interest income	1,157	1,491	(334)	(22.4)%
Allowance for equity funds used during construction	(74)	5,688	(5,762)	(101.3)%
Other (expense) income, net	(12,709)	2,777	(15,486)	(557.7)%
Interest charges	35,149	33,999	(1,150)	(3.4)%
Federal and state income tax expense	1,562	5,986	4,424	73.9%
Net income	$6,328	$20,557	$(14,229)	(69.2)%

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Includes the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, through March 31, 2019, and January 1, 2020, through March 31, 2020.

COVID-19 Impacts

The rapid spread of COVID-19 and the varying degrees of restrictions on business and social activities imposed by federal, state, and local governments to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory, have caused Cleco to experience increasingly adverse business conditions, especially in the latter half of March 2020. While Cleco continues to assess the COVID-19 situation, at this time Cleco cannot estimate with any degree of certainty the full impact of the COVID-19 outbreak on its financial condition and future results of operations, although Cleco expects the COVID-19 situation to adversely impact future quarters. For additional discussion regarding risks associated with the COVID-19 pandemic, see “Risk Factors — COVID-19.”

Operating Revenue, Net

Operating revenue, net increased $3.4 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to higher electric operations revenue of $31.3 million and higher other operations revenue of $11.0 million at Cleco Cajun, partially offset by $38.4 million of lower fuel cost recovery revenue at Cleco Power.

Operating Expenses

Operating expenses increased $0.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $31.4 million of higher Cleco Cajun expenses, as well as $8.8 million of higher other operations and maintenance expenses and $2.7 million of higher taxes other than income taxes at Cleco Power. These increases were partially offset by $38.0 million of lower recoverable fuel and purchased power expenses at Cleco Power and $2.2 million of lower Cleco Cajun Transaction costs at Cleco Holdings.

Allowance for equity funds used during construction

Allowance for equity funds used during construction decreased $5.8 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $4.5 million of lower Cleco Power construction costs as a result of various projects being placed in service in 2019 and $1.0 million due to lower AFUDC rates driven by the impact of Cleco Power’s $150.0 million short-term debt borrowings outstanding under its credit facility.

Other (Expense) Income, Net

Other (expense) income, net increased $15.5 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $11.2 million for the decrease in cash surrender value of certain trust-owned life insurance policies as a result of unfavorable market conditions at Cleco Holdings and $2.0 million of higher pension non-service costs at Cleco Power.

Income Taxes

Federal and state income tax expense decreased $4.4 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.6 million for the change in pretax income, excluding AFUDC equity, and $1.2 million for state tax expenses.

The effective income tax rate for the first quarter of 2020 and 2019 was 19.8% and 22.6%, respectively. The estimated annual effective income tax rate used during the first quarter of 2020 and 2019 for Cleco may not be indicative of the full-year income tax rate.

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

Cleco Power
	FOR THE THREE MONTHS ENDED MARCH 31,
			FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2020	2019	VARIANCE	CHANGE
Operating revenue
Base	$147,999	$142,385	$5,614	3.9%
Fuel cost recovery	76,431	114,790	(38,359)	(33.4)%
Electric customer credits	(8,340)	(8,160)	(180)	(2.2)%
Other operations	15,764	19,430	(3,666)	(18.9)%
Affiliate revenue	1,106	300	806	268.7%
Operating revenue, net	232,960	268,745	(35,785)	(13.3)%
Operating expenses
Recoverable fuel and purchased power	76,834	114,794	37,960	33.1%
Non-recoverable fuel and purchased power	7,692	8,991	1,299	14.4%
Other operations and maintenance	56,944	47,700	(9,244)	(19.4)%
Depreciation and amortization	43,677	42,377	(1,300)	(3.1)%
Taxes other than income taxes	12,276	9,978	(2,298)	(23.0)%
Total operating expenses	197,423	223,840	26,417	11.8%
Operating income	35,537	44,905	(9,368)	(20.9)%
Interest income	954	994	(40)	(4.0)%
Allowance for equity funds used during construction	(74)	5,688	(5,762)	(101.3)%
Other (expense) income, net	(2,667)	268	(2,935)	*
Interest charges	18,581	17,145	(1,436)	(8.4)%
Federal and state income tax expense	3,338	7,998	4,660	58.3%
Net income	$11,831	$26,712	$(14,881)	(55.7)%

*
Not meaningful

The following table shows the components of Cleco Power’s retail and wholesale customer sales related to base revenue:

	FOR THE THREE MONTHS ENDED MARCH 31,
(MILLION kWh)	2020	​	2019	FAVORABLE/ (UNFAVORABLE)
Electric sales		​
Residential	780	​	787	(0.9)%
Commercial	582	​	582	—%
Industrial	484	​	490	(1.2)%
Other retail	31	��	31	—%
Total retail	1,877	​	1,890	(0.7)%
Sales for resale	650	​	619	5.0%
Total retail and wholesale customer sales	2,527	​	2,509	0.7%

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The following table shows the components of Cleco Power’s base revenue:

	FOR THE THREE MONTHS ENDED MARCH 31,
(THOUSANDS)	2020	2019	FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	$61,890	$56,104	10.3%
Commercial	47,056	44,863	4.9%
Industrial	20,580	20,649	(0.3)%
Other retail	2,679	2,558	4.7%
Surcharge	2,442	5,321	(54.1)%
Total retail	134,647	129,495	4.0%
Sales for resale	13,352	12,890	3.6%
Total base revenue	$147,999	$142,385	3.9%

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 readily available, and winter energy is typically priced below the rate charged for energy used in the summer. Normal heating degree-days and cooling degree-days are calculated for a month by separately calculating the average actual heating and cooling degree-days for that month over a period of 30 years.

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

	FOR THE THREE MONTHS ENDED MARCH 31,
				CHANGE
	2020	2019	NORMAL	PRIOR YEAR	NORMAL
Heating degree-days	586	733	891	(20.1)%	(34.2)%
Cooling degree-days	264	108	78	144.4%	238.5%

Base

Base revenue increased $5.6 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to the absence of $4.6 million of deferrals to a regulatory liability for over collections of revenue related to the St. Mary Clean Energy Center project due to the delay in the project’s commercial operational date and the absence of $2.6 million for the reversal of the accumulated LCFC revenue, partially offset by $1.7 million of lower Cleco Katrina/Rita storm restoration surcharge revenue as a result of the completion of the Cleco Katrina/Rita bond repayment in March 2020. For information on the effects of future energy sales on the results of operations, financial condition, or cash flows of Cleco Power, see “Risk Factors — Operational Risks — Future Electricity Sales.”

Fuel Cost Recovery/Recoverable Fuel and Purchased Power

Changes in fuel costs historically have not significantly affected Cleco Power’s net income. Generally, fuel and purchased power expenses are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to its customers substantially all such charges. Approximately 77% of Cleco Power’s total fuel cost during the first quarter of 2020 was regulated by the LPSC. Recovery of FAC costs is subject to periodic fuel audits by the LPSC which may result in a refund to customers. Generally, fuel and purchased power expenses are impacted by customer usage, the per unit cost of fuel used for electric generation, and the dispatch of Cleco Power’s generating facilities by MISO. For more information Cleco Power’s most current fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel

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Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit.”

Other Operations Revenue

Other operations revenue decreased $3.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to the absence of $2.4 million of net generation revenue as a result of the Teche Unit 3 SSR ending in April 2019 and $0.5 million of lower forfeited discounts. For more information on the SSR, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — SSR.”

Other Operations and Maintenance Expense

Other operations and maintenance expense increased $9.2 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $3.5 million of higher fees for outside services, $2.9 million of higher generating station outage maintenance expenses, and $2.3 million of higher uncollectible accounts expense.

Depreciation and Amortization

Depreciation and amortization increased $1.3 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $3.0 million of higher depreciation on normal recurring additions to fixed assets and $2.1 million of higher amortization of intangible property due to the implementation of the START project, partially offset by $2.7 million of lower amortization of storm damages which is based on collections from customers, and the absence of $1.1 million of deferrals of corporate franchise taxes to a regulatory asset.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2.3 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $1.4 million of higher property taxes and $0.5 million of higher franchise taxes.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction decreased $5.8 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $4.5 million of lower construction costs as a result of the St. Mary Clean Energy Center project, the Coughlin Pipeline project, the Terrebonne to Bayou Vista Transmission project, and the START project being placed in service in 2019 and $1.0 million due to lower AFUDC rates driven by the impact of Cleco Power’s $150.0 million short-term debt borrowings outstanding under its credit facility.

Other (Expense) Income, Net

Other (expense) income, net increased $2.9 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.0 million of higher pension non-service costs and $0.7 million for the decrease in the cash surrender value of company-owned life insurance policies.

Interest Charges

Interest charges increased $1.4 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to lower allowance for borrowed funds used during construction primarily due to the St. Mary Clean Energy Center project, the Coughlin Pipeline project, the Terrebonne to Bayou Vista Transmission project, and the START project being placed in service in 2019.

Income Taxes

Federal and state income tax expense decreased $4.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.8 million for the change in pretax income, excluding AFUDC equity, and $1.6 million for state tax expenses.

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The effective income tax rate for the first quarter of 2020 and 2019 was 22.0% and 23.0%, respectively. The estimated annual effective income tax rate used during the first quarter of 2020 and 2019 for Cleco Power may not be indicative of the full-year income tax rate.

Cleco Cajun
	FOR THE THREE MONTHS ENDED MARCH 31,
			FAVORABLE/(UNFAVORABLE)
(THOUSANDS)	2020	2019	VARIANCE	CHANGE
Operating revenue
Electric operations	$89,147	$58,194	$30,953	53.2%
Electric customer credits	(153)	—	(153)	(100.0)%
Other operations	30,961	19,965	10,996	55.1%
Affiliate revenue	161	—	161	100.0%
Operating revenue, net	120,116	78,159	41,957	53.7%
Operating expenses
Fuel used for electric generation	15,572	9,922	(5,650)	(56.9)%
Purchased power	44,675	30,445	(14,230)	(46.7)%
Other operations and maintenance	20,516	14,410	(6,106)	(42.4)%
Depreciation and amortization	10,103	5,410	(4,693)	(86.7)%
Taxes other than income taxes	3,473	3,145	(328)	(10.4)%
Total operating expenses	94,339	63,332	(31,007)	(49.0)%
Operating income	25,777	14,827	10,950	73.9%
Interest income	155	254	(99)	(39.0)%
Other income (expense), net	34	(496)	530	106.9%
Interest charges	10	—	(10)	(100.0)%
Federal and state income tax expense	6,421	3,529	(2,892)	(81.9)%
Net income	$19,535	$11,056	$8,479	76.7%

Represents the financial results from the closing of the Cleco Cajun Transaction on February 4, 2019, through March 31, 2019, and January 1, 2020, through March 31, 2020.

Electric Operations

Electric operations revenue increased $31.0 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to the increase in wholesale revenue, which is partially the result of the Cleco Cajun Transaction closing in February 2019.

Other Operations Revenue

Other operations revenue increased $11.0 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $5.7 million of higher lease revenue, including variable lease revenue, as a result of the Cottonwood Sale Leaseback and $3.6 million of higher transmission revenue from wholesale customers. These increases were partially the result of the Cleco Cajun Transaction closing in February 2019. For more information on the Cottonwood Sale Leaseback agreement, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases — Lessor Agreements — Cottonwood Sale Leaseback Agreement” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 4 — Leases — Cottonwood Sale Leaseback Agreement.”

Fuel Used for Electric Generation

Fuel used for electric generation increased $5.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to mark-to-market losses for gas related derivative contracts and higher fuel costs, which is partially the result of the Cleco Cajun Transaction closing in February 2019.

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Purchased Power

Purchased power increased $14.2 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to a higher amount of purchased power from MISO, which is partially the result of the Cleco Cajun Transaction closing in February 2019.

Other Operations and Maintenance Expense

Other operations and maintenance expense increased $6.1 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $3.7 million of higher generation operations expenses and $2.3 million of higher administrative and generations expenses. These increases were partially the result of the Cleco Cajun Transaction closing in February 2019.

Depreciation and Amortization

Depreciation and amortization increased $4.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to normal recurring additions to fixed assets. This increase was partially the result of the Cleco Cajun Transaction closing in February 2019.

Income Taxes

Federal and state income tax expense increased $2.9 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.4 million for the increase in pretax income and $1.0 million for state tax expenses. These increases were partially offset by $0.5 million of miscellaneous tax items.

The effective income tax rate for the first quarter of 2020 and 2019 was 24.7% and 24.2%, respectively. The estimated annual effective income tax rate used during the first quarter of 2020 and 2019 for Cleco Cajun may not be indicative of the full-year income tax rate.

Comparison of the Years Ended December 31, 2019, and 2018

Cleco
	FOR THE YEAR ENDED DEC. 31,
			FAVORABLE / (UNFAVORABLE)
(THOUSANDS)	2019	2018	VARIANCE	CHANGE
Operating revenue, net	$1,639,605	$1,231,044	$408,561	33.2%
Operating expenses	1,324,711	986,487	(338,224)	(34.3)%
Operating income	314,894	244,557	70,337	28.8%
Interest income	6,090	6,073	17	0.3%
Allowance for equity funds used during construction	15,397	14,159	1,238	8.7%
Other income (expense), net	758	(14,328)	15,086	105.3%
Interest charges	141,309	126,642	(14,667)	(11.6)%
Federal and state income tax expense	43,165	29,382	(13,783)	(46.9)%
Net income	$152,665	$94,437	$58,228	61.7%

Significant factors affecting Cleco’s net income during the year ended December 31, 2019, are described below.

Operating Revenue

Operating revenue, net increased $408.6 million during 2019 as compared to 2018 primarily due to the addition of $375.5 million of electric operations and $117.5 million of other operations revenue at Cleco Cajun. These increases were partially offset by $51.4 million of lower fuel cost recovery revenue at Cleco Power.

Operating Expenses

Operating expenses increased $338.2 million during 2019 as compared to 2018 primarily due to the addition of $400.3 million of Cleco Cajun’s operating expenses, as well as $10.4 million of higher depreciation and amortization expenses and $4.6 million of higher other operations and maintenance expenses at Cleco Power. These increases were partially offset by $51.3 million of lower recoverable fuel and purchased power expenses at Cleco Power.

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Other Income (Expense), Net

Other income (expense), net increased $15.1 million during 2019 as compared to 2018 primarily due to $10.3 million for the increase in cash surrender value of certain trust-owned life insurance policies as a result of favorable market conditions at Cleco Holdings and $4.0 million of lower pension non-service costs at Cleco Power.

Interest Charges

Interest charges increased $14.7 million during 2019 as compared to 2018 primarily due to $9.3 million of interest associated with the financing of the Cleco Cajun Transaction and $3.2 million of interest associated with the private placement of senior notes entered into on September 11, 2019, at Cleco Holdings. For more information about the senior notes issued on September 11, 2019, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt — Cleco Debt.”

Income Taxes

Federal and state income tax expense increased $13.8 million during 2019 as compared to 2018 primarily due to the change in pretax income, excluding AFUDC equity. The effective income tax rate for the year ended December 31, 2019, was 22.0% which was different than the federal statutory rate. For more information about the difference in the effective income tax rate and the federal statutory rate, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 11 — Income Taxes — Cleco.”

Results of operations for Cleco Power and Cleco Cajun 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. These factors include, among others, an increasingly competitive business environment; the ability to recover costs through rate-setting proceedings; the ability to successfully perform in MISO and the related operating challenges; the cost of compliance with environmental and reliability regulations; conditions in the credit markets and global economy; changes in the federal and state regulation of generation, transmission, and the sale of electricity; the regulatory treatment of the TCJA, and the increasing uncertainty of future federal and state regulatory and environmental policies. For a discussion of various regulatory changes and competitive forces affecting Cleco Power and other electric utilities, see “Forward-Looking Statements,” “Business — Regulatory Matters, Industry Developments, and Franchises,” and “— Financial Condition — Regulatory and Other Matters — Market Restructuring.” For a discussion of risk factors affecting Cleco Power’s business, see “Risk Factors.” For more information about the TCJA, see “— Financial Condition — Liquidity and Capital Resources — General Considerations and Credit-Related Risks — TCJA.”

Cleco Power’s residential customers’ demand for electricity is affected largely by weather. Weather is generally 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 readily available, and energy used in the winter is typically 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.

Over the last five years, Cleco Power has experienced moderate growth in retail non-industrial sales and anticipates the same over the next five years. Cleco Power may experience increases in the retail industrial class in 2020, due to changes in the oil and gas industry. In addition, Cleco Power expects to begin providing service to expansions of current customers’ operations, as well as service to new retail customers. 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. Cleco Power is pursuing load growth opportunities that include renewal of

41

existing franchises and wholesale contracts as well as adding new wholesale customers and franchises. For more information on other expectations of future energy sales on Cleco Power, see “— Comparison of the Years Ended December 31, 2019, and 2018 — Base,” “Forward-Looking Statements,” and “Risk Factors — Operational Risks — Future Electricity Sales.”

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

• imposition of federal and/or state renewable portfolio standards (“RPS”),

• 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 fuels and the addition of new generation capacity,

• transmission congestion costs,

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

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

• changes in the credit markets and local and global economies.

For more information on energy legislation in regulatory matters that could affect Cleco, see “Business — Regulatory Matters, Industry Developments, and Franchises — Legislative and Regulatory Changes and Matters.”

Cleco Power’s revenues and earnings are substantially affected by regulatory proceedings known as rate cases, or in some cases, a request for extension of an FRP. During those cases, the LPSC 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 customers through its rates. In some instances, the outcome of a rate case or request for extension of an FRP may impact wholesale decisions of Cleco Power. These proceedings may examine, among other things, the prudence of Cleco Power’s operation and maintenance practices, level of 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. Rate cases generally have timelines of approximately one year, and decisions are typically subject to appeal, potentially leading to additional uncertainty. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP, with anticipated new rates being effective July 1, 2020. The transmission tariffs of Cleco Power are regulated by FERC with its own regulatory proceedings. Both the LPSC and FERC regulatory proceedings can involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, all of whom have differing concerns but who have the common objective of limiting rate increases or reducing rates.

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 amortization, and taxes other than income taxes. Other operations expenses are affected by, among other things, the cost of employee benefits, insurance expense, and the costs associated with energy delivery and customer service. Annual maintenance expenses associated with Cleco Power’s plants generally depend upon their physical characteristics, maintenance practices, and 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 and amortization expense is primarily 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 property taxes. Cleco Power anticipates certain non-fuel cost recovery expenses to be higher in 2020 as compared to 2019. These expenses include higher depreciation and amortization expense, higher taxes other than income taxes, higher miscellaneous expense, higher distribution operations expense, higher interest expense, higher generation operations expense, and higher administration and general operations expense, partially offset by lower distribution maintenance expense.

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	FOR THE YEAR ENDED DEC. 31,
			FAVORABLE / (UNFAVORABLE)
(THOUSANDS)	2019	2018	VARIANCE	CHANGE
Operating revenue
Base	$669,091	$678,378	$(9,287)	(1.4)%
Fuel cost recovery	461,837	513,209	(51,372)	(10.0)%
Electric customer credits	(38,516)	(33,195)	(5,321)	(16.0)%
Other operations	72,833	82,330	(9,497)	(11.5)%
Affiliate revenue	3,125	874	2,251	257.6%
Operating revenue, net	1,168,370	1,241,596	(73,226)	(5.9)%
Operating expenses
Recoverable fuel and purchased power	461,877	513,206	51,329	10.0%
Non-recoverable fuel and purchased power	34,648	37,530	2,882	7.7%
Other operations and maintenance	207,164	202,552	(4,612)	(2.3)%
Depreciation and amortization	172,471	162,069	(10,402)	(6.4)%
Taxes other than income taxes	43,742	47,267	3,525	7.5%
Total operating expenses	919,902	962,624	42,722	4.4%
Operating income	248,468	278,972	(30,504)	(10.9)%
Interest income	4,744	5,052	(308)	(6.1)%
Allowance for equity funds used during construction	15,397	14,159	1,238	8.7%
Other expense, net	(3,616)	(8,699)	5,083	58.4%
Interest charges	71,279	71,303	24	—%
Federal and state income tax expense	45,452	55,924	10,472	18.7%
Net income	$148,262	$162,257	$(13,995)	(8.6)%

The following table shows the components of Cleco Power’s retail and wholesale customer sales related to base revenue:

	FOR THE YEAR ENDED DEC. 31,
(MILLION kWh)	2019	2018	FAVORABLE / (UNFAVORABLE)
Electric sales
Residential	3,589	3,780	(5.1)%
Commercial	2,772	2,731	1.5%
Industrial	2,027	2,243	(9.6)%
Other retail	129	133	(3.0)%
Total retail	8,517	8,887	(4.2)%
Sales for resale	3,046	2,991	1.8%
Total retail and wholesale customer sales	11,563	11,878	(2.7)%

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The following table shows the components of Cleco Power’s base revenue:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	FAVORABLE / (UNFAVORABLE)
Electric sales
Residential	$297,204	$304,708	(2.5)%
Commercial	198,664	192,781	3.1%
Industrial	84,030	90,291	(6.9)%
Other retail	10,786	10,918	(1.2)%
Storm surcharge	22,132	23,138	(4.3)%
Total retail	612,816	621,836	(1.5)%
Sales for resale	56,275	56,542	(0.5)%
Total base revenue	$669,091	$678,378	(1.4)%

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

	FOR THE YEAR ENDED DEC. 31,
				2019 CHANGE
	2019	2018	NORMAL	PRIOR YEAR	NORMAL
Cooling degree-days	3,178	3,311	2,779	(4.0)%	14.4%
Heating degree-days	1,325	1,470	1,547	(9.9)%	(14.4)%

Significant factors affecting Cleco Power’s net income during the year ended December 31, 2019, are described below.

Base

Base revenue decreased $9.3 million in 2019 as compared to 2018 primarily due to $6.8 million of milder weather and $2.5 million of lower rates. For more information on the effects of future energy sales on the results of operations, financial condition, or cash flows of Cleco Power, see “— Significant Factors Affecting Cleco Power,” “Forward-Looking Statements,” and “Risk Factors — Operational Risks — Future Electricity Sales.”

Fuel Cost Recovery/Recoverable Fuel and Purchased Power

Fuel costs historically have not significantly affected Cleco Power’s net income. Generally, fuel and purchased power expenses are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to its customers substantially all such charges. Approximately 76% of Cleco Power’s total fuel cost during 2019 was regulated by the LPSC. Recovery of FAC costs is subject to periodic fuel audits by the LPSC which may result in a refund to customers. Generally, fuel and purchased power expenses are impacted by customer usage, the per unit cost of fuel used for electric generation, and the dispatch of Cleco Power’s generating facilities by MISO. Fuel and purchased power expenses may also be impacted by the interruption of the continuous supply of lignite due to adverse weather conditions and other factors that disrupt mining operations and transportation to Dolet Hills Power Station. For more information on the accounting for MISO transactions, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Accounting for MISO Transactions.” For more information on Cleco Power’s most current fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit.”

Electric Customer Credits

Electric customer credits increased $5.3 million in 2019 as compared to 2018 primarily related to $3.4 million for the estimated refunds due to Cleco Power’s wholesale transmission customers as a result of the FERC audit and $2.3 million of higher estimated FRP refunds. For more information on the FERC audit, see “Financial

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Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — FRP,” “Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — FERC Audit.”

Other Operations Revenue

Other operations revenue decreased $9.5 million in 2019 as compared to 2018 primarily related to $6.8 million of lower net generation revenue as a result of the Teche Unit 3 SSR ending in April 2019 and $2.1 million of lower reconnect fees. For more information on the SSR, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR.”

Non-Recoverable Fuel and Purchased Power

Non-recoverable fuel and purchased power decreased $2.9 million in 2019 as compared to 2018 primarily due to lower MISO transmission costs as a result of the Teche Unit 3 SSR ending in April 2019.

Other Operations and Maintenance Expense

Other operations and maintenance expense increased $4.6 million during 2019 as compared to 2018 primarily related to $6.9 million of higher outside service expenses, $6.4 million of higher generation operations expenses, and $4.1 million of higher customer service expenses, partially offset by $13.0 million of lower generating station outage maintenance expenses.

Depreciation and Amortization

Depreciation and amortization increased $10.4 million during 2019 as compared to 2018 primarily related to $4.0 million of lower deferrals of corporate franchise taxes to a regulatory asset, $3.8 million of higher normal recurring additions to fixed assets, and $2.7 million of higher amortization of intangible property due to the installation of a new enterprise business applications suite.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $3.5 million in 2019 as compared to 2018 primarily related to lower corporate franchise taxes.

Other Expense, Net

Other expense, net decreased $5.1 million during 2019 as compared to 2018 primarily related to $4.0 million of lower pension non-service costs and $0.6 million for the change in cash surrender value of life insurance policies.

Income Taxes

Federal and state income taxes decreased $10.5 million during 2019 as compared to 2018 primarily due to $6.2 million for the change in pretax income, excluding AFUDC equity, $3.2 million for flowthrough of state tax benefits, and $2.5 million of adjustment to tax returns as filed. These decreases were partially offset by $1.4 million of miscellaneous tax items. The effective income tax rate for the year ended December 31, 2019, was 23.5% which was different than the federal statutory rate. For more information about the difference in the effective income tax rate and the federal statutory rate, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 11 — Income Taxes — Cleco Power.”

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Cleco Cajun
(THOUSANDS)	FOR THE YEAR ENDED DEC. 31, 2019
Operating revenue
Electric operations	$375,489
Electric customer credits	(1,447)
Other operations	117,468
Affiliate revenue	108
Operating revenue, net	491,618
Operating expenses
Fuel used for electric generation	81,514
Purchased power	177,254
Other operations and maintenance	91,215
Depreciation and amortization	35,544
Taxes other than income taxes	14,785
Total operating expenses	400,312
Operating income	91,306
Interest income	987
Other expense, net	(368)
Interest charges	35
Federal and state income tax expense	22,479
Net income	$69,411

Significant factors affecting Cleco Cajun’s net income from the closing of the Cleco Cajun Transaction on February 4, 2019, through December 31, 2019, are described below.

Operating Revenue

Operating revenue, net of $491.6 million during 2019 primarily consisted of $375.5 million of electric operations revenue from wholesale customers, $57.1 million of lease revenue, including variable lease revenue, as a result of the Cottonwood Sale Leaseback, and $47.9 million of transmission revenue from wholesale customers. For more information on the Cottonwood Sale Leaseback agreement, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases — Lessor Agreements — Cottonwood Sale Leaseback Agreement.”

Operating Expense

Operating expenses of $400.3 million during 2019 primarily consisted of $120.5 million of purchased power from MISO, $81.5 million of fuel expenses for generation, $50.3 million of MISO transmission costs, $34.9 million of depreciation on fixed assets, $29.2 million of general and administrative expense, $27.5 million for generating station operations expenses, and $26.5 million of routine generating station maintenance expenses.

Income Taxes

Federal and state income taxes of $22.5 million during 2019 primarily included $19.3 million of tax expense on pretax income at the statutory tax rate and $2.7 million for state taxes. The effective income tax rate for 2019 was 24.5%. The estimated annual effective income tax rate used for 2019 for Cleco Cajun may not be indicative of the full-year income tax rate.

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Comparison of the Years Ended December 31, 2018, and 2017

Cleco
	FOR THE YEAR ENDED DEC. 31,
			FAVORABLE / (UNFAVORABLE)
(THOUSANDS)	2018	2017	VARIANCE	CHANGE
Operating revenue, net	$1,231,044	$1,175,646	$55,398	4.7%
Operating expenses	986,487	910,419	76,068	8.4%
Operating income	$244,557	265,227	(20,670)	(7.8)%
Interest income	6,073	1,424	4,649	326.5%
Allowance for equity funds used during construction	14,159	8,320	5,839	70.2%
Other expense, net	(14,328)	(6,899)	(7,429)	(107.7)%
Interest charges	126,642	122,913	3,729	3.0%
Federal and state income tax expense	29,382	7,079	22,303	315.1%
Net income	$94,437	$138,080	$(43,643)	(31.6)%

Operating revenue, net increased $55.4 million during 2018 as compared to the 2017 primarily due to $56.6 million of higher fuel cost recovery revenue at Cleco Power, and $27.7 million higher base revenue at Cleco Power, partially offset by $31.6 million of higher electric customer credits at Cleco Power.

Operating expenses increased $76.1 million during 2018 as compared to 2017 primarily due to $56.7 million of higher recoverable fuel and power purchased expenses at Cleco Power and $14.4 million of expenses associated with the Cleco Cajun Transaction at Cleco Holdings.

Interest income increased $4.6 million during 2018 as compared to 2017 primarily due to $2.7 million of higher interest rates and balances on temporary investments and $1.2 million of interest on a note receivable at Cleco Power.

Allowance for equity funds used during construction increased $5.8 million during 2018 as compared to 2017 primarily due to higher construction costs related to various projects.

Other expense, net increased $7.4 million during 2018 as compared to 2017 primarily due to $6.4 million of change in value of life insurance policies as a result of unfavorable market conditions at Cleco Holdings.

Federal and state income tax expense increased $22.3 million during 2018 as compared to 2017 primarily due to $46.3 million for the absence of adjustments related to the TCJA and $3.7 million for the flowthrough of state tax benefits. The increases were partially offset by $15.2 million for the reduction in the federal statutory tax rate as prescribed by the TCJA and $10.5 million for the change in pretax income, excluding AFDUC equity. The effective income tax rate for the year ended December 31, 2018, was 23.7%. For more information on the TCJA, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — TCJA.”

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

Cleco Power
	FOR THE YEAR ENDED DEC. 31,
			FAVORABLE / (UNFAVORABLE)
(THOUSANDS)	2018	2017	VARIANCE	CHANGE
Operating revenue
Base	$678,378	$651,732	$26,646	4.1%
Fuel cost recovery	513,209	456,657	56,552	12.4%
Electric customer credits	(33,195)	(1,566)	(31,629)	*
Other operations	82,330	77,522	4,808	6.2%
Affiliate revenue	874	851	23	2.7%
Operating revenue, net	$1,241,596	$1,185,196	$56,400	4.8%
Operating expenses
Recoverable fuel and purchased power	513,206	456,509	(56,697)	(12.4)%
Non-recoverable fuel and purchased power	37,530	35,750	(1,780)	(5.0)%
Other operations and maintenance	202,552	202,738	186	0.1%
Depreciation and amortization	162,069	158,415	(3,654)	(2.3)%
Taxes other than income taxes	47,267	46,539	(728)	(1.6)%
Total operating expenses	962,624	899,951	(62,673)	(7.0)%
Operating income	$278,972	$285,245	$(6,273)	(2.2)%
Allowance for equity funds used during construction	$14,159	$8,320	$5,839	70.2%
Interest charges	$71,303	$69,362	$(1,941)	(2.8)%
Federal and state income tax expense	$55,924	$67,331	$11,407	16.9%
Net income	$162,257	$150,738	$11,519	7.6%

*
Not Meaningful

Cleco Power’s net income for 2018 increased $11.5 million compared to 2017 primarily as a result of the following factors:

• higher base revenue,

• lower federal and state income tax expense,

• higher allowance for equity funds used during construction,

• higher other operations revenue, and

• higher interest income.

These increases were partially offset by:

• higher electric customer credits,

• higher depreciation and amortization, and

• higher interest charges.

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The following table shows the components of Cleco Power’s retail and wholesale customer sales related to base revenue:

	FOR THE YEAR ENDED DEC. 31,
(MILLION kWh)	2018	2017	FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	3,780	3,526	7.2%
Commercial	2,731	2,650	3.1%
Industrial	2,243	2,078	7.9%
Other retail	133	131	1.5%
Total retail	8,887	8,385	6.0%
Sales for resale	2,991	2,959	1.1%
Total retail and wholesale customer sales	11,878	11,344	4.7%

The following table shows the components of Cleco Power’s base revenue:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2018	2017	FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	$304,708	$286,587	6.3%
Commercial	192,781	188,431	2.3%
Industrial	90,291	87,528	3.2%
Other retail	10,918	10,592	3.1%
Surcharge	23,138	20,965	10.4%
Total retail	621,836	594,103	4.7%
Sales for resale	56,542	57,629	(1.9)%
Total base revenue	$678,378	$651,732	4.1%

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

	FOR THE YEAR ENDED DEC. 31,			2018 CHANGE
	2018	2017	NORMAL	PRIOR YEAR	NORMAL
Cooling degree-days	3,311	3,044	2,779	8.8%	19.1%
Heating degree-days	1,470	1,029	1,546	42.9%	(4.9)%

Base

Base revenue increased $26.6 million in 2018 as compared to 2017 primarily due to $22.6 million of higher usage from warmer summer weather and colder winter weather and $4.1 million due to higher rates.

Fuel Cost Recovery/Recoverable Fuel and Purchased Power

Changes in fuel costs historically have not significantly affected Cleco Power’s net income. Generally, fuel and purchased power expenses are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to its customers substantially all such charges. Approximately 76% of Cleco Power’s total fuel cost during 2018 was regulated by the LPSC. Recovery of FAC costs is subject to periodic fuel audits by the LPSC which may result in a refund to customers. Generally, fuel and purchased power expenses are impacted by customer usage, the per unit cost of fuel used for electric generation, and the dispatch of Cleco Power’s generating facilities by MISO. Fuel and purchased power expenses were also impacted by the interruption of the continuous supply of lignite due to adverse weather conditions and other factors that disrupted mining operations and transportation to Dolet Hills Power Station. For more information on the accounting for MISO transactions, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Accounting for MISO Transactions.” For more information on

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Cleco Power’s fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit.”

Electric Customer Credits

Electric customer credits increased $31.6 million in 2018 as compared to 2017 primarily due to accrued estimated refunds for the tax-related benefits of the TCJA. For more information on the TCJA, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 11 — Income Taxes — TCJA,” “Note 13 — Regulation and Rates — TCJA.”

Other Operations Revenue

Other operations revenue increased $4.8 million in 2018 as compared to 2017 primarily due to $2.3 million of higher revenue from wholesale customers due to the absence of the 2017 customer credits relating to the MISO ROE complaints, $1.6 million of higher net transmission and distribution revenue, and $0.2 million of higher generation revenue from the Teche Unit 3 SSR. The $0.2 million of Teche Unit 3 SSR revenue consisted of $1.8 million higher revenue, partially offset by $1.6 million of expected refunds to MISO as a result of the SSR settlement agreement. For more information on the SSR, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR.”

Other Operations and Maintenance Expense

Other operations and maintenance expense decreased $0.2 million in 2018 as compared to 2017 primarily due to $7.6 million of higher deferrals of production operations and maintenance expenses to a regulatory asset, $7.5 million of lower compensation expense, and the absence of $1.9 million for the write-off of an uncollectible account. These decreases were partially offset by $5.6 million of higher fees for outside services, $3.4 million of higher employee benefits expenses, $2.9 million of higher net generating station outage and routine maintenance expenses, $2.8 million of higher customer service expenses, $1.7 million of higher distribution operations expenses, and $1.5 million of higher generation operations expenses.

Depreciation and Amortization

Depreciation and amortization expense increased $3.7 million in 2018 as compared to 2017 primarily due to $4.2 million of normal recurring additions to fixed assets and $3.8 million of higher amortization of storm damages which is based on collections from customers. These increases were partially offset by $2.7 million of higher deferrals of corporate franchise taxes to a regulatory asset and $1.4 million of lower amortization of the production operations and maintenance regulatory asset.

Interest Income

Interest income increased $3.8 million in 2018 as compared to 2017 primarily due to $1.7 million of higher interest rates and balances on temporary investments and $1.2 million of interest on a note receivable.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $5.8 million in 2018 as compared to 2017 primarily due to higher construction costs related to the St. Mary Clean Energy Center project, the Coughlin Pipeline project, the START project, the Terrebonne to Bayou Vista Transmission project, and the Bayou Vista to Segura Transmission project.

Interest Charges

Interest charges increased $1.9 million in 2018 as compared to 2017 primarily due to $4.9 million of interest on senior notes issued in December 2017 and March 2018. This increase was partially offset by $2.4 million of higher allowance for borrowed funds used during construction and $1.0 million of lower interest on Cleco Katrina/Rita storm recovery bonds.

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Income Taxes

Federal and state income taxes decreased $11.4 million in 2018 as compared to 2017. Tax expense decreased primarily due to $26.9 million related to the reduction in the federal statutory tax rate as prescribed by the TCJA, $2.2 million for the change in pretax income, excluding AFUDC equity, and $1.3 million for adjustments for permanent tax differences. These decreases were partially offset by $14.3 million for the absence of adjustments related to the TCJA and $3.7 million for the flowthrough of state tax benefits. The effective income tax rate is 25.6%, which is different than the federal statutory rate primarily due to permanent tax differences, the flowthrough of benefits associated with AFUDC equity, adjustments for tax returns as filed, tax credits, and state tax expense. For more information on the TCJA, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 11 — Income Taxes — TCJA,” “Note 13 — Regulation and Rates — TCJA.”

CRITICAL ACCOUNTING POLICIES

Cleco’s critical accounting policies include accounting policies that are important to Cleco’s financial condition and results of operations and 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. The preparation of financial statements contained in this report requires management to make estimates and assumptions. Estimates and assumptions about future events and their effects cannot be made with certainty. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. 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 “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies.”

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

• To determine assets, liabilities, and expenses relating to pension and other postretirement benefits, management must make assumptions about future trends. Assumptions and estimates include, but are not limited to, discount rates, expected return on plan assets, mortality rates, 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, 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 2019 return on plan assets was 22.17% compared to an expected long-term return of 6.55%. For 2018, the plan assets had a negative return of (7.31)% compared to an expected long-term return of 5.86%. For the calculation of the 2020 periodic expense, Cleco decreased the expected long-term return on plan assets to 5.91%.

Management uses a theoretical bond portfolio in order to calculate the discount rate for the measurement of liabilities. As a result of the annual review of assumptions, the pension plan discount rate decreased from 4.35% to 3.43% for the December 31, 2019, 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. Historically, Cleco Power has been allowed to recover pension plan expenses; therefore, 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 (approximately eight years as of December 31, 2019, for Cleco’s plan) when it exceeds certain thresholds. This approach of

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amortizing gains and losses has the effect of reducing the volatility of pension expense. Over time, it is not expected to reduce or increase the pension expense relative to an approach that immediately recognizes losses and gains.

The following table shows the impact of a 0.5% change in Cleco’s pension plan discount rate, salary scale, and rate of return on plan assets:

ACTUARIAL ASSUMPTION (THOUSANDS)	CHANGE IN ASSUMPTION	CHANGE IN PROJECTED BENEFIT OBLIGATION	CHANGE IN ESTIMATED BENEFIT COST
Discount rate	0.5% increase	$(41,744)	$(4,323)
	0.5% decrease	$46,870	$4,775
Salary scale	0.5% increase	$8,428	$1,669
	0.5% decrease	$(7,650)	$(1,510)
Expected return on assets	0.5% increase	$—	$(2,113)
	0.5% decrease	$—	$2,113

Cleco Power made a $12.3 million discretionary contribution to the pension plan in 2019. Cleco Power did not make any required or discretionary contributions to the pension plan in 2018 or 2017. Based on funding assumptions at December 31, 2019, management estimates that $66.5 million in pension contributions will be required through 2024. Cleco expects to make $83.0 million in discretionary contributions during 2020, which would reduce the future required contributions. 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 “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 10 — Pension Plan and Employee Benefits” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 9 — Pension Plan and Employee Benefits.

• Cleco has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. At March 31, 2020, Cleco Power had $144.7 million in regulatory assets, net. As a result of the 2016 Merger, Cleco Holdings recognized regulatory assets. At March 31, 2020, Cleco Holdings had $155.4 million of regulatory assets. Actions by the LPSC could limit the recovery of Cleco’s regulatory assets, causing Cleco to record a loss on some or all of the regulatory assets. If future recovery of costs ceases to be probable, Cleco Holdings could be required to record a loss of its regulatory assets associated with acquisition adjustments. For more information on the LPSC and regulatory assets, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Regulation,” “Note 6 — Regulatory Assets and Liabilities,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 6 — Regulatory Assets and Liabilities.”

• 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 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.

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For more information on income taxes, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 11 — Income Taxes” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 10 — Income Taxes.”

• Cleco is currently involved in certain legal proceedings and management has estimated the probable costs for the resolution of these claims. These estimates are based on an analysis of potential results, assuming a combination of litigation and settlement assumptions. For more information on legal proceedings affecting Cleco, see “Business — Environmental Matters — Air Quality,” “Risk Factors — Operational Risks — Litigation,” “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation.”

• Assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if it exceeds the estimated fair value. On April 13, 2016, in connection with the completion of the 2016 Merger, Cleco recognized goodwill of $1.49 billion. Goodwill is required to be tested for impairment at the reporting segment level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting segment below its carrying value. Additionally, on the date of the 2016 Merger, intangible assets were recognized for fair value adjustments of the Cleco trade name and long-term wholesale power supply contracts. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizing independent valuation experts, and involves the use of significant estimates and assumptions. Management’s judgments and estimates can materially impact the financial statements in periods after acquisition, such as through depreciation, amortization, and goodwill impairment. For more information on intangible assets and goodwill recorded in connection with the 2016 Merger, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 17 — Intangible Assets, Intangible Liabilities, and Goodwill.”

Cleco Power

Cleco Power’s retail rates are regulated by the LPSC. Future rate changes could have a material impact on the results of operations, financial condition, or cash flows of Cleco Power. Areas that could be materially impacted by future actions of regulators are described below:

• 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 March 31, 2020, the carrying value of Cleco Power’s long-lived assets was $3.60 billion. Currently, Cleco Power has concluded that none of its long-lived assets are impaired.

• The LPSC determines the amount and type of fuel and purchased power expenses 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. Cleco Power has FAC filings for January 2018 and thereafter that are subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. For more information on LPSC fuel audits, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits.” For information on fuel revenue, see “— Results of Operations — Comparison of the Years Ended December 31, 2019, and 2018 — Cleco Power — Significant Factors Affecting Cleco Power — Fuel Cost Recovery/Recoverable Fuel and Power Purchased” and “— Results of Operations — Comparison of the Three Months Ended March 31, 2020, and 2019 — Cleco Power — Fuel Cost Recovery/Recoverable Fuel and Purchased Power.”

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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 ability to maintain or expand its businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, including the impact of COVID-19, regulatory authorizations and policies, Cleco Holdings’ and Cleco Power’s credit ratings, cash flows from routine operations, and credit ratings of project counterparties. After assessing the current operating performance, liquidity, and credit ratings of Cleco Holdings and Cleco Power, management believes that Cleco 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 Holdings and Cleco Power at March 31, 2020:

	SENIOR UNSECURED DEBT			CORPORATE/LONG-TERM ISSUER
	S&P	MOODY’S	FITCH	S&P	MOODY’S	FITCH
Cleco Holdings	BBB-	Baa3	BBB-	BBB-	Baa3	BBB-
Cleco Power	BBB+	A3	BBB+	BBB+	A3	BBB

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.

Cleco Holdings and Cleco Power pay fees and interest under their bank credit agreements based on the highest rating held. Savings are dependent upon the level of borrowings. If Cleco Holdings’ or Cleco Power’s credit ratings were to be downgraded, Cleco Holdings or Cleco Power, respectively, could be required to pay additional fees and incur higher interest rates for borrowings under their respective credit facilities.

With respect to any open trading contracts that Cleco has or 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 contract, changes in the market price, changes in open contracts, 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.

Cleco Power and Cleco Cajun participate in the MISO market. MISO requires Cleco Power and Cleco Cajun to provide credit support which may increase or decrease due to the timing of the settlement schedules. For more information about MISO, see “— Regulatory and Other Matters — Transmission Rates.” For more information about credit support, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees.”

Global and United States Economic Environment

Global and domestic economic conditions 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. During periods of capital market volatility, the availability of capital could be limited and the costs of capital may increase for many companies. Although Cleco has not experienced restrictions in the financial markets, their ability to access the capital markets may be restricted at a time when Cleco would like, or need, to do so. Any restrictions could have a material impact on Cleco’s 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 Cleco’s lenders or customers, causing them to fail to meet their obligations to Cleco or to delay payment of such obligations. The lower interest rates to which Cleco has been exposed have been beneficial to debt issuances; however, these rates have negatively affected interest income for Cleco’s short-term investments.

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TCJA

The provisions of the TCJA reduced the top federal statutory corporate income tax rate from 35% to 21%. As a result of the tax rate reduction, on January 1, 2018, Cleco Power began accruing an estimated reduction in reserve for the federal statutory corporate income tax rate. In February 2018, the LPSC directed utilities, including Cleco Power, to provide considerations of the appropriate manner to flowthrough to ratepayers the benefits of the reduction in corporate income taxes as a result of the TCJA. After various filings and settlement discussions, on July 10, 2019, the LPSC approved for Cleco Power to accrue rate refunds totaling $79.2 million, plus interest, for the reduction in the statutory federal tax rate for the period from January 2018 to June 2020. The refund is being credited to customers over 12 months beginning August 1, 2019. At March 31, 2020, Cleco Power had $19.7 million accrued for the estimated tax-related benefits from the TCJA and $1.6 million accrued for the related interest.

Also, on July 10, 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT resulting from the enactment of the TCJA in Cleco Power’s application for its next FRP, which was filed on June 28, 2019, with anticipated new rates being effective July 1, 2020. At March 31, 2020, Cleco Power had a regulatory liability of $375.0 million for the portion of the net reduction to ADIT subject to regulatory treatment. Due to the uncertainty around the regulatory treatment, the entire regulatory liability is reflected in non-current liabilities.

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. Other financial assets and liabilities are reported at their carrying values at their date of issuance on the consolidated balance sheets with their fair values as of the balance sheet date disclosed within the three levels. For more information about fair value levels, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 8 — Fair Value Accounting” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 7 — 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. For more information on Cleco and Cleco Power’s restricted cash and cash equivalents, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Restricted Cash and Cash Equivalents” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies – Restricted Cash and Cash Equivalents.”

Debt

Cleco

At March 31, 2020, Cleco had $238.0 million of short-term debt outstanding under its $475.0 million credit facilities, at an average all-in interest rate of 2.11%. Cleco had no short-term debt at December 31, 2019.

At March 31, 2020, Cleco’s long-term debt and finance leases outstanding was $3.18 billion, of which $63.9 million was due within one year. The long-term debt due within one year at March 31, 2020, primarily represents $63.3 million of principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC. Long-term debt decreased by $13.5 million from December 31, 2019, primarily due to the $11.1 million final principal payment made on the Cleco Katrina/Rita storm recovery bonds on March 2, 2020. For more information on Cleco’s debt, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 8 — Debt.”

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Cash and cash equivalents available at March 31, 2020, were $350.2 million combined with $237.0 million available credit facility capacity ($87.0 million from Cleco Holdings and $150.0 million from Cleco Power) for total liquidity of $587.2 million. For more information on the credit facility capacity, see “— Credit Facilities.” Cleco Holdings and Cleco Power have uncommitted lines of credit that allow up to $10.0 million each in short-term borrowings, but no more than $10.0 million in the aggregate, to support their working capital needs.

At March 31, 2020, 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 “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 8 — Fair Value Accounting” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 7 — Fair Value Accounting.”

At March 31, 2020, and December 31, 2019, Cleco had a working capital surplus of $184.1 million and $126.7 million, respectively. The $57.4 million increase in working capital is primarily due to:

• a $233.9 million increase in cash and cash equivalents, primarily due to the draws on Cleco’s credit facilities,

• a $62.1 million decrease in long-term debt due within one year primarily due to the long-term refinancing of $50.0 million 2008 series A GO Zone bonds and the $11.1 million final principal payment on the Cleco Katrina/Rita storm recovery bonds on March 2, 2020,

• a $50.6 million decrease in accounts payable, excluding FTR purchases, primarily due to the short-term incentive plan payments in March 2020, the timing of property tax payments, lower accruals for fuel costs, and lower MISO power purchases and load charges, and

• a $26.2 million increase in fuel inventory primarily due to higher purchases of coal and higher deliveries of lignite at Cleco Power.

These increases in working capital were partially offset by:

• a $238.0 million increase in short-term debt due to draws on Cleco’s $475.0 million credit facilities,

• a $22.7 million increase in accrued interest primarily due to the timing of interest payments on long-term debt,

• a $15.0 million increase in taxes payable primarily due to accruals of property taxes and higher provisions for income taxes,

• an $11.8 million decrease in customer accounts receivable primarily due to a decrease in customer usage, a decrease in fuel surcharges, the timing of customer collections, and the absence of the Cleco Katrina/Rita storm restoration surcharge,

• a $10.7 million decrease in cash surrender value of life insurance policies primarily due to market changes,

• a $7.0 million decrease in restricted cash and cash equivalents, and

• a $6.9 million decrease in accumulated deferred fuel, excluding Cleco Power FTRs, primarily due to the timing of collections.

Cleco had no short-term debt outstanding at December 31, 2019, or 2018.

At December 31, 2019, Cleco’s long-term debt and finance leases outstanding was $3.19 billion, of which $126.0 million was due within one year. The long-term debt due within one year at December 31, 2019, primarily represents $63.3 million of principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC, $50.0 million of GO Zone bonds with a mandatory tender in May 2020, and $11.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds. Long-term debt increased by $295.1 million from December 31, 2018, primarily due to the private placement of $300.0 million aggregate principal amount of senior notes on September 11, 2019, and $30.0 million balance remaining on the $100.0 million bank term loan entered into on February 4, 2019, in connection with the Cleco Cajun Transaction.

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These increases were partially offset by $20.6 million for scheduled payments made on the Cleco Katrina/Rita storm recovery bonds. For more information on Cleco’s debt, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt.”

Cash and cash equivalents available at December 31, 2019, were $116.3 million combined with $475.0 million available credit facility capacity ($175.0 million from Cleco Holdings and $300.0 million from Cleco Power) for total liquidity of $591.3 million. For more information on the credit facility capacity, see “— Credit Facilities.” Cleco Holdings and Cleco Power have uncommitted lines of credit that allow up to $10.0 million each in short-term borrowings, but no more than $10.0 million in the aggregate, to support their working capital needs.

At December 31, 2019, 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 “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 8 — Fair Value Accounting.”

At December 31, 2019, and 2018, Cleco had a working capital surplus of $126.7 million and $185.9 million, respectively. The $59.2 million decrease in working capital is primarily due to:

• a $104.9 million increase in long-term debt due within one year primarily due to $63.3 million of principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC, $50.0 million of GO Zone bonds with a mandatory tender in May 2020, partially offset by $9.5 million of lower principal payments for the Cleco Katrina/Rita storm recovery bonds due to the bonds maturing in March 2020,

• a $33.8 million increase in affiliate accounts payable primarily for amounts due to Cleco Group for affiliate settlement of taxes payable,

• a $14.1 million increase in other current liabilities primarily due to additional liabilities incurred as a result of the Cleco Cajun Transaction,

• a $10.0 million decrease in accumulated deferred fuel, excluding FTRs, primarily due to the timing of collections at Cleco Power, partially offset by additional deferrals through a fuel surcharge at Cleco Power, and

• a $6.6 million increase in accounts payable, excluding Cleco Power FTR purchases, primarily due to higher accruals related to the Cleco Cajun Transaction, partially offset by lower accruals of operating and maintenance expenses and lower capital expenditures as a result of several Cleco Power capital projects being placed in service in 2019.

These decreases in working capital were partially offset by:

• a $34.7 million decrease in taxes payable primarily due to lower provisions for income taxes and lower corporate franchise taxes,

• a $33.5 million increase in customer accounts receivable primarily due to the addition of Cleco Cajun receivables, partially offset by credits to Cleco Power’s customers related to the TCJA,

• a $26.2 million increase in material and supplies inventory primarily due to the addition of inventory at Cleco Cajun,

• a $11.4 million increase in other current assets primarily due to an indemnification asset at Cleco Cajun as a result of a contingent liability assumed with the Cleco Cajun Transaction,

• an $8.5 million increase in other accounts receivable primarily due to the addition of Cleco Cajun receivables, and

• a $6.1 million increase in cash and cash equivalents.

At December 31, 2019, Cleco’s Consolidated Balance Sheets reflected $4.83 billion of total liabilities compared to $4.31 billion at December 31, 2018. The $521.2 million increase in total liabilities during 2019 was primarily due to:

• an increase in total long-term debt of $295.1 million, as previously discussed,

• an increase in deferred lease revenue of $49.9 million as a result of the Cleco Cajun Transaction,

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• an increase in accumulated deferred federal and state income taxes, net of $49.0 million,

• an increase in postretirement benefit obligations of $34.2 million primarily due to lower discount rates, partially offset by a greater return on the fair value of plan assets and a contribution to the plan during 2019,

• an increase of $33.8 million in affiliate accounts payable primarily for amounts due to Cleco Group for affiliate settlement of taxes payable,

• an increase in intangible liabilities of $31.9 million as a result of the Cleco Cajun Transaction, and

• an operating lease liability of $25.8 million as a result of the implementation of new accounting guidance effective January 1, 2019.

These increases in total liabilities were partially offset by a decrease in taxes payable of $34.7 million primarily as a result of lower accruals of federal and state income taxes.

In connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings issued $300.0 million under a new bridge loan agreement and $100.0 million under a new term loan agreement. Both loan agreements are variable rate debt and have a three-year term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings to maintain (i) a debt to capital ratio (as defined in the applicable agreement) below 65% and (ii) a rating applicable to Cleco’s senior debt rating (as defined in the applicable agreement). On September 11, 2019, Cleco Holdings completed the private placement of $300.0 million aggregate principal amount of its 3.375% senior notes due September 15, 2029. The proceeds from the issuance were used to repay the remaining amounts due under the $300.0 million bridge loan agreement and to repay a portion of the $100.0 million term loan agreement. The senior notes are governed by an indenture entered into between Cleco Holdings and a trustee. The indenture contains certain covenants that restrict Cleco Holdings’ ability to merge, consolidate, transfer, or lease all or substantially all of its assets or create or incur certain liens.

Cleco Holdings (Holding Company Level)

At March 31, 2020, Cleco Holdings had $88.0 million of short-term debt outstanding under its $175.0 million credit facility, at an all-in interest rate of 2.50%. For more information on Cleco Holding’s credit facility, see “— Credit Facilities.” Cleco Holdings has an uncommitted line of credit that allows up to $10.0 million in short-term borrowings, but no more than $10.0 million in the aggregate with Cleco Power’s similar line of credit, to support its working capital needs. There were no amounts outstanding under the uncommitted line of credit at March 31, 2020. Cleco Holdings had no short-term debt outstanding at December 31, 2019.

At March 31, 2020, Cleco Holding’s long-term debt outstanding was $1.67 billion, of which $63.3 million was due within one year. The long-term debt due within one year at March 31, 2020, represents principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC.

Cash and cash equivalents available at Cleco Holdings at March 31, 2020, were $93.5 million, combined with $87.0 million credit facility capacity for total liquidity of $180.5 million.

Cleco Holdings had no short-term debt outstanding at December 31, 2019, or 2018.

At December 31, 2019, Cleco Holding’s long-term debt outstanding was $1.67 billion, $63.3 million of which was due within one year. The long-term debt due within one year at December 31, 2019, represents principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC. For Cleco Holdings, long-term debt increased $326.3 million primarily due to the private placement of $300.0 million aggregate principal amount of senior notes on September 11, 2019, and $30.0 million balance remaining on the $100.0 million bank term loan entered into on February 4, 2019, in connection with the Cleco Cajun Transaction.

At December 31, 2019, and 2018, Cleco Holdings had no borrowings outstanding under its $175.0 million credit facility. This credit facility provides for working capital and other financing needs. The credit facility includes restrictive financial covenants and expires in 2021. Cleco Holdings has an uncommitted line of credit that allows up to $10.0 million in short-term borrowings, but no more than $10.0 million in the aggregate with Cleco Power’s similar line of credit, to support its working capital needs.

Cash and cash equivalents available at Cleco Holdings at December 31, 2019, were $15.0 million, combined with $175.0 million credit facility capacity for a total liquidity of $190.0 million.

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Credit Facilities

On May 15, 2020, Cleco Holdings entered into the Cleco Holdings Amendments. Also, on May 15, 2020, Cleco Power entered into the Cleco Power Amendment. The Amendments extend the terms of each facility through June 28, 2022. The current borrowing costs under the amended Cleco Holdings revolving credit facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. Cleco Holdings’ amended $300.0 million term loan bears interest at an interest rate of LIBOR plus 1.875% and Cleco Holdings’ amended $30.0 million term loan bears interest at an interest rate of LIBOR plus 1.875%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and additional interest of 0.50% under any of the Cleco Holdings Amendments. The current borrowing costs under the amended Cleco Power revolving credit facility are equal to LIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees of 0.150%. If Cleco Power’s credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of 0.125% under the Cleco Power Amendment. The Amendments also include customary LIBOR-transition provisions.

At March 31, 2020, Cleco had two separate revolving credit facilities, one for Cleco Holdings in the amount of $175.0 million with outstanding borrowings of $88.0 million and one for Cleco Power in the amount of $300.0 million with outstanding borrowings of $150.0 million. The total of all revolving credit facilities creates a maximum aggregate capacity of $475.0 million with outstanding borrowings of $238.0 million.

In connection with the Cleco Cajun Transaction, on February 4, 2019, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total credit facility of $175.0 million. Cleco Holdings’ $175 million credit facility provides for working capital and other financing needs. The credit facility includes restrictive financial covenants and expires in 2022. Under covenants contained in Cleco Holdings’ credit facility, Cleco is required to maintain total indebtedness less than or equal to 65% of total capitalization. At March 31, 2020, Cleco Holdings was in compliance with the covenants of its credit facility. The borrowing costs under the facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and additional interest of 0.50% under the pricing levels of its credit facility.

Cleco Power’s $300.0 million credit facility provides for working capital and other financing needs. The credit facility includes restrictive financial covenants and expires in 2022. Under covenants contained in Cleco Power’s credit facility, Cleco Power is required to maintain total indebtedness less than or equal to 65% of total capitalization. At March 31, 2020, Cleco Power was in compliance with the covenants of its credit facility. The borrowing costs under the facility are equal to LIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees of 0.150%. If Cleco Power’s credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of 0.125% under the pricing levels of its credit facility.

If Cleco Holdings or Cleco Power were to default under the covenants in their respective credit facilities or other debt agreements, they would be unable to borrow additional funds under the facilities 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 Holdings would be considered in default under its credit facility.

Debt and Distribution Limitations

The 2016 Merger Commitments include provisions for limiting the amount of distributions that can be made from Cleco Holdings to Cleco Group, depending on Cleco Holdings’ debt to EBITDA ratio and its corporate credit ratings. Cleco Holdings may not make any distribution unless, after giving effect to such distribution, Cleco Holdings’ debt to EBITDA ratio is equal to or less than 6.50 to 1.00 and Cleco Holdings’ corporate credit rating is investment grade with one or more of the three credit rating agencies. At March 31, 2020, Cleco Holdings was in compliance with the provisions of the 2016 Merger Commitments that would restrict the amount of distributions available. Additionally, in accordance with the 2016 Merger Commitments, Cleco Power is subject to certain provisions limiting the amount of distributions that may be paid to Cleco Holdings, depending on Cleco Power’s common equity ratio and its corporate credit ratings. Cleco Power may not make any distribution unless, after giving effect to such distribution, Cleco Power’s common equity ratio would not be less than 48% and Cleco Power’s corporate credit rating is investment grade with two of the three credit rating agencies. At March 31, 2020, Cleco Power was in compliance with the provisions of the 2016 Merger Commitments that would restrict the amount of distributions available. The 2016 Merger Commitments also

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prohibit Cleco from incurring additional long-term debt, excluding non-recourse debt, unless certain financial ratios are achieved. For more information on the 2016 Merger Commitments, see “Risk Factors — Structural Risks — Holding Company” and “— Regulatory Risks — Regulatory Compliance.”

Cleco Cash Flows

Net Operating Cash Flow

Internally generated cash from operating activities consists of net income, adjusted for non-cash expenses, non-cash income, and changes in operating assets and liabilities. Non-cash items include depreciation and amortization, deferred fuel costs, deferred income taxes, and allowance for equity funds used during construction. Cash provided by operating activities for Cleco may vary year to year primarily as a result of the cash provided by operating activities at Cleco Power and Cleco Cajun. Changes in Cleco Power’s cash provided by operating activities are discussed below. Cleco Cajun’s cash provided by operating activities may vary year to year primarily as a result of changes in wholesale contracts, cost of fuel and purchased power, and costs for generation station operations and maintenance.

Net cash provided by operating activities was $60.2 million and $108.1 million during the three months ended March 31, 2020, and 2019, respectively. Net cash provided by operating activities decreased $47.9 million primarily due to:

• higher payments for fuel purchases of $24.8 million primarily due to higher purchases of petroleum coke and coal,

• higher payout for employee benefits of $7.1 million,

• lower net fuel and purchased power collections of $6.2 million primarily due to timing of collections at Cleco Power,

• higher payments of $6.1 million primarily due to timing of vendor payments, and

• higher interest payments of $3.3 million.

These decreases were partially offset by:

• higher receipts for other accounts receivable of $8.5 million, including the timing of receipts of joint owners’ portion of generating station expenditures and

• higher collections from Cleco Cajun customers of $6.0 million.

Net cash provided by operating activities was $430.1 million and $317.8 million for the years ended December 31, 2019, and 2018, respectively. Net cash provided by operating activities during 2019 increased $112.3 million from 2018 primarily due to:

• $124.0 million for the addition of Cleco Cajun operations, including receipts of $37.7 million as a result of the Cottonwood Sale Leaseback,

• higher net fuel and purchased power collections at Cleco Power of $29.7 million primarily due to the timing of collections, and

• lower payments for fuel purchases of $18.6 million primarily due to lower purchases of petroleum coke at Cleco Power.

These increases were partially offset by:

• payments for pension plan contributions of $12.3 million at Cleco Power,

• lower receipts of $8.6 million, primarily due to the timing of receipts of Cleco Power’s joint owners’ portion of generating stations expenditures,

• lower Cleco Power customer deposits of $7.9 million, and

• higher interest paid on long-term debt at Cleco Holdings of $6.8 million primarily as a result of additional borrowings to finance the Cleco Cajun Transaction.

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Net cash provided by operating activities during 2018 increased $52.4 million from 2017 primarily due to:

• higher collections from customers of $25.3 million due to lower 2016 Merger credits used in 2018 and the timing of collections of accounts receivables,

• lower payments for fuel purchases of $23.6 million primarily due to lower deliveries of lignite and petroleum coke,

• lower payments for affiliate settlements of $18.1 million

• lower vendor payments of $18.0 million due to timing of property tax payments, and

• higher receipts of $8.1 million primarily due to timing of receipts of joint owners’ portion of generating station expenditures.

These increases were partially offset by:

• lower net fuel and power purchase collections of $30.4 million primarily due to timing of collections and

• higher payments for employee benefits of $8.2 million.

Net Investing Cash Flow

Net cash used in investing activities was $65.4 million and $892.7 million during the three months ended March 31, 2020, and 2019, respectively. Net cash used in investing activities decreased $827.3 million primarily due to:

• the absence of payment for the acquisition of all the membership interest in South Central Generating of $962.2 million, partially offset by the absence of cash received of $147.2 million and

• lower additions to property, plant, and equipment, net of AFUDC, of $12.3 million.

Net cash used in investing activities was $1.12 billion and $288.2 million during the years ended December 31, 2019, and 2018, respectively. Net cash used in investing activities increased $827.2 million primarily due to:

• payment for the acquisition of all the membership interest in South Central Generating of $962.2 million, partially offset by cash received of $147.2 million and

• higher additions to property, plant, and equipment, net of AFUDC, of $31.5 million.

These increases were partially offset by the absence of the issuance of a $16.8 million note receivable.

Net cash used in investing activities during 2018 increased $84.6 million from 2017 primarily due to:

• higher additions to property, plant, and equipment, net of AFUDC, of $48.3 million,

• the issuance of a $16.8 million note receivable, and

• the absence of proceeds from the sale of transmission assets of $16.7 million.

Net Financing Cash Flow

Net cash provided by financing activities was $226.8 million and $770.6 million during the three months ended March 31, 2020, and 2019, respectively. Net cash provided by financing activities decreased $543.8 million primarily due to:

• the absence of borrowings of $400.0 million related to the financing of the Cleco Cajun Transaction in February 2019 and

• lower contributions from Cleco Group of $384.9 million.

These decreases were partially offset by:

• higher draws on credit facilities of $130.0 million and

• lower payments on credit facilities of $108.0 million.

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Net cash provided by financing activities was $687.8 million for the year ended December 31, 2019. Net cash used in financing activities was $41.7 million for the year ended December 31, 2018. Net cash provided by financing activities during 2019 increased $729.5 million primarily due to:

• borrowings of $400.0 million related to the financing of the Cleco Cajun Transaction,

• higher contributions from Cleco Group of $384.9 million,

• the issuance of $300.0 million in senior notes at Cleco Holdings, and

• the absence of distributions to Cleco Group of $71.4 million.

These increases were partially offset by:

• higher repayments of long-term debt of $371.4 million and

• the absence of the $50.0 million issuance of senior notes in March 2018 at Cleco Power.

Net cash used in financing activities during 2018 increased $62.5 million from 2017 primarily due to lower issuances of senior notes of $75.0 million, partially offset by lower distributions to Cleco Group of $12.7 million.

Capital Expenditures

Cleco’s capital expenditures are primarily incurred at Cleco Power and Cleco Cajun. Cleco Power’s 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 FRP. Such assets primarily consist of improvements to Cleco Power’s distribution system, transmission system, and generating stations as well as hardware and software upgrades. Cleco Cajun’s capital expenditures primarily consist of improvements to Cleco Cajun’s transmission system and generating stations as well as hardware and software upgrades.

During the years ended December 31, 2019, 2018, and 2017, Cleco Power had capital expenditures, excluding AFUDC, of $298.6 million, $275.0 million, $226.9 million, respectively. In 2019, 2018, and 2017, 100% of Cleco Power’s capital expenditure requirements were funded internally.

During the years ended December 31, 2019, 2018, and 2017, other subsidiaries had capital expenditures of $9.8 million, $1.9 million, and $1.7 million, respectively. The higher capital expenditures in 2019 was primarily due to the addition of Cleco Cajun’s capital expenditures.

In 2020 and for the five-year period ending 2024, Cleco and Cleco Power expect to materially fund its capital expenditure requirements with internally generated funds. However, Cleco Power may choose to issue debt in order to achieve its stipulated regulatory capital structure. All computations of internally funded capital expenditures exclude AFUDC and capitalized interest.

Cleco and Cleco Power’s estimated capital expenditures and debt maturities for 2020 and for the five-year period ending December 31, 2024 are presented in the following tables. All amounts exclude AFUDC and capitalized interest.

Cleco
PROJECT (THOUSANDS)	2020	%	2020-2024	%
Environmental	$—	—%	$71,000	5%
New business	50,000	17%	169,000	11%
Transmission reliability	67,000	22%	222,000	15%
Fuel optimization	—	—%	265,000	18%
General(1)	182,000	61%	764,000	51%
Total capital expenditures	$299,000	100%	$1,491,000	100%
Debt payments	11,000		681,000
Total capital expenditures and debt payments	$310,000		$2,172,000

(1)
Primarily consists of rehabilitation projects of older transmission, distribution, and generation assets and hardware and software upgrades at Cleco Power.

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Cleco Power
PROJECT (THOUSANDS)	2020	%	2020-2024	%
Environmental	$—	—%	$45,000	3%
New business	50,000	18%	169,000	13%
Transmission reliability	67,000	25%	222,000	16%
Fuel optimization	—	—%	265,000	19%
General(1)	156,000	57%	672,000	49%
Total capital expenditures	$273,000	100%	$1,373,000	100%
Debt payments	11,000		186,000
Total capital expenditures and debt payments	$284,000		$1,559,000

(1)
Primarily consists of rehabilitation projects of older transmission, distribution, and generation assets and hardware and software upgrades.

Capital expenditures for other subsidiaries, including Cleco Cajun, in 2020 are estimated to total $26.0 million. For the five-year period ending December 31, 2024, capital expenditures for other subsidiaries, including Cleco Cajun, are estimated to total $118.0 million. Cleco expects cash and cash equivalents on hand in addition to cash generated from operations, borrowings from credit facilities, and the net proceeds of any issuances of debt securities to be adequate to fund normal ongoing capital expenditures, working capital, and debt service requirements for the foreseeable future.

Other Cash Requirements

Cleco Power’s regulated operations and Cleco Cajun unregulated operations are Cleco’s primary sources of internally generated funds. These funds, along with the issuance of additional debt in future years, will be used for general company purposes, capital expenditures, and debt service.

Contractual Obligations

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, 2019, and represent only the projected future payments that Cleco was contractually obligated to make as of December 31, 2019.

					PAYMENTS DUE BY PERIOD
CONTRACTUAL OBLIGATIONS (THOUSANDS)	TOTAL	LESS THAN ONE YEAR	1-3 YEARS	3-5 YEARS	MORE THAN 5 YEARS
Cleco
Long-term debt(1)	$4,781,024	$141,829	$598,210	$542,643	$3,498,342
Finance lease(2)	34,099	2,612	5,222	5,222	21,043
Operating lease(3)	36,814	4,982	6,730	6,484	18,618
Purchase(4)	209,360	120,978	55,296	18,612	14,474
Other long-term liabilities(5)	18,935	5,738	6,148	5,249	1,800
Postretirement benefits(6)	272,906	9,146	42,517	56,051	165,192
Total Cleco	$5,353,138	$285,285	$714,123	$634,261	$3,719,469
Cleco Power
Long-term debt(1)	$2,354,387	$77,634	$156,857	$277,169	$1,842,727
Finance lease(2)	34,099	2,612	5,222	5,222	21,043
Operating lease(3)	35,679	3,960	6,665	6,436	18,618
Purchase(4)	127,021	50,431	47,857	15,491	13,242
Other long-term liabilities(5)	10,800	1,800	3,600	3,600	1,800
Postretirement benefits(6)	61,800	—	24,100	37,700	—
Total Cleco Power	$2,623,786	$136,437	$244,301	$345,618	$1,897,430

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(1)
For more information regarding individual long-term debt maturities, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 8 — Debt.” For Cleco, the amount above excludes the fair value adjustments related to the 2016 Merger. For Cleco and Cleco Power, the Series A GO Zone bonds with a maturity date of December 2038 but a mandatory tender of May 2020 are included in the column representative of the maturity date. Cleco’s anticipated interest payments related to long-term debt also are included in this category and do not reflect anticipated future refinancing, early redemptions, or debt issuances.

(2)
Finance leases are maintained in the ordinary course of Cleco’s business activities, including leases for barges. Cleco’s anticipated interest payments and operating fees related to finance lease obligations are also included in this category. For more information regarding these leases, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases — Finance Lease.”

(3)
Operating leases are maintained in the ordinary course of Cleco’s business activities. These leases include utility systems, railcars, towboats, office space, operating facilities, and office equipment and have various terms and expiration dates from 1 to 27 years. For more information regarding Cleco’s operating leases, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases.”

(4)
Significant purchase obligations for Cleco are:

 
Fuel Contracts: To supply a portion of the fuel requirements for Cleco’s generating plants, Cleco has entered into various commitments to obtain and deliver coal, lignite, petroleum coke, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. Generally, Cleco Power’s fuel and purchased power expenses are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to its customers substantially all such charges. For more information regarding fuel contracts, see “Business — Operations — Cleco Power — Fuel and Purchased Power” and “— Cleco Cajun — Fuel and Purchased Power.”

 
Purchase orders: Cleco has entered into purchase orders in the course of normal business activities.

(5)
Other long-term liabilities primarily consist of obligations for deferred compensation and various operating and maintenance agreements.

(6)
Postretirement benefits obligations consist of the expected required contributions for the pension plan and the estimated present value of obligations for SERP and other postretirement obligations. For more information regarding Cleco’s defined benefit pension plan, SERP, and other postretirement obligations, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 10 — Pension Plan and Employee Benefits” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 9 — Pension Plan and Employee Benefits.”

For purposes of this table, it is assumed that all terms and rates related to the above obligations will remain the same and all franchises will be renewed according to the rates used in the table.

Off-Balance Sheet Commitments and On-Balance Sheet Guarantees

Cleco Holdings 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 Holdings’ subsidiaries and equity investees (affiliates). Cleco Holdings 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. For more information about off-balance sheet commitments and on-balance sheet guarantees, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees.”

Cybersecurity

The operation of Cleco’s electrical systems relies on evolving operational and information technology systems and network infrastructures that are complex. The failure of Cleco or its vendors’ operational and information technology systems and networks due to a physical or cyberattack, or other event could significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; result in damage to Cleco’s assets or operations, or those of third parties; result in damage to Cleco’s reputation; and subject Cleco to claims by customers or third parties, any of which could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco. In addition, the Cleco Cajun Transaction could increase the risk associated with cybersecurity that could have a material adverse effect on Cleco’s results of operations, financial condition, or cash flows including phishing attacks, denial of service attacks, and employee insider attacks. Cleco continues to assess its cybersecurity tools and processes and has taken a variety of actions to monitor and address cyber-related risks. Cleco’s Chief Digital and Information Officer leads Cleco’s cybersecurity team and oversees Cleco’s cybersecurity maturity plan. Each quarter, management provides cybersecurity updates to Cleco’s Board of Managers. For more information on risks related to Cleco’s cybersecurity, see “Risk Factors — Operational Risks — Technology and Terrorism Threats.”

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Regulatory and Other Matters

Inflation

Annual inflation rates, as measured by the United States Consumer Price Index, have averaged 2% during the three years ended December 31, 2019. Under established regulatory practice, historical costs have traditionally formed the basis for recovery from customers. As a result, Cleco Power’s cash flows designed to provide recovery of historical plant costs may not be adequate to replace property, plant, and equipment in future years.

Environmental Matters

Cleco is subject to extensive environmental regulation by federal, state, and local authorities and is required to comply with numerous environmental laws and regulations, and to obtain and comply with numerous governmental permits, in operating its facilities. In addition, existing environmental laws, regulations, and permits could be revised or reinterpreted; new laws and regulations could be adopted or become applicable to Cleco or its facilities; and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, water and/or waste management. Cleco may incur significant additional costs to comply with these revisions, reinterpretations, and requirements. Cleco Power could then seek recovery of additional environmental compliance costs as riders through the LPSC’s EAC or FRP. If Cleco fails to comply with these revisions, reinterpretations, and requirements, it could be subject to civil or criminal liabilities and fines. For information on environmental matters, see “Business — Environmental Matters.”

Retail Rates of Cleco Power

For both 2019 and 2018, retail rates, which includes the retail portion of FAC and EAC revenue, regulated by the LPSC accounted for approximately 86% of Cleco Power’s total base, FAC, and EAC revenue.

Fuel Rates

Generally, Cleco Power’s cost of fuel used for electric generation and the cost of purchased power are recovered through the LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. Recovery of FAC costs is subject to periodic fuel audits by the LPSC. For more information on the FAC and the most recent fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit.”

Environmental Rates

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides Cleco Power an EAC to recover from customers certain costs of environmental compliance. These expenses are eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC. For more information on the EAC and the most recent environmental audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit.”

Base Rates

Cleco Power’s annual retail earnings are subject to an FRP that was approved by the LPSC in June 2014. For more information on the LPSC’s regulation of Cleco Power’s base rates, see “Business — Regulatory Matters, Industry Developments, and Franchises — Rates.”

For more information on the LPSC Staff’s FRP reviews, amounts accrued by Cleco Power as a result of the TCJA, and information on the tax dockets, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — FRP,” “— TCJA,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — FRP” and “— TCJA.”

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SSR

In September 2016, Cleco Power filed an Attachment Y with MISO requesting retirement of Teche Unit 3 effective April 1, 2017. MISO conducted a study which determined the proposed retirement of Teche Unit 3 would result in violations of specific applicable reliability standards for which no mitigation is available. As a result, MISO designated Teche Unit 3 as an SSR unit, until such time that an appropriate alternative solution can be implemented to mitigate reliability issues. Cleco Power received a termination notice, effective April 30, 2019, and filed paperwork to withdraw the filed Attachment Y. For more information on the MISO SSR designation of Teche Unit 3, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — SSR.”

Energy Efficiency

In 2013, the LPSC issued a General Order adopting rules promoting energy efficiency programs. Cleco Power began participating in energy efficiency programs in November 2014. Cleco Power has recovered approximately $3.3 million annually for each of the program years through an approved rate tariff. In January 2018, Cleco began recovering an additional $3.3 million annually for estimated costs related to programs specific to political subdivisions.

In November 2017, the LPSC initiated an audit on the first two program years to consider all program costs. On June 19, 2019, the LPSC approved the audit report and concluded the costs were reasonable and prudent, and eligible for recovery consistent with the energy efficiency rules. On December 17, 2019, the LPSC initiated an audit on program years three and four to consider all program costs. Cleco Power has responded to several sets of data requests regarding the audit. Management is unable to predict or give a reasonable estimate of the outcome of the audit.

Generally utility companies are allowed to recover from customers the accumulated decrease in revenues associated with the energy efficiency programs. In December 2018, Cleco Power filed a letter of intent with the LPSC to recover certain accumulated decrease in revenues, also known as LCFC. On October 21, 2019, Cleco Power received notice of approval from the LPSC allowing recovery of the accumulated LCFC revenues until such a time that base rates reset, which is expected in July 2020.

MISO Cost Benefit Analysis

Cleco Power entered into MISO in 2013. Within five years of joining MISO, the LPSC required Cleco Power to conduct a study of the costs and benefits of its membership in MISO. During the second quarter of 2017, Cleco Power submitted an analysis with both a backward-looking, historical analysis and a forward-looking, prospective analysis of the costs and benefits of operating in MISO, as compared to a scenario where Cleco Power and Entergy Louisiana exit MISO and operate independently. Cleco Power’s analysis indicated that continued MISO membership would best serve the public interest. Cleco Power has responded to several sets of data requests on the analysis. Management is unable to predict the outcome of this analysis or give a reasonable estimate of the possible range of disallowance of costs, if any.

Wholesale Rates

The rates Cleco, through Cleco Power and Cleco Cajun, charges its wholesale customers are subject to FERC’s triennial market power analysis. FERC requires 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 must be filed with FERC every three years or upon the occurrence of a change in status as defined by FERC regulation. Cleco’s next triennial market power analysis is expected to be filed during the fourth quarter of 2020.

Transmission Rates

In July 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. In 2015, MISO and the Southwest Power Pool made separate filings containing different metrics to meet specific

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requirements. A compliance determination for both filings has not been made and no timetable is available for when a determination will be made. Until a determination is made, Cleco is unable to determine if this order will have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco Power and Cleco Cajun’s generation dispatch and transmission operations are integrated with 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. Both use market-based mechanisms to manage transmission congestion across the MISO market area. For more information about the risks associated with Cleco’s participation in MISO, see “Risk Factors — Regulatory Risks — MISO.”

Cleco Power and Cleco Cajun earn transmission revenues pursuant to MISO’s FERC filed tariff. The performance obligation of transmission service is satisfied as service is provided. Revenue is recognized upon delivery of the transmission service. For Cleco Power, revenue from the transmission of electricity is recorded based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of revenue requirements with rates effective June 1 of each year. For Cleco Cajun, revenue from the transmission of electricity is recorded based on a FERC-approved annual filing rate mechanism effective June 1 of each year. Cleco Cajun charges transmission rates based on its cost to provide transmission services.

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. For more information about the ROE complaints, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE.”

Transmission, Distribution, and Generation Projects

Cleco Power’s significant ongoing projects include the Bayou Vista to Segura Transmission project and the DSMART distribution project. For information on these projects, see “— Overview — Cleco Power.”

Market Restructuring

Wholesale Electric Markets

RTO

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. Cleco Power and Cleco Cajun’s generation dispatch and transmission operations are integrated with MISO. For more information about Cleco Power and Cleco Cajun’s integration into MISO, see “— Transmission Rates.”

ERO

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.

A NERC Reliability Standards audit is conducted every three years for Cleco Power and Cleco Cajun. On October 17, 2019, Cleco Power’s NERC Reliability Standards audit was completed. The final report was issued on October 31, 2019. Cleco Power is unable to determine the timing of NERC’s approval of the audit report due to the impact of the COVID-19 pandemic. The Cleco Cajun NERC Reliability Standards audit occurred during April 2019. There were no violations or areas of concern discovered during the Cleco Cajun audit.

A NERC CIP audit is also conducted every three years. Cleco Power’s next NERC CIP audit has been delayed due to the impact of the COVID-19 pandemic; however, it is expected to be complete by the end of the third quarter of 2020. Cleco Cajun’s CIP audit occurred during June 2019. The preliminary findings have been received by Cleco Cajun.

Management is unable to predict the final financial outcome of the current Cleco Power NERC Reliability Standards audit, the current Cleco Cajun CIP audit, or any future audits, or whether any findings will have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco. For a discussion

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of risks associated with FERC’s regulation of Cleco Power’s transmission system, see “Risk Factors — Regulatory Risks — Reliability and CIP 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 LPSC’s review of the “300-foot rule” in Docket No. R-32763 has been ongoing since April 2013. On February 5, 2020, the docket was closed due to no substantive actions in the proceedings since October 2014. Management is unable to predict if this docket will be reopened for reconsideration in the future and cannot determine the impact any potential rulemaking may have on the results of operations, financial condition, or 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. 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.

IRP

In accordance with the General Order in LPSC Docket No. R-30021, in October 2017, Cleco Power filed a request with the LPSC to initiate an IRP process. In February 2018, Cleco Power filed the data assumptions to be used in its IRP analysis. The IRP process includes conducting stakeholder meetings and receiving feedback from stakeholders. LPSC acknowledgment of a completed IRP process was received with no objections or discussions on January 22, 2020.

The IRP report describes how Cleco Power plans to meet its forecasted load requirements on a reliable and economic basis. The IRP is used as a guide in future decision-making and does not represent firm operational commitments. LPSC acknowledgment of a completed IRP process does not represent approval of any actions stated in the IRP report.

Service Quality Plan (“SQP”)

In October 2015, the LPSC proposed an SQP containing 21 requirements for Cleco Power. The SQP has provisions relating to employee headcount, customer service, reliability, vegetation management, and reporting. In April 2016, the SQP was approved by the LPSC. The SQP will remain in effect until 2021. Prior to the expiration of the SQP, a new five-year program must be negotiated and submitted to the LPSC for approval. Cleco Power filed its annual SQP monitoring report on April 1, 2019.

Franchises

Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state law. These franchises are for fixed terms, which vary from 10 years to more than 50 years. 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 April 2022. For more information on franchises, see “Business — Regulatory Matters, Industry Developments, and Franchises — Franchises.”

Recent Authoritative Guidance

For a discussion of recent authoritative guidance, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Recent Authoritative Guidance” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 3 — Recent Authoritative Guidance.”

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BUSINESS

GENERAL

Cleco Holdings is a public utility holding company that holds investments in several subsidiaries, including Cleco Power and Cleco Cajun. Prior to the Cleco Cajun Transaction, substantially all of Cleco Holdings’ operations were conducted through Cleco Power. Cleco Holdings, 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 Holdings’ predecessor was incorporated on October 30, 1998, under the laws of the state of Louisiana. On April 13, 2016, Cleco Holdings completed its merger with Merger Sub whereby Merger Sub merged with and into Cleco Corporation, with Cleco Corporation surviving the 2016 Merger, and Cleco Corporation converting to a limited liability company and changing its name to Cleco Holdings, as a direct, wholly owned subsidiary of Cleco Group and an indirect, wholly owned subsidiary of Cleco Partners.

Cleco Power is a regulated electric utility engaged principally in the generation, transmission, distribution, and sale of electricity within Louisiana. Cleco Power owns ten generating units with a total nameplate capacity of 3,360 MW and serves approximately 288,000 customers in Louisiana through its retail business. Additionally, Cleco Power supplies wholesale power in Louisiana and Mississippi. Cleco Power was organized as a limited liability company under the laws of the state of Louisiana on December 12, 2000. Cleco Power’s predecessor was incorporated on January 2, 1935, under the laws of the state of Louisiana.

Cleco Cajun, organized on December 28, 2017, under the laws of the state of Louisiana, is an unregulated electric utility that owns eight generating assets with a rated capacity of 3,555 MW and supplies wholesale power and capacity in Arkansas, Louisiana, and Texas. On February 4, 2019, the Cleco Cajun Transaction was completed. For more information on the Cleco Cajun Transaction, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations.”

At March 31, 2020, Cleco had 1,484 employees. Cleco’s mailing address is P.O. Box 5000, Pineville, Louisiana 71361-5000, and its telephone number is (318) 484-7400. Cleco’s website is located at https://www.cleco.com. Cleco 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 electronically filed reports can also be obtained on the SEC’s website located at https://www.sec.gov. Cleco’s governance guidelines, code of conduct for financial managers, ethics and business standards, and the charters of its boards of managers’ audit, leadership development and compensation, business planning and budget review, governance and public affairs, and asset management committees are available on its website and available in print upon request. Information on Cleco’s website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

OPERATIONS

Cleco Power

Certain Factors Affecting Cleco Power

As an electric utility, Cleco Power is affected by a number of factors influencing the electric utility industry in general. For more information on these factors, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Comparison of the Years Ended December 31, 2019, and 2018 — Cleco Power — Significant Factors Affecting Cleco Power” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Comparison of the Three Months Ended March 31, 2020, and 2019 — Cleco Power.”

Power Generation

As of March 31, 2020, Cleco Power’s aggregate net electric generating capacity was 3,214 MW. This amount reflects the maximum production capacity these units can sustain over a specified period of time. On March 1, 2019, Cleco Power began to operate Dolet Hills Power Station from June through September of each year; however, Dolet Hills Power Station will continue to be available to operate in other months, if needed. In January 2020, Cleco Power’s joint

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owner in Dolet Hills Power Station unilaterally entered into a settlement with the Arkansas Public Service Commission to seek regulatory approval to retire the Dolet Hills Power Station by 2026. This settlement does not bind Cleco Power to agree to retire the Dolet Hills Power Station by the end of 2026.

In April 2020, Cleco Power and SWEPCO mutually agreed to not develop additional mining areas for future lignite extraction and subsequently provided notice to the LPSC of the intent to cease mining at the Dolet Hills and Oxbow mines by June 2020, subject to LPSC review and approval. Early closure of the mines would most likely result in increased costs billed through fuel, which management currently believes are recoverable. Management does not believe an early closure of the mines would have an adverse impact on the recovery value of the plant. Cleco Power has the ability to secure alternative fuel sources and expects to have sufficient lignite fuel available to continue seasonal operations of the Dolet Hills Power Station through at least the 2020 and 2021 seasonal operations periods. Also in April 2020, Cleco Power announced its intent to seek regulatory approval to retire the Dolet Hills Power Station at the end of 2021, subject to recovery mechanisms. This does not bind Cleco Power to a specific retirement plan and Cleco Power will continue to evaluate the cost of operating the Dolet Hills Power Station compared with other alternatives and decide the best course of action for the Dolet Hills Power Station within the LPSC regulatory requirements and recovery mechanisms.

In August 2019, the St. Mary Clean Energy Center was placed into service. The St. Mary Clean Energy Center is a 47 net MW generating unit that is fueled by waste heat from Cabot Corporation’s carbon black manufacturing plant in Franklin, Louisiana. The unit is expected to generate more than 300,000 MWh of zero additional carbon emitting energy each year.

The following table sets forth certain information with respect to Cleco Power’s generating facilities as of March 31, 2020:

GENERATING STATION	YEAR OF INITIAL OPERATION	NAMEPLATE CAPACITY (MW)(1)	NET CAPACITY (MW)(2)	PRIMARY FUEL USED FOR GENERATION	GENERATION TYPE
Brame Energy Center
Nesbitt Unit 1	1975	440	424	natural gas	steam
Rodemacher Unit 2	1982	157(3)	148(3)	coal	steam
Madison Unit 3	2010	641	625	petroleum coke/coal	steam
Acadia Unit 1	2002	580	548	natural gas	combined cycle
Coughlin Unit 6	2000	264	252	natural gas	combined cycle
Coughlin Unit 7	2000	511	486	natural gas	combined cycle
Teche Unit 3	1971	359	327	natural gas	steam
Teche Unit 4	2011	33	34	natural gas	combustion
Dolet Hills Power Station	1986	325(4)	323(4)	lignite	steam
St. Mary Clean Energy Center	2019	50	47	waste heat	steam
Total generating capability		3,360	3,214

(1)
Nameplate capacity is the capacity at the start of commercial operations.

(2)
Based on capacity testing of the generating units and operational tests performed between April and August 2019. These amounts do not represent generating unit capacity for MISO planning reserve margins.

(3)
Represents Cleco Power’s 30% ownership interest in the capacity of Rodemacher Unit 2, a 523-MW generating unit.

(4)
Represents Cleco Power’s 50% ownership interest in the capacity of Dolet Hills Power Station, a 650-MW generating unit.

The following table sets forth the amounts of power generated by Cleco Power for the years indicated:

YEAR	THOUSAND MWh	PERCENT OF TOTAL ENERGY REQUIREMENTS
2019	12,552	103.0%
2018	11,848	94.6%
2017	10,864	91.1%
2016	12,759	103.6%
2015	12,564	100.2%

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Cleco Power’s generation dispatch and transmission operations are integrated with MISO. The amount of power generated by Cleco Power is dictated by the availability of Cleco Power’s generating fleet and the manner in which MISO dispatches each generating unit. Depending on how generating units are dispatched by MISO, the amount of power generated may be greater than or less than total energy requirements. Generating units are dispatched by referencing each unit’s economic efficiency as it relates to the overall MISO market. For more information on MISO, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Transmission Rates.”

Fuel and Purchased Power

Changes in fuel expenses reflect fluctuations in the amount, type, and pricing of fuel used for electric generation; fuel transportation and delivery costs; and deferral of expenses for recovery from customers through Cleco Power’s FAC in subsequent months. Changes in purchased power expenses are a result of the quantity and price of economic power purchased from the MISO market. These quantity changes can be affected by Cleco plant outages and plant performance. For a discussion of certain risks associated with changes in fuel costs and their impact on utility customers, see “Risk Factors — Operational Risks — Transmission Constraints” and “— Regulatory Risks — LPSC Audits.”

The following table sets forth the percentages of power generated from various fuels at Cleco Power’s electric generating plants, the cost of fuel used per MWh attributable to each such fuel, and the weighted average fuel cost per MWh:

		LIGNITE		COAL	NATURAL GAS		PETROLEUM COKE		RENEWABLES	WEIGHTED AVERAGE COST PER MWh
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	PERCENT OF GENERATION
2019	$119.88	4.7%	$24.60	11.3%	$21.18	69.1%	$26.54	14.2%	0.7%	$26.85
2018	$93.88	6.9%	$22.55	16.7%	$26.81	52.6%	$26.54	23.8%	—	$30.66
2017	$44.70	8.9%	$24.75	12.4%	$27.19	51.3%	$22.50	27.4%	—	$27.16
2016	$50.39	13.0%	$28.13	9.3%	$20.84	52.9%	$18.77	24.8%	—	$24.86
2015	$46.87	16.9%	$28.68	9.7%	$21.37	50.6%	$19.80	22.8%	—	$26.04

Power Purchases

Cleco Power is a participant in the MISO market. MISO makes economic and routine dispatch decisions regarding Cleco Power’s generating units. Power purchases are made at prevailing market prices, also referred to as LMP, which are highly correlated to natural gas prices. LMP includes a component directly related to congestion on the transmission system. Pricing zones with greater transmission congestion may have higher LMPs. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power’s pricing zones. 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.” For information on the cost benefit analysis of Cleco Power’s MISO membership, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Retail Rates of Cleco Power — MISO Cost Benefit Analysis.”

Coal, Petroleum Coke, and Lignite Supply

Cleco Power uses coal for generation at Rodemacher Unit 2. During 2019, Cleco Power contracted with Peabody Coal Sales, LLC to provide Cleco Power’s coal needs at Rodemacher Unit 2, utilizing short-term spot coal agreements. The coal supply agreements were fixed-price contracts. For 2020, Cleco Power intends to meet its coal needs through short-term spot coal agreements which are expected to be fixed-price contracts. For the transportation of coal, Cleco Power had an agreement with Union Pacific Railroad Company to transport coal from Wyoming’s Powder River Basin to Rodemacher Unit 2. The transportation agreement was for three years and expired on December 31, 2019. On January 1, 2020, Cleco Power renewed its agreement with Union Pacific Railroad Company to continue this transportation agreement for three additional years, expiring December 31, 2022. Cleco Power leases 115 railcars to transport its coal under a lease that expires on March 31, 2021. A lease for 85 railcars expired on March 31, 2020.

The continuous supply of coal may be subject to interruption due to adverse weather conditions or other factors that may disrupt transportation to the plant site. At March 31, 2020, Cleco Power’s coal inventory at Rodemacher Unit 2 was approximately 138,000 tons (approximately a 58-day supply).

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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, ample petroleum coke supplies are produced from refineries each year throughout the world, particularly in the Gulf Coast region. During 2019, Cleco received its petroleum coke supply from multiple refineries located along the upper and lower Mississippi River. Cleco purchased slightly more than 600,000 tons of petroleum coke during 2019, all of which were either an evergreen extension of a previous agreement or a negotiated agreement for one year ending December 31, 2019. For 2020, Cleco has contracted for 810,000 tons of petroleum coke from multiple refineries located along the upper and lower Mississippi River through one-year agreements ending December 31, 2020. The agreements are priced according to the Advisian Worley Group (formerly Jacobs Consultancy) Pace Petroleum Coke Quarterly Monthly Price Index or the “PACE” Monthly Index.

During 2019, Cleco purchased approximately 375,000 tons of Illinois Basin coal. Cleco Power uses Louisiana waterways, such as the Mississippi River and the Red River, to deliver both petroleum coke and Illinois Basin coal to the Madison Unit 3 plant site. The continuous supply of petroleum coke and Illinois Basin coal may be subject to interruption due to adverse weather conditions or other factors that may disrupt transportation to the plant site. Savage Inland Marine is Cleco Power’s exclusive transportation coordinator and provider. Cleco Power has a logistics agreement with Savage Inland Marine that is set to expire in March 2033. At March 31, 2020, Cleco Power’s petroleum coke inventory at Madison Unit 3 was approximately 333,000 tons and Cleco Power’s Illinois Basin coal inventory at Madison Unit 3 was approximately 298,000 tons. The total fuel inventory was 631,000 tons (approximately a 111-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 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, which are operated 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 to meet projected dispatch needs. For information regarding deferred mining costs and obligations associated with this mining agreement see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 6 — Regulatory Assets and Liabilities — Mining Costs,” “Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees,” “— Long-Term Purchase Obligations,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees.” For more information on Oxbow, see “Financial Statements and Supplementary Data — Notes to the Audited the Financial Statements — Note 14 — Variable Interest Entities” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 13 — Variable Interest Entities.”

The continuous supply of 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. During 2019, the cost of lignite per MWh increased primarily due to the mine continuing to incur fixed costs, despite fewer tons of lignite mined compared to prior years. At March 31, 2020, Cleco Power’s lignite inventory at Dolet Hills was approximately 415,000 tons (approximately a 66-day supply).

Natural Gas Supply

During 2019, Cleco Power purchased 46.8 million MMBtu 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:

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NATURAL GAS SUPPLIER	2019 PURCHASES (MMBtu)	AVERAGE AMOUNT PURCHASED PER DAY (MMBtu)	PERCENT OF TOTAL NATURAL GAS USED
Tenaska Marketing Ventures	15,891,247	43,538	34.0%
Mansfield Power and Gas	7,531,077	20,633	16.1%
Sequent Energy Management	4,739,467	12,985	10.1%
Shell Energy North America	4,196,533	11,497	9.0%
DTE Energy Trading, Inc.	2,289,367	6,272	4.9%
Range Resources	1,856,507	5,086	4.0%
BP Energy Company	1,666,937	4,567	3.6%
Cima Energy LP	1,636,862	4,485	3.5%
Spire Marketing, Inc.	1,625,726	4,454	3.5%
Kaiser Marketing Appalachian LLC	1,195,504	3,275	2.6%
ConocoPhillips Company	1,047,400	2,870	2.2%
NextEra Energy Resources	1,029,363	2,820	2.2%
Others	2,044,466	5,601	4.3%
Total	46,750,456	128,083	100.0%

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

Natural gas was available without interruption throughout 2019. 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. During 2019, in order to partially address potential natural gas fuel curtailments and interruptions, Cleco contracted for natural gas firm transportation with several interstate pipelines for a period of one year ending in late 2020. Additionally, in September 2019, Cleco Power completed the construction of the Coughlin Pipeline project. The new pipeline connects the Pine Prairie Energy Center to Cleco’s Coughlin Power Station. It is expected to increase reliability for natural gas delivery and mitigate exposure to transportation cost increases.

Cleco uses gas storage in order 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. 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. At March 31, 2020, Cleco Power had 1.4 million MMBtu of gas in storage. Currently, Cleco Power anticipates that its diverse supply options and gas storage, combined with its solid-fuel generation resources, are adequate to meet its generation needs during any temporary interruption of natural gas supplies.

Sales

Cleco Power’s 2019 and 2018 system peak demands, which occurred on September 6, 2019, and January 17, 2018, were 2,492 MW and 2,879 MW, respectively. Sales and system peak demand are affected by weather and are typically highest during the summer air-conditioning season; however, peaks may occur during the winter season as well. For information on the effects of future energy sales on Cleco Power’s results of operations, financial condition, and cash flows, see “Risk Factors — Operational Risks — Future Electricity Sales” and “— Weather Sensitivity.” For information on the financial effects of seasonal demand on Cleco Power’s quarterly operating results, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 19 — Miscellaneous Financial Information (Unaudited).”

Reserve margin is the net capacity resources (either owned or purchased) less native load demand, divided by native load demand. Members of MISO submit their forecasted native load demand to MISO each year. During 2019, Cleco Power’s reserve margin was 31.7%, which was above MISO’s unforced planning reserve margin

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benchmark of 7.9%. During 2018, Cleco Power’s reserve margin was 21.2%, which was also above MISO’s unforced planning reserve margin benchmark of 8.4%. Cleco Power expects to meet or exceed MISO’s unforced planning reserve margin benchmark of 8.9% in 2020. For more information on MISO, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Transmission Rates.”

Customers

Cleco Power did not have a significant customer that accounted for 10% or more of Cleco or Cleco Power’s consolidated revenue in 2019, 2018, or 2017. For more information regarding Cleco Power’s sales and revenue, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

Capital Investment Projects

For a discussion of certain Cleco Power major capital investment projects, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Cleco Power — Bayou Vista to Segura Transmission Project” and “— DSMART Project.”

Capital Expenditures and Financing

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

Cleco Cajun

Power Generation

On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in NRG South Central. As a result, Cleco Cajun became a new reportable segment. For more information about the Cleco Cajun Transaction, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations.”

The following table sets forth certain information with respect to Cleco Cajun’s generating facilities:

GENERATING STATION	COMMENCEMENT OF COMMERCIAL OPERATION	RATED CAPACITY (MW)	NET CAPACITY (MW)(1)	PRIMARY FUEL USED FOR GENERATION	GENERATION TYPE
Bayou Cove (2)	2002	225(5)	223(5)	natural gas	combustion
Big Cajun I
Unit 1 and Unit 2	1972	220	184	natural gas	steam
Unit 3 and Unit 4	2001	210	198	natural gas	combustion
Big Cajun II
Unit 1	1981	580	558	coal	steam
Unit 2	1982	540	574	natural gas	steam
Unit 3	1983	341(6)	334(6)	coal	steam
Cottonwood (3)	2003	1,263	1,155	natural gas	combined cycle
Sterlington (4)	1971 - 1975	176	99	natural gas	combustion
Total generating capability		3,555	3,325

(1)
Based on capacity testing of the generating units and operational tests performed between December 2018 and September 2019. These amounts do not represent generating unit capacity for MISO planning reserve margins.

(2)
Units 2, 3, and 4.

(3)
Units 1, 2, 3, and 4. Upon closing of the Cleco Cajun Transaction, Cottonwood Energy entered into the Cottonwood Sale Leaseback.

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For more information on the Cottonwood Sale Leaseback, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases — Lessor Agreements — Cottonwood Sale Leaseback Agreement” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 4 — Leases — Cottonwood Sale Leaseback Agreement.”

(4)
Units 1-4 and 6-10

(5)
Represents Cleco Cajun’s 225 MW ownership interest in the capacity of Bayou Cove, a 300-MW generating unit.

(6)
Represents Cleco Cajun’s 58% ownership interest in the capacity of Big Cajun Unit 3, a 588-MW generating unit.

Fuel and Purchased Power

Cleco Cajun uses coal and natural gas for its power generation resources. Cleco Cajun procures these fuels under contracts from a variety of suppliers and transporters. Cleco Cajun maintains an inventory of coal supply on-site at its coal generating facilities.

Sales

Cleco Cajun sells wholesale electric supply in Louisiana, Texas, and Arkansas. It furnishes supply to its wholesale customers primarily through all-requirements power supply and service agreements, which require Cleco Cajun to provide the electric capacity, energy, and other services necessary to serve most of its customers’ load requirements. Cleco Cajun procures the entirety of the power required to fulfill these obligations through its participation in the MISO market.

Cleco Cajun’s business experiences seasonality, as it bills its customers based on actual electric energy consumed. This usage tends to be greater during periods of high and low temperatures as compared to periods of moderate temperatures.

Competition

Competition for Cleco Cajun’s customers is limited through 2025, when the majority of the wholesale electric supply contracts terminate. Cleco Cajun currently intends to fully participate in co-operative requests for proposals for load after 2025. Within MISO, competitors typically comprise of investor-owned utilities, independent power producers, power marketers and power plant developers. These entities typically compete on the basis of price, reliability, and residual risk to the purchasing customer and its end users.

Customers

Cleco Cajun did not have a significant customer that accounted for 10% or more of Cleco’s consolidated revenue in 2019. For more information regarding Cleco Cajun’s sales and revenue, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

Capital Expenditures and Financing

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

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 is subject to the jurisdiction of FERC with respect to transmission tariffs, accounting, interconnections with other utilities, reliability, and the transmission of power. Periodically, Cleco Power has sought and received from both the LPSC and FERC increases in retail rates and transmission tariffs, respectively, to cover increases in operating costs and costs associated with additions to generation, transmission, and distribution facilities.

Cleco Cajun is subject to the jurisdiction of FERC with respect to transmission tariffs, interconnections with other utilities, reliability, and the transmission of power. The rates Cleco, through Cleco Power and Cleco Cajun, charges its wholesale customers are subject to FERC’s triennial market power analysis.

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Cleco Power’s annual retail earnings are subject to an FRP that was approved by the LPSC in June 2014. Under the terms of Cleco Power’s current FRP, Cleco Power is allowed to earn a target ROE of 10.0%, while providing the opportunity to earn up to 10.9%. Additionally, 60% of retail earnings between 10.9% and 11.75% and all retail earnings over 11.75% are required to be refunded to customers. The amount of credits due to customers, if any, is determined by Cleco Power and the LPSC annually. Credits are typically included on customers’ bills the following summer, but the amount and timing of the refunds are ultimately subject to LPSC approval. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP with anticipated new rates being effective July 1, 2020. Cleco Power has responded to several sets of data requests relating to the new FRP.

Generally, Cleco Power’s cost of fuel used for electric generation and the cost of purchased power are recovered through the LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. Recovery of FAC costs is subject to periodic fuel audits by the LPSC. For more information on the FAC and the most recent fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit.”

In 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides for an EAC to recover from customers certain costs of environmental compliance. These expenses are eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC. For more information on the EAC and the most recent EAC audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit.”

For more information on the LPSC staff’s FRP reviews, amounts accrued by Cleco Power as a result of the TCJA, and information on the tax dockets, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — FRP,” “— TCJA,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — FRP” and “— TCJA.”

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

Franchises

Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state law. These franchises are for fixed terms, which vary from 10 years to more than 50 years. 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 April 2022.

Franchise Renewals

Cleco Power renewed the following franchise agreements in 2019:

RENEWAL DATE	CITY/TOWN/VILLAGE	TERM	NUMBER OF CUSTOMERS
January 2019	Jeanerette	22 years	2,849
June 2019	Loreauville	27 years	384
July 2019	Opelousas	10 years	9,604
December 2019	Evergreen	27 years	214

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Industry Developments

For information on industry developments, see “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 “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 “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 impact of the TCJA on regulated public utilities,

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

• the role of electric utilities and independent transmission providers in competitive bidding in the construction of new transmission facilities,

• 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 a utility’s ability to buy generation assets,

• mandatory transmission reliability standards,

• NERC’s imposition of additional reliability and cybersecurity standards,

• 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,

• regulation of the disposal and management of CCRs from coal-fired power plants, and

• FERC’s increased ability to impose financial penalties.

At this time, management is unable to predict the outcome of such issues or the effects thereof on the results of operations, financial condition, or cash flows of Cleco.

For information on certain regulatory matters and regulatory accounting affecting Cleco, see “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

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material respects with these permits, as well as all applicable environmental laws and regulations. Environmental requirements affecting electric power generating 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 of the costs to comply with certain environmental laws and regulations from its retail customers. 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 the results of operations, financial condition, or cash flows of Cleco. For Cleco Power’s expected capital expenditures related to environmental compliance in 2020, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Cash Generation and Cash Requirements — Capital Expenditures.”

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 EGUs 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_x from Cleco’s generating units. The CAA contains a regional haze program with the goal of returning Class I Federal areas of the nation to natural visibility by 2064. States are required to develop regional haze State Implementation Plans (“SIP”) and revise them every ten years. A SIP must include requirements for the installation of Best Available Retrofit Technology (“BART”) for applicable EGUs in Louisiana. The EPA issued a final approval of the Louisiana SIP in December 2017. Although the approval was appealed to the United States Court of Appeals for the Fifth Circuit by the Sierra Club and the National Parks Conservation Association, the court denied all the challenges to the EPA’s approval of the Louisiana Regional Haze SIP. Because the Louisiana SIP mandates use of existing controls and participation in the Cross State Air Pollution rule as BART, Cleco does not believe the Louisiana SIP will have a material impact on the results of operations, financial condition, or cash flows of Cleco. The second planning period for the regional haze program will take place in 2021-2028. The SIP is due to be submitted to the EPA by July 31, 2021. Until the LDEQ determines what the reasonable progress requirements are for Cleco units and completes its update of the SIP, Cleco is unable to predict if the adopted rules will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

The CAA also established the Acid Rain Program to address the effects of acid rain and imposed restrictions on acid rain-causing SO₂ emissions from certain generating units. The CAA requires these EGUs 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. Cleco had sufficient allowances for operations in 2019 and expects to have sufficient allowances for 2020 operations under the Acid Rain Program.

The Acid Rain Program also established emission rate limits on NO_x emissions for certain generating units. Compliance with the acid rain permit limits for NO_x has been achieved at all affected facilities.

In December 2015, the EPA published the proposed CSAPR update for the 2008 ozone NAAQS in the Federal Register. The EPA finalized the rule in October 2016 with publication in the Federal Register. The EPA proposed Federal Implementation Plans (“FIP”) that update the existing EGU CSAPR NO_x ozone-season emission budgets and implement the budgets through the existing CSAPR NO_x ozone-season allowance trading program. The FIP required implementation began with the 2017 ozone season. Cleco is in compliance with the revised FIP rules. These rules did not have a material impact on the results of operations, financial condition, or cash flows of Cleco.

In October 2015, the EPA promulgated a revision to the 2015 ozone NAAQS, lowering the level of both the primary and secondary standards to 70 ppb. Under the CAA, each state is required to submit a SIP that provides for the implementation, maintenance and enforcement of each primary and secondary NAAQS. In particular, each SIP must contain adequate provisions prohibiting emissions activity within the state which will contribute significantly to non-attainment or interfere with maintenance by any other state with respect to any such primary or secondary ambient air quality standard. This “good neighbor” SIP is to be submitted to the EPA by the state

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within three years of promulgation of a new or revised NAAQS. The EPA determined that the SIP submittal by Louisiana meets the SIP completeness criteria. Cleco is in compliance with the rule. This rule did not have a material impact on the results of operations, financial condition, or cash flows of Cleco.

For more information on the legal proceedings of the MATS ruling, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit.”

On February 7, 2019, the EPA published in the Federal Register a proposed rule titled National Emission Standards for Hazardous Air Pollutants: Coal-and Oil-Fired Electric Utility Steam Generating Units — Reconsideration of Supplemental Findings and Residual Risk and Technology Review. The EPA proposes to find, after considering the cost of compliance relative to the hazardous air pollutant (“HAP”) benefits, that regulation of HAP emissions under section 112 of the CAA is not appropriate and necessary which would reverse the EPA’s prior conclusions. However, the EPA further proposes that this new determination will not remove the Coal-and Oil-Fired source category from the CAA list of sources that must be regulated and will not affect the existing HAP emissions standards. In addition, the proposal presents the results of the required residual risk and technology review which indicate that residual risks due to HAP emissions from this source category are acceptable and that the current standards provide an ample margin to protect human health. However, until the EPA has finalized the proposal, Cleco cannot predict the potential impacts of the final rule.

On April 12, 2019, the EPA published in the Federal Register proposed amendments to the National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines to address the results of the required periodic residual risk and technology review of the regulations. The EPA is proposing to find that risks from this source category due to air toxics emissions are acceptable and that the existing rule provides an adequate margin of safety to protect public health. The EPA also identified no new cost-effective controls under the technology review that would achieve further emissions reductions from the source category. In addition, the EPA is proposing through this rulemaking to remove the stay of effectiveness of the emission standards for new lean premix and diffusion flame gas-fired turbines that was promulgated in 2004. If the lifting of the stay were to be finalized as proposed, an emission limit for formaldehyde could be applied to new or reconstructed lean premix and diffusion flame turbines. Until the EPA has finalized the rule, Cleco cannot determine if the rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

In August 2015, the EPA released the final guidelines referred to as the CPP. These guidelines provide each state with standards for CO₂ emissions from the state’s utility industry. The EPA derived the limits for each state through a strategy involving a combination of unit efficiency improvements, dispatching away from boilers to combined cycle units, and applying renewable energy. The CPP requires significant reductions of CO₂ emissions. The CPP sets interim and final CO₂ emission goals for each state. The interim emission goals begin in 2022, with final emission goals required by 2030. In February 2016, the United States Supreme Court issued a stay of the CPP to remain in place until the D.C. Circuit Court of Appeals ruled on the merits and any ruling from the United States Supreme Court.

In August 2015, the EPA released the New Source Performance Standards (“NSPS”) rules for CO₂ emissions from new, modified, or reconstructed units. The rules set requirements and conditions with respect to CO₂ emission standards for new units and those that are modified or reconstructed. Cleco does not anticipate a modification or reconstruction of its existing sources that would trigger the application of the CO₂ emission limits.

In March 2017, the President of the United States signed a broad executive order. Among other measures, the order directed the EPA to review the CPP, the proposed FIP for the CPP, and the greenhouse gas new source performance standards (GHG NSPS). On July 8, 2019, the EPA published in the Federal Register a final rule to replace the CPP, formally titled Repeal of the CPP: Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations and informally known as the Affordable Clean Energy, or ACE, Rule. The state agency will have to set standards of performance for each affected generating unit and submit the implementation plan to the EPA for approval by

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July 8, 2022, with compliance expected within 24 months thereafter. Until the state agency has set standards for the affected generating units, management cannot determine the future regulatory requirements and impact on Cleco’s existing affected units or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

In December 2018, following a review as directed by the President of the United States, the EPA published proposed rules to replace the August 2015 NSPS rules for CO₂ emissions from new, modified, or reconstructed units. As with the current NSPS rules, the proposed rules set requirements and conditions with respect to CO₂ emission standards for new, modified, or reconstructed units. Cleco does not anticipate a future modification or future reconstruction of its existing units, as defined in the proposal, that would trigger the application of the proposed CO₂ emission limits. Until the EPA finalizes the rule, management cannot state what the final standards will entail or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

Until all directions of the executive order are carried out, management cannot predict what the final standards will entail or what controls the EPA and the state of Louisiana may require of Cleco in a final state implementation plan for existing units. However, any new rules that require significant reductions of CO₂ emissions could require significant capital expenditures or curtailment of operations of certain EGUs to achieve compliance.

The enactment of federal or state RPS mandating the use of renewable and alternative fuel sources such as wind, solar, biomass, and geothermal energy 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 business based on the RPS programs in other states.

A primary NAAQS for NO₂ promulgated by the EPA became effective in April 2010. The EPA established a new one-hour standard at a level of 100 ppb to supplement the existing annual standard. In 2012, the EPA determined that no area in the country was violating the standard. In April 2018, the EPA published, following the required review of the NAAQS, a final action that retains the ambient air standards for NO₂. 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 the EPA has not yet completed any new designations, Cleco cannot predict the likelihood or potential impacts of such a rule on its generating units at this time.

The EPA revised the NAAQS for SO₂ in June 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 EPA expects to use monitoring or modeling data developed in the future to confirm the status of areas that currently have no monitoring data. Classification of those areas without adequate data will be deferred until adequate data has been developed. In January 2018, the EPA published a final rule designating all areas containing Cleco generation facilities as either attainment/unclassifiable or unclassifiable. Therefore, there is no adverse impact to Cleco’s generating units.

On March 18, 2019, the EPA published, following the required review of the NAAQS, a final action that retains the ambient air standards for SO₂. 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 SO₂ emissions in the country, a non-attainment designation could result in utilities such as Cleco being required to substantially reduce their SO₂ emissions. However, because the EPA has not yet completed any new designations, Cleco cannot predict the likelihood or potential impacts of such a rule on its generating units at this time.

On May 2, 2019, Louisiana Generating notified the EPA and the LDEQ that it has elected not to Retrofit (as such term is defined in the Consent Decree) Big Cajun II, Unit 1.

Water Quality

Cleco’s facilities 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

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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.

In March 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 EPA published its final rule in August 2014. 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). The proposed standards would (1) set a performance standard, dealing with fish impingement mortality 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 are required to complete a number of studies within a 45-month period and then comply with the rule as soon as possible after the next discharge permit renewal, by a date determined by the permitting authorities. Portions of the final rule could apply to a number of Cleco’s fossil fuel steam electric generating stations. Until the required studies are conducted, including technical and economic evaluations of the control options available, and regulatory agency officials have reviewed the studies and made determinations, Cleco remains uncertain as to which technology options or retrofits will be required to be installed on its affected facilities. The costs of required technology options and retrofits may be significant, particularly 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. In November 2015, the EPA released the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category rule (“ELG rule”). The rule is focused on reducing the discharge of metals in wastewater from generating facilities to surface waters. In April 2017, the EPA administrator indicated that it is appropriate and in the public interest to reconsider the rule.

In September 2017, the EPA published a rule postponing for a two year period the earliest compliance dates for some of the wastewater streams that fall under the rule. On November 22, 2019, the EPA published proposed revisions to the ELG rule that would revise the technology-based effluent limitations guidelines and standards applicable to flue gas desulfurization and bottom ash transport waste waters. The rule may require costly technological upgrades at Cleco’s facilities, particularly if additional wastewater treatment systems are required to be installed or if waste streams must be eliminated. Until the EPA finalizes the rule, management cannot predict what the final standards will entail, what controls the EPA and the state of Louisiana may require of Cleco, or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

Solid Waste Disposal

In the course of operations, Cleco’s facilities generate solid and hazardous waste materials requiring 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.

In April 2015, the EPA published a final rule in the Federal Register for regulating the disposal and management of CCRs from coal-fired power plants (“CCR rule”). The federal regulation classifies CCRs as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act and allows beneficial use of CCRs with some restrictions. The rule establishes extensive requirements for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. In September 2017, the EPA administrator indicated that it is appropriate and in the public interest to reconsider the provisions of the final CCR rule. In August 2018, the Court of Appeals for the D.C. Circuit vacated several requirements in the CCR rule which included eliminating the previous acceptability of compacted clay material as a liner for impoundments. As a result, on December 2, 2019, the EPA published a proposed rule titled Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; A Holistic Approach to Closure Part A: Deadline To Initiate Closure. The proposed regulation would set deadlines for costly modifications including retrofitting of clay-lined impoundments with compliant liners or closure of the impoundments. Until the EPA has finalized the regulation, management cannot determine if the rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

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Cleco Power continues to be subject to state regulations pertaining to the disposal of coal ash. As a result, Cleco Power has an ARO for the retirement of certain ash disposal facilities. As part of the Cleco Cajun Transaction, Cleco recognized $15.3 million of AROs primarily related to the retirement of Cleco Cajun’s ash management areas. All costs of the CCR rule for Cleco Power are expected to be recovered from its customers in future rates. The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to the uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. Cleco will continue to gather additional data in future periods and will make decisions about compliance strategies and the timing of closure activities. As additional information becomes available and management makes decisions about compliance strategies and the timing of closure activities, Cleco will update the ARO balances to reflect these changes in estimates. However, management does not expect any required adjustment to the ARO to have a material effect on the results of operations, financial condition, or cash flows of Cleco. At December 31, 2019, management’s analysis confirmed that no additional adjustments were needed to update Cleco or Cleco Power’s ARO balance.

In December 2016, the Water Infrastructure Improvements for the Nation Act (“WIIN Act”), including the WIIN Act’s provisions regarding CCRs was signed into law. The WIIN Act’s CCR provisions allow for implementation of the federal CCR rule through a state-based permit program. However, until the state of Louisiana has evaluated the WIIN Act and made a decision on implementing a state-based option, Cleco cannot determine if the rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

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. Hazardous wastes produced by Cleco are properly disposed of at permitted hazardous waste disposal sites.

Toxic Substances Control Act (the “TSCA”)

The TSCA directs the EPA to regulate the marketing, disposing, manufacturing, processing, distributing in commerce, and usage of various toxic substances, including PCBs. Cleco operates and may continue to operate equipment containing PCBs under the TSCA. Once the equipment reaches the end of its useful life, the EPA regulates handling and disposing of the equipment and fluids containing PCBs. Within these regulations, handling and disposing is allowed only through facilities approved and permitted by the EPA. Cleco properly disposes of its PCB waste material at TSCA-permitted disposal facilities.

Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”)

The CERCLA imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. In 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study (“RI/FS”) from the EPA for a facility known as the Devil’s Swamp Lake site located just northwest of Baton Rouge, Louisiana. The notice requested that Cleco and Cleco Power, along with many other listed potentially responsible parties (“PRP”), enter into negotiations with the EPA for the performance of an RI/FS at the Devil’s Swamp Lake site. In 2008, the EPA identified Cleco as one of many companies that sent PCB wastes for disposal to the site. The EPA proposed to add the Devil’s Swamp Lake site to the National Priorities List, based on the release of PCBs to fisheries and wetlands located on the site, but no final listing decision has been made. The EPA issued a Unilateral Administrative Order to two PRPs, Clean Harbors, Inc. and Baton Rouge Disposal, to conduct an RI/FS in 2009. The tier 1 part of the study was completed in June 2012. The tier 2 remedial investigation report, that fish and crawfish from the area should not be eaten, was made public in December 2015. On September 9, 2019, the EPA publicly announced a proposed cleanup strategy for the Superfund Site. Until a final plan is presented by the EPA, management is unable to determine how significant Cleco’s share of the costs associated with a possible response action at the site, if any, may be and whether this will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

Emergency Planning and Community Right-to-Know Act (“EPCRA”)

Section 313 of the EPCRA requires certain facilities that manufacture, process, or otherwise use minimum quantities of listed toxic chemicals to file an annual report with the EPA called a Toxic Release Inventory (“TRI”) report. The TRI report requires industrial facilities to report on approximately 650 substances that the facilities release into the air, water, and land. The TRI report ranks companies based on the amount of a

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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 and 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. Neither Cleco nor Cleco Power are parties in any lawsuits related to EMFs.

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PROPERTIES

CLECO POWER

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

Electric Generating Stations

As of March 31, 2020, Cleco Power either owned or had an ownership interest in six steam electric generating stations, three combined cycle units, and one gas turbine with a combined nameplate capacity of 3,360 MW, and a combined electric net generating capacity of 3,214 MW. The nameplate capacity is the capacity at the start of commercial operations, and the net generating capacity is the result of capacity tests and operational tests performed during 2019, as required by MISO. 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 “Business — Operations — Cleco Power — Power Generation.”

Electric Substations

As of March 31, 2020, Cleco Power owned 86 active transmission substations and 249 active distribution substations.

Electric Lines

As of March 31, 2020, Cleco Power’s transmission system consisted of 67 circuit miles of 500kV lines; 561 circuit miles of 230-kV lines; 672 circuit miles of 138 kV lines; and 29 circuit miles of 69-kV lines. As of March 31, 2020, Cleco Power’s distribution system consisted of 3,398 circuit miles of 34.5-kV lines and 8,718 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 under Cleco Power’s Indenture of Mortgage, which does not impair the use of such properties in the operation of its business. As of March 31, 2020, 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.

CLECO CAJUN

Cleco Cajun has electric generating stations and electric operating properties located in Louisiana and Texas. Cleco Cajun considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For more information on Cleco Cajun’s generating facilities, see “Business — Operations — Cleco Cajun.”

Electric Generating Stations

As of March 31, 2020, Cleco Cajun has ownership interest in five electric generating stations which, combined, consist of 14 gas turbine units and five steam electric generating units located in Louisiana as well as four combined cycle units located in Texas. These generating facilities have a combined rated capacity of 3,555 MW. For more information on Cleco Cajun’s generating facilities, see “Business — Operations — Cleco Cajun.”

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General Properties

Cleco Cajun owns various properties throughout Louisiana, which include a regional office, telecommunications equipment, and other general-purpose assets.

Title

Cleco Cajun’s assets are owned in fee simple and are not subject to non-ordinary course of business liens or encumbrances.

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LEGAL PROCEEDINGS

For information on legal proceedings affecting Cleco, see “Business — Environmental Matters — Air Quality,” “Risk Factors — Operational Risks — Litigation,” “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation.”

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

RISK OVERVIEW

Cleco is exposed to counterparty credit risk, liquidity risk, interest rate risk, and commodity price risk. Cleco has implemented a governance framework, inclusive of risk policies and procedures to manage these and other risks.

Counterparty Credit Risks

When Cleco enters into bilateral commodity derivative or physical commodity transactions, Cleco may be exposed to counterparty credit risk. Cleco is exposed to counterparty credit risk when a counterparty fails to meet their financial obligations causing Cleco to incur replacement losses.

Cleco monitors and manages its credit risk exposure through credit risk management policies and procedures that include:

• routine reviewing of counterparty credit quality and credit exposure,

• entering into standard industry master agreements with specific terms and conditions for credit exposure and non-performance, and

• exchanging guarantees or forms of cash equivalent collateral for financial assurance.

For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — General Considerations and Credit-Related Risks.”

Liquidity Risks

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows. Future actions or inactions of the federal government, including a failure to increase the government debt limit, could increase the actual or perceived risk that the United States may not pay its obligations when due and may disrupt financial markets, including capital markets, potentially limiting availability and increasing costs of capital. 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 Holdings and Cleco Power, management believes that Cleco will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. Cleco Holdings and Cleco Power pay fees and interest under their respective credit facilities based on the highest rating held. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — General Considerations and Credit-Related Risks.”

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, by refinancing balances outstanding under its variable-rate credit facility with fixed-rate 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 March 31, 2020, Cleco Holdings had $88.0 million of short-term debt outstanding under its $175.0 million credit facility at an all-in interest rate of 2.50%. The borrowing costs under Cleco Holdings’ credit facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%.

At March 31, 2020, Cleco Holdings had $330.0 million long-term variable rate bank term loans outstanding. One bank term loan has a balance of $300.0 million outstanding, at an interest rate of LIBOR plus 1.625%, for an all-in interest rate of 2.275% at March 31, 2020. Another bank term loan has a balance of $30.0 million outstanding, at an interest rate of LIBOR plus 1.625%, for an all-in interest rate of 2.275% at March 31, 2020. The weighted average rate for all outstanding term loan debt was 3.11%. Each 1% increase in the interest rate applicable to Cleco’s short- and long-term variable rate debt would result in a decrease in Cleco Holdings’ pretax earnings of $4.2 million.

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At March 31, 2020, Cleco Power had $150.0 million of short-term debt outstanding under its $300.0 million credit facility at an all-in interest rate of 1.875%. Cleco Power’s borrowing costs under its $300.0 million credit facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%. Each 1% increase in the interest rate applicable to Cleco Power’s short-term debt would result in a decrease in Cleco Power’s pretax earnings of $1.5 million.

Cleco may enter into 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 each reporting period presented, Cleco did not enter into any contracts to mitigate the volatility in interest rate risk.

Commodity Price Risks

Cleco Power and Cleco Cajun’s financial performance can be impacted by changes in commodity prices that impact fuel costs, generation revenues, and customer supply and revenue. Cleco’s Energy Market Risk Management Policy authorizes hedging commodity price risk with physical or financially settled derivative instruments within approved guidelines and limits of authority. Some of these transactions may qualify for the normal purchase, normal sale (“NPNS”) exception under derivative accounting guidance. Contracts that do not qualify for NPNS accounting treatment or are not elected for NPNS accounting treatment are marked-to-market and recorded on the balance sheet at their fair value.

Cleco Power and Cleco Cajun, individually, may be exposed to transmission congestion price risk as a result of physical transmission constraints present between MISO LMP nodes when serving customer load. Cleco Power and Cleco Cajun are awarded and/or purchase FTRs in auctions facilitated by MISO. FTRs are accounted for as derivatives not designated as hedging instruments for accounting purposes.

During 2019, Cleco Cajun entered into other commodity derivative contracts including fixed price physical forwards and swap transactions. During the three months ended March 31, 2020, Cleco Cajun entered into other commodity derivative contracts including fixed price physical forwards and financially settled swap transactions.

The following tables present the fair values of derivative instruments and their respective line items as recorded on Cleco’, Consolidated Balance Sheet at March 31, 2020:

Cleco
	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT MARCH 31, 2020
Commodity-related contracts
FTRs
Current	Energy risk management assets	$1,779
Current	Energy risk management liabilities	(683)
Other commodity derivatives
Current	Energy risk management assets	213
Current	Energy risk management liabilities	(9,014)
Non-current	Other deferred credits	(3,480)
Commodity-related contracts, net		$(11,185)

Cleco monitors the Value at Risk (“VaR”) of its other commodity derivative contracts requiring derivative accounting treatment. Cleco applies a parametric VaR covariance analytical approach within a 5-day holding period at a 95% confidence interval. VaR is defined as the minimum expected loss over a given holding period at a given confidence level based on observable market price volatilities.

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The following table presents the VaR of other commodity derivative contracts for the three months ended March 31, 2020, as well as the VaR at March 31, 2020, based on these assumptions:

		FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)	AT MAR. 31, 2020	HIGH	LOW	AVERAGE
Cleco	$4,558	$4,997	$2,087	$4,264

For more information on the accounting treatment and fair value of FTRs and other commodity derivatives, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Derivatives and Other Risk Management Activity,” “Note 8 — Fair Value Accounting — Commodity Contracts,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies — Derivatives and Other Risk Management Activity” and “Note 7 — Fair Value Accounting — Commodity Contracts.”

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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MANAGEMENT

Board of Managers of Cleco

As of May 22, 2020, the Board of Managers of Cleco Holdings is comprised of 12 managers, as set forth below. The Board of Managers of Cleco Power is comprised of 13 managers, including the same 12 managers that comprise the Board of Managers of Cleco Holdings, plus one additional manager, Melissa Stark. The Board of Managers of Cleco Holdings and the Board of Managers of Cleco Power are collectively referred to below as “the Boards.” The managers’ ages, dates of appointment, employment history, and committee assignments as of May 22, 2020, are also set forth below. Each of Ms. Scott and Messrs. Gallot, Gilchrist, and Wainer serve pursuant to one-year agreements which are considered for renewal annually by the Boards. Mr. Fontenot serves by virtue of his position as the CEO, and the other managers are designated for membership by BCI, John Hancock Financial, or MIRA.

Andrew Chapman joined MIRA in 2006. During his 13 years with MIRA, Mr. Chapman has served as a director of utility companies owned in part by MIRA’s funds, including Puget Sound Energy, Duquesne Light Company, Aquarion Water Company, Cleco, and entities related to those holdings. Along with Cleco, he now serves on the board for the entity holding Lordstown Energy Center, a gas-fired power plant in eastern Ohio. Mr. Chapman is 65 years old and became a member of the Boards in 2016. He is the Chair of the Business Planning and Budget Review Committee and a member of the Asset Management Committee, the Leadership Development and Compensation Committee, the Governance and Public Affairs Committee and the Audit Committee.

Mr. Chapman held executive positions with Elizabethtown Water Company, E-town Corporation, American Water Works and the State of New Jersey prior to joining MIRA in 2006.

Mr. Chapman earned his Masters of Business Administration from the Yale School of Management.

William “Bill” Fontenot has served as the President and CEO of Cleco Holdings since January 2018 and CEO of Cleco Power since February 2019. Mr. Fontenot is 57 years old and was appointed to the Boards in 2018. He is a member of the Asset Management Committee, the Business Planning and Budget Review Committee, and the Governance and Public Affairs Committee. During Mr. Fontenot’s 33 years of service, he managed the development and restructuring efforts of generation projects valued at over $900.0 million, as well as led the development and construction of the $1.0 billion power plant, Madison Unit 3. His previous background was in marketing and the development of merchant power businesses.

Mr. Fontenot serves on the boards of the Council for a Better Louisiana, Association of Edison Illuminating Companies, Southeastern Electric Exchange, and the Central Louisiana Community Foundation. He is a member of St. Rita Catholic Church.

Mr. Fontenot holds a Bachelor’s of Science degree in electrical engineering from Louisiana State University.

Paraskevas “Paris” Fronimos is a Senior Principal on the Infrastructure and Renewable Resource Investments team of BCI. He is 45 years old and became a member of the Boards in 2019. Mr. Fronimos is the Chair of the Asset Management Committee and a member of the Business Planning and Budget Review Committee.

Mr. Fronimos joined BCI in 2017 and works with the management teams of portfolio companies to unlock and deliver shareholder value. He is primarily engaged with energy and utility companies in the Americas, serving as a Director of Tribus Services Inc., a United States utility services company, an Alternate Director of Nova Transportadora do Sudeste, a Brazilian natural gas pipeline, and an Alternate Director of Isagen, a Colombian power producer. Prior to BCI, Mr. Fronimos was employed by Nova Scotia Power, a Canadian power utility, as a fuels portfolio manager. He has more than 15 years of experience in the energy and utilities space, having worked on environmental and energy policy, developing greenfield energy projects, advising on transactions, and driving fleet and fuel supply optimization activities, including commodity pricing and hedging.

Mr. Fronimos holds a bachelor’s degree in Mineral Resources Engineering from the Technical University of Crete and a Master’s in Business Administration (specializing in Natural Resources and Energy) from the University of Alberta. He is an Energy Risk Professional (ERP®) certified by the Global Association of Risk Professionals.

Richard “Rick” Gallot, Jr. is the President of Grambling State University. He is 54 years old and became a member of the Boards in 2016. Mr. Gallot is a member of the Leadership Development and Compensation Committee and the Governance and Public Affairs Committee.

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Mr. Gallot serves on the board of Origin Bancorp, Inc. (Nasdaq: OBNK). He recently served as a Louisiana state senator for District 29, where he held the position of Vice-chair of the Commerce Committee and was a member of the Agriculture, Forestry, Aquaculture, and Rural Development Committee and the Revenue and Fiscal Affairs Committee. He previously served as a member of the Louisiana House of Representatives for District 11, where he served as Chair of the House and Governmental Affairs Committee and was a member of the Executive Committee.

Mr. Gallot obtained his Juris Doctorate from Southern University School of Law and has been a licensed Louisiana Attorney since 1990.

David Randall “Randy” Gilchrist is the President and CEO of Gilchrist Construction Company (“GCC”), a central Louisiana-based infrastructure contractor specializing in road and bridge construction. He is 60 years old and became a member of the Boards in 2016. Mr. Gilchrist is a member of the Asset Management Committee and the Audit Committee.

Under Mr. Gilchrist’s leadership, GCC has grown since 1985 from a small site work contractor to one of Louisiana’s leading highway contractors. Mr. Gilchrist has served as President of Associated General Contractors, Chair of Driving Louisiana Forward, Chair of the Central Louisiana Chamber of Commerce, and Vice Chair of Central Louisiana Economic Development Alliance. He has also served on the boards of The Rapides Foundation and Rapides Healthcare System.

Gerald Hanrahan is a Senior Industry Advisor to the Power and Infrastructure Team at John Hancock. The Power and Infrastructure Team is responsible for transactions in public utility, independent power project and infrastructure financing areas for John Hancock and manages a portfolio of over $21.0 billion in assets spanning over 300 individual investments. Mr. Hanrahan is 59 years old and became a member of the Boards in 2018. He is a member of the Asset Management Committee.

Mr. Hanrahan joined John Hancock as a director in 2001, served as managing director from 2003 to 2011, and served as Team Leader - Vice President from 2011 until 2016. He has worked in the financing area of the power industry since 1990. Before joining John Hancock, Mr. Hanrahan worked for four years in the Boston and London offices of InterGen, where he coordinated all financing activities on $2.7 billion in power projects in Turkey, Colombia and Egypt. Before that, he spent nine years in the structured finance and financial advisory divisions of Bank of Tokyo Capital Corporation in Boston.

Mr. Hanrahan holds a Masters of Business Administration from Babson College and a Bachelor’s of Science degree from Northeastern University.

Christopher Leslie is Executive Chairman of MIRA Americas. Prior to taking that role in July 2016, Mr. Leslie was the CEO of Macquarie Infrastructure Partners Inc. (“Macquarie”), the manager of MIRA’s United States-based private infrastructure funds, Macquarie Infrastructure Partners I, II and III, which collectively manage more than $7.0 billion in United States and Canadian infrastructure investments. Mr. Leslie is 55 years old and became a member of the Boards in 2016. He is the Chair of the Leadership Development and Compensation Committee.

Mr. Leslie joined Macquarie in 1992 in Australia. He has been instrumental in expanding Macquarie’s infrastructure business globally, having launched Macquarie offices in Southeast Asia, India and North America.

Mr. Leslie holds a Bachelor of Commerce degree from the University of Melbourne.

Jon Perry is a Senior Principal within the Infrastructure & Renewable Resources Department at BCI, where he is responsible for sourcing, executing and managing infrastructure investments. He is 44 years old and became a member of the Boards in 2018. Mr. Perry is the Chair of the Audit Committee.

Mr. Perry serves on the board of Noverco Inc. (“Noverco”), an investment holding company, which through its subsidiaries, distributes natural gas. Noverco also offers power generation, gas storage, and marketing services. He has over 10 years of experience in the utility and energy sectors. Prior to working with BCI, he held positions as Manager, Mergers and Acquisitions at TransAlta, a leading Canadian independent power producer and Manager, Regulatory and Financial Reporting at FortisAlberta, a regulated distribution utility. Before then, Mr. Perry held financial and investor relations positions in Canadian junior and mid-cap oil and gas companies.

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Mr. Perry holds a Bachelor of Medical Laboratory Sciences from University of British Columbia. He is also a Chartered Accountant in the Province of Alberta and is a Chartered Financial Analyst charter holder.

Aaron Rubin is a Managing Director at MIRA, where he is responsible for MIRA’s North American power and utilities investment team. He is 42 years old and became a member of the Boards in 2018. Mr. Rubin is a member of the Business Planning and Budget Review Committee.

Since joining MIRA in 2008, Mr. Rubin has had extensive responsibility for investment origination and execution as well as for management of portfolio investments. He has also served as the CEO of the Moscow-based Macquarie Russia & CIS Infrastructure Fund, and has been a director of a number of MIRA portfolio companies in the energy, transportation, and communications sectors. Mr. Rubin is currently a director of Lordstown Energy Center, a 940 MW gas-fired power plant construction project in Ohio. Mr. Rubin is also the director of the UK subsidiary of Wheelabrator Technologies, Inc. Prior to joining MIRA, Mr. Rubin was a Vice President in JPMorgan’s North American mergers and acquisitions team.

Mr. Rubin holds a Bachelor of Commerce and a Bachelor of Laws degree from the University of Queensland.

Peggy Scott currently serves as the Chair of the Boards. She served as Chairperson and Interim CEO of Cleco Holdings from February 9, 2017, through December 31, 2017. She also serves on Cleco’s Audit Committee and Governance and Public Affairs Committee. Presently, Ms. Scott advises diverse industries, including healthcare and technology. She is 68 years old and became a member of the Boards in 2016.

Ms. Scott serves on the boards of The Eastern Company (Nasdaq: EML) and Health Insurance Innovations, Inc. (Nasdaq: HIIQ). Previously, she served as the Executive Vice President, Chief Operating Officer and CFO of Blue Cross Blue Shield of Louisiana (“BCBS”) and as Chief Strategy Officer. Prior to BCBS, Ms. Scott was an office Managing Partner with Deloitte Touche Tohmatsu Limited and held executive positions in United States and International companies where she led transformations, growth strategies, and operations in seven foreign countries.

Ms. Scott was named one of the ten Outstanding Young Women of America, featured in the Wall Street Journal as National Financial Executive of the year, and inducted into the American Institute of CPAs’ Hall of Fame. She is in the Louisiana State University’s Alumni Hall of Distinction, named a Tulane Outstanding Alumnus and holds a Ronald Reagan presidential citation.

Ms. Scott is a Certified Public Accountant and also is certified in Valuations and Forensics. She holds a Masters of Business Administration from Tulane University and a Bachelor’s of Science degree in accounting from Louisiana State University.

Melissa Stark currently serves as the managing principal and owner of Co Issuer Corporate Staffing, LLC, which she established in 2003 to provide independent directors and officers for special purpose entities. She is 57 years old and was appointed in 2016 as a special independent manager of Cleco Power, whose sole purpose is to vote on any bankruptcy-related matters, as specified in Cleco Power’s Second Amended and Restated Operating Agreement. From 2001 to 2017, Ms. Stark concurrently served as a principal and co-founder of Water Tower Capital, LLC, a Chicago based investment advisory firm. From 1994 to 1996 she was Vice President - Fixed Income Research at Duff & Phelps (now known as Fitch) where she covered high yield bonds in the retail industry. She served as Vice President - Special Investments at PPM America, Inc. from 1991 to 1994.

Ms. Stark holds a Masters of Business Administration in Finance from New York University Stern School of Business.

Steven Turner is a Senior Portfolio Manager within the Infrastructure & Renewable Resources Department at BCI, where he is responsible for sourcing, executing, and managing infrastructure investments. He is 47 years old and became a member of the Boards in 2016. Mr. Turner is the Chair of the Governance and Public Affairs Committee and a member of the Business Planning and Budget Review Committee and the Leadership Development and Compensation Committee.

Mr. Turner serves on the board of Corix Infrastructure Inc., a privately-held waste/wastewater and utility holding company based in Vancouver, British Columbia. He is also a past director of Macquarie Utilities Inc. and Aquarion Water Company, the parent companies to a suite of New England-based water utilities.

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Mr. Turner has over 15 years of experience in equity capital markets. Prior to joining BCI, he held positions as an Associate with Ventures West Management, a leading Canadian venture capital firm and as an Associate Equity Analyst with Raymond James Ltd., a full service brokerage firm.

Mr. Turner has a Bachelor’s of Science degree in Environmental Engineering from Montana Tech of the University of Montana and holds a Masters of Business Administration from the University of Victoria. He is also a registered Professional Engineer in the Province of British Columbia, a Chartered Financial Analyst charter holder and a holder of the ICD.D designation.

Bruce Wainer is the CEO of Wainer Enterprises, a family-owned commercial development company on Louisiana’s Northshore and in New Orleans. He is 61 years old and became a member of the Boards in 2016. Mr. Wainer is a member of the Business Planning and Budget Review Committee and the Governance and Public Affairs Committee. He is the developer of some of the most successful commercial developments in the New Orleans area and past chairman of the Northshore Business Council. His business affiliations include partner at Wainer Brothers, All State Financial Company and Circle West Trailer Park Company; president of Quality Properties, Inc., Regent Lands, Inc., Flowers, Inc., Upside Down Cajun Brands, Inc., Louisiana Properties, Inc., Tamco, Inc., Riverhill, Inc., Metro Credit Services, Inc. and Pan American Investors, Inc., and manager of Advance Mortgage Company, LLC.

Executive Officers of Cleco

The names of the executive officers of Cleco and certain subsidiaries, their positions held, five-year employment history, ages, and years of service as of May 22, 2020, are as follows. Executive officers are appointed annually to serve for the ensuing year or until their successors have been appointed.

NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
William G. Fontenot
Cleco Holdings	President and CEO since January 2018.
Cleco Power	CEO since February 2019; President and CEO from January 2018 to February 2019; Interim CEO from February 2017 to December 2017; Chief Operating Officer from April 2016 to February 2017; Senior Vice President - Utility Operations from March 2012 to April 2016.
Cleco Cajun	CEO since February 2019. (Age 57; 33 years of service)
Kazi K. Hasan
Cleco Holdings Cleco Power	CFO since October 2018; Chief Risk Officer, AES Corporation from late 2014 to May 2018.
Cleco Cajun	CFO since February 2019. (Age 49; 1 year of service)
Anthony L. Bunting
Cleco Holdings Cleco Power	Chief Transformation Officer since February 2019; Chief Administrative Officer from April 2016 to February 2019; Vice President - Transmission & Distribution Operations from March 2012 to April 2016. (Age 60; 28 years of service)

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NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Robert R. LaBorde, Jr.
Cleco Holdings	Chief Operations Officer since February 2019; Vice President Generation Operations & Environmental Services from April 2016 to February 2019.
Cleco Power	Vice President - Generation Operations from November 2012 to April 2016. (Age 52; 28 years of service)
Justin S. Hilton
Cleco Power	President since February 2019.
Cleco Holdings Cleco Power	Vice President MISO Operations from April 2016 to February 2019; General Manager Transmission Strategy from March 2012 to April 2016. (Age 50; 30 years of service)
Robert E. Adrian
Cleco Cajun	Chief Operating Officer since November 2018; CEO, eServices, LLC from January 2012 to November 2018.
	(Age 60; 1 year of service)
J. Robert Cleghorn
Cleco Power	Vice President Regulatory Strategy since April 2016.
Cleco Holdings Cleco Power	General Manager Regulatory Strategy & Planning from March 2012 to April 2016. (Age 61; 32 years of service)
Gregory A. Coco
Cleco Power	Vice President Transmission & Distribution Operations since April 2016.
Cleco Holdings	General Manager Brame Energy Center from March 2013 to April 2016.
Cleco Power	(Age 60; 38 years of service)
Patrick M. Dupuy
Cleco Holdings	Interim Vice President Asset Optimization since February 2019; Plant Manager, Dolet Hills Power Station from November 2002 to February 2019.
	(Age 57; 34 years of service)
Kristin L. Guillory
Cleco Cajun	President since September 2019.
Cleco Holdings Cleco Power	Treasurer from February 2018 to September 2019; General Manager Finance and Assistant Treasurer from May 2016 to February 2018; Manager Finance, Risk and Analytics & Assistant Treasurer from December 2013 to May 2016. (Age 37; 15 years of service)

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NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Sidney D. Jacobson
Cleco Holdings	Vice President Risk Management since May 2020; Director Risk Management from January 2019 to May 2020; Managing Director, Pivotal Risk Advisors from October 2015 to January 2019; Partner, Energy Consulting Practice, Sungard Consulting Services from July 2011 to October 2015.
	(Age 53; 1 year of service)
Jeremy J. Kliebert
Cleco Holdings	Associate General Counsel since March 2019; Vice President, Deputy General Counsel, Chief Data Privacy Officer, Chief IP Counsel, and Chief Privacy Counsel, Albemarle Corporation from December 2017 to March 2019; Vice President, Deputy General Counsel, Chief IP Counsel and Data Privacy Counsel, Albemarle Corporation from January 2015 to December 2017.
	(Age 44; 1 year of service)
F. Tonita Laprarie
Cleco Holdings Cleco Power	Controller & Chief Accounting Officer since July 2016; General Manager Audit & Risk from March 2014 to July 2016.
Cleco Cajun	Controller & Chief Accounting Officer since February 2019.
	(Age 55; 19 years of service)
Mark A. Madsen
Cleco Holdings	Chief Digital & Information Officer since May 2019; Chief Information Officer, Vice President of IT - Waste Management Inc. from March 2010 to January 2019. (Age 50; 1 year of service)
Sybil S. Montegut
Cleco Holdings	Vice President Enterprise Analytics since May 2020; Director Innovation and Transformation from January 2020 to May 2020; General Manager Transformation Office from March 2018 to January 2020; Supervisor Corporate Analytics from May 2016 to March 2018; Senior Investor Relations Analyst from November 2012 to May 2016.
	(Age 42; 11 years of service)
Normanique G. Preston
Cleco Holdings	Chief Human Resources & Diversity Officer since September 2019; Vice President Human Resources from August 2018 to September 2019; Vice President - Human Resources, Dynegy, Inc. from November 2015 to June 2018.
	(Age 53; 1 year of service)
Joel M. Prevost
Cleco Holdings Cleco Power	Vice President Asset Management since April 2016; General Manager T&D Engineering & Construction from March 2012 to April 2016. (Age 59; 38 years of service)

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NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Eric A. Schouest
Cleco Power	Vice President Governmental Affairs since September 2019.
Cleco Cajun	President from February 2019 to September 2019; Interim President from May 2018 to February 2019.
Cleco Holdings Cleco Power	Vice President Governmental Affairs from March 2018 to May 2018; Vice President Marketing South from August 2016 to March 2018; General Manager Governmental Affairs/Regulatory Sales from February 2013 to August 2016. (Age 55; 18 years of service)
Dean C. Sikes
Cleco Holdings Cleco Power	Vice President Engineering, Construction & Project Management since April 2016; General Manager Generation Engineering & Construction from March 2013 to April 2016. (Age 56; 32 years of service)
Vincent Sipowicz
Cleco Holdings	Treasurer since May 2020; Director Investor Relations, AES Corporation from 2015 to May 2020; Director Corporate Finance/Treasury, AES Corporation from 2012 to 2015.
	(Age 46; <1 year of service)
Marty A. Smith
Cleco Power	Vice President Marketing since May 2018; Vice President Marketing North from January 2017 to May 2018; General Manager Distribution Engineering & Real Estate from February 2013 to April 2016.
Cleco Holdings	General Manager Corporate Safety from April 2016 to January 2017.
	(Age 58; 28 years of service)
Russell L. Snyder
Cleco Power	Vice President Generation Operations since February 2019; General Manager Southern Gas Fleet from May 2016 to February 2019; Manager - Power Plant (>500 MW) from February 2010 to May 2016.
	(Age 59; 35 years of service)
Terry J. Whitmore
Cleco Holdings	Vice President Transmission Services since February 2019.
Cleco power	General Manager Transmission Strategy from May 2016 to February 2019; Manager - Transmission Strategy & Support from March 2012 to May 2016.
	(Age 56; 30 years of service)

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Audit Committee

Cleco has a separately-designated standing audit committee. The members of Cleco’s Audit Committee are Andrew Chapman, Randy Gilchrist, Jon Perry (who serves as Chair of the committee) and Peggy Scott. The Boards have determined that Andrew Chapman is the Audit Committee financial expert.

Code of Business Conduct & Ethics and Related Party Transactions

Cleco has adopted a Code of Conduct that applies to its principal executive officer, principal financial officer, principal accounting officer, and treasurer. Cleco also has adopted Ethics & Business Standards applicable to all employees and the Boards. In addition, the Boards have adopted Conflicts of Interest and Related Policies to prohibit certain conduct and to reflect the expectation of the Boards that their members engage in and promote honest and ethical conduct in carrying out their duties and responsibilities, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships and corporate opportunities. Under the Conflicts of Interest and Related Policies, Cleco considers transactions that are reportable under the SEC’s rules for transactions with related parties to be conflicts of interest and prohibits them. Any request, waiver, interpretation or other administration of the policy shall be referred to the Governance and Public Affairs Committee. Any recommendations by the Governance and Public Affairs Committee to implement a waiver shall be referred to the full Boards for a final determination. The Code of Conduct for Financial Managers, Ethics & Business Standards, and Conflicts of Interest and Related Policies are posted on Cleco’s website at https://cleco.com; About Us-Leadership-Codes of Conduct. Each of these documents is also available free of charge by request sent to: Public Relations, Cleco, P.O. Box 5000, Pineville, LA 71361-5000.

Communications with the Boards

The Corporate Governance Guidelines provide for communications with the Boards by interested persons. In order for employees and other interested persons to make their concerns known to the Boards, Cleco has established a procedure for communications with the Boards through the Board’s Chair. The procedure is intended to provide a method for confidential communication, while at the same time protecting the privacy of the members of the Boards. Any interested person wishing to communicate with the Boards, or the non-management members of the Boards, may do so by addressing such communication as follows:

Chair of the Boards of Managers
c/o Corporate Secretary
Cleco Holdings
P. O. Box 5000
Pineville, LA 71361-5000

Upon receipt, Cleco’s Corporate Secretary will forward the communication, unopened, directly to the Chair of the Boards. The Chair will, upon review of the communication, make a determination as to whether it should be brought to the attention of the other non-management members and/or the management member of the Boards and whether any response should be made to the person sending the communication, unless the communication was made anonymously.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This section provides information about the compensation program in place for the Company’s named executive officers who are included in the Summary Compensation Table. It includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company provides.

Executive Summary

2019 Business Highlights

In 2019, the Company performed well operationally and financially and initiated transformational strategic projects. Below are some of our accomplishments for the year:

• Key Strategic Initiatives

○ Completed the START project which includes replacement of and improvement to Cleco’s enterprise business applications

○ Implemented several key elements of the safety strategy focused on improving employee and contractor safety to build a stronger safety culture which resulted in fewer recordable injuries as compared to 2018

○ Continued capture of potential cost savings identified in the 2017 benchmarking opportunity assessment

○ Increased efforts related to cybersecurity

○ Completed the human resources strategy related to succession planning as well as diversity and inclusion

• Effective Utility Operations

○ Effectively restored power following nine storms with a total cost of $25.1 million

• Key Capital Investments and Regulatory Outcomes

○ Completed construction on the St. Mary Clean Energy Center project, the Coughlin Pipeline project, and the Terrebonne to Bayou Vista Transmission project

○ Continuing construction on the Bayou Vista to Segura Transmission project

○ Continuing the DSMART project

Compensation Philosophy

The compensation principles and philosophy of the Committee are:

• Executives should be rewarded on performance, and incentives should align interests between management and the Company;

• Total remuneration (the sum of base salary, annual incentives, long-term incentives, and retirement benefits) should be aligned with the market median;

○ Newly hired and/or promoted executives should be transitioned to median over time as they become more proficient in their roles;

• The mix of fixed compensation (base salary and retirement benefits) and variable/at-risk compensation (annual incentive and long-term incentive) should align with market by emphasizing variable/at-risk compensation; and

• The competitive market for an executive’s compensation will be based on comparable utilities and will not be adjusted for Cleco’s privately held status or location.

Compensation Program Elements

The Committee targets total compensation (made up of the elements described below) to be competitive with the median of the Comparator Group (as defined below), but individual positioning may vary above or below the

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median depending on each executive’s experience, performance, and contribution to the Company. For 2019, we believe that we accomplished our philosophy through the following compensation and benefit components:

2019 PAY ELEMENT	DESCRIPTION
Base Salary	•	Fixed pay element
	•	Delivered in cash
Annual Cash Incentive (STIP)	•	Performance-based annual incentive plan that pays out in cash
	•	EBITDA is primary measure for the named executive officers
	•	Additional metrics include safety, system reliability, customer service, generation fleet availability, and milestone measures
Long-Term Incentives	•	Performance-based incentive paid in cash currently with a three-year cycle
	•	Payout is contingent on average ROE and total EBITDA, each weighted at 50%
Benefits	•	Broad-based benefits such as group medical, dental, vision, and prescription drug coverage; basic life insurance; supplemental life insurance; dependent life insurance; accidental death and dismemberment insurance; a defined benefit pension plan (for those employees hired prior to August 1, 2007); and 401(k) Plan with a Company match for those employees hired before August 1, 2007, as well as 401(k) Plan with an enhanced benefit for those employees hired on or after August 1, 2007; same as those provided to all employees
Executive Benefits	•	SERP (closed to new participants in 2014)
	•	Nonqualified Deferred Compensation Plan
Perquisites	•	Limited to executive physicals, spousal/companion travel, and relocation assistance

Roles and Responsibilities

Leadership Development and Compensation Committee (the “Compensation Committee”)

The Compensation Committee, which consists of one independent member of the board of managers of the Company (“Board Manager”) and three investor Board Managers, is responsible for developing and overseeing the Company’s executive compensation program. The Compensation Committee met seven times during 2019, including four telephonic meetings. The General Counsel and Chief Compliance Officer attended the Compensation Committee meetings on behalf of management but did not participate in the Compensation Committee’s executive sessions.

The Compensation Committee’s responsibilities, which are more fully described in its charter, include:

• establishing and overseeing the Company’s executive compensation philosophy and goals and the programs which align with those;

• engaging and evaluating an independent compensation consultant;

• determining if the Company’s executive compensation and benefit programs are achieving their intended purpose, being properly administered and creating proper incentives in light of the Company’s risk factors;

• analyzing the executive compensation and benefits practices of peer companies and annually reporting to the Board or recommending for approval by the Board the overall design of the Company’s executive compensation and benefit programs;

• annually evaluating the performance of the CEO and the CFO and recommending to the Board adjustments in the CEO and CFO’s compensation and benefits;

• overseeing the administrative committees and periodically reviewing the Company’s benefit plans, including retirement plans;

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• annually reviewing the Committee’s charter and revising as necessary;

• annually ensuring there is a process for talent and succession management for executives; and

• reviewing and making recommendations on efforts to promote diversity and inclusion.

The Compensation Consultant

The Compensation Committee engaged Pay Governance to consult on matters concerning executive officers’ compensation and benefits. All executive compensation adjustments and award calculations for 2019 were reviewed by Pay Governance on behalf of the Compensation Committee. Pay Governance acted at the direction of the Compensation Committee and was independent of management. Pay Governance was responsible for:

• recommending a group of peer companies to use for market comparisons;

• reviewing the Company’s executive compensation program, including compensation levels in relation to Company performance, pay opportunities relative to those at comparable companies, short- and long-term incentive targets and metrics, executive retirement benefits, and other executive benefits;

• reviewing the Company’s Board of Managers compensation program;

• reporting on emerging trends and best practices in the area of executive and Board of Manager compensation; and

• attending the Compensation Committee meetings.

The Compensation Committee reviewed the firm’s qualifications as well as its independence and the potential for conflicts of interest. The Compensation Committee concluded that Pay Governance is independent, and its services to the Compensation Committee do not create any conflicts of interest. The Compensation Committee has the sole authority to approve Pay Governance’s compensation and determine the nature and scope of its services. Pay Governance does not perform any other services for or receive any other fees from the Company.

CEO

The CEO discusses with the Compensation Committee base salary adjustments, cash incentives, and long-term incentive awards for executives other than himself. The CEO participates in meetings of the Compensation Committee to discuss executive compensation, including measures and performance targets but is subsequently excused to allow the independent members of the Compensation Committee to meet in executive session.

Evaluation and Design of the Compensation and Benefit Programs

The Compensation Committee believes that compensation and benefits for our executive officers who successfully enhance investors’ value should be competitive with the compensation and benefits offered by similar companies in our industry to attract and retain the high quality executive talent required by the Company. The Compensation Committee examines executive officers’ compensation against comparable positions using publicly available proxy data for a group of 13 industry peers (the “Peer Group”) and utility industry survey data to help design and benchmark our executive officer compensation. This evaluation includes base salary, annual and long-term incentive plan targets, other potential awards, retirement benefits, and target total compensation. The Peer Group is used to track comparable performance of the long-term incentive plan. The combination of the Peer Group and the utility industry survey data is referred to as the “Comparator Group.”

Vectren Corporation was removed from the Peer Group in 2019 due to its acquisition by another company. The Compensation Committee will continue to evaluate the Peer Group annually as companies are often acquired, taken private, or grow at a rate that renders them inappropriate for comparison purposes. The Compensation Committee evaluates the Peer Group to ensure that peer companies are of similar scope in relation to revenues, assets, and employee count and have a good operational fit.

2019 PEER GROUP
ALLETE, Inc.	Hawaiian Electric Industries, Inc.	Pinnacle West Capital Corporation
Alliant Energy Corporation	IDACORP, Inc.	PNM Resources, Inc.
Avista Corporation	NorthWestern Corporation	Portland General Electric Company
Black Hills Corporation	OGE Energy Corp.
El Paso Electric Company	Otter Tail Corporation

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In setting executive compensation levels in 2019, the Compensation Committee also used utility industry survey data from the most recent Willis Towers Watson Energy Services Executive Compensation Database. Survey data provides a broader energy industry perspective. This survey data is used in conjunction with the Peer Group data as a competitive market reference point for the Compensation Committee to consider in determining pay levels.

Decisions Made in 2019 with Regard to Each Compensation and Benefit Component

Base Salary

The Compensation Committee strives to set base salary levels for the executive officers as a group, including the named executive officers, at a level approximating +/-10% of the Comparator Group market median for total remuneration.

Base salaries for the named executive officers in 2019 are shown in the table below:

NAME	2019 BASE SALARY	2019 % CHANGE
Mr. Fontenot	$650,000	13.0%
Mr. Hasan	$400,000	0.0%
Ms. Callis	$285,000	5.6%
Mr. Bunting	$300,000	22.0%
Mr. LaBorde	$265,000	10.4%
Mr. Hilton(1)	$260,000	20.9%

(1)
Mr. Hilton is a Cleco Power employee.

Annual Cash Incentive

The Company maintains the STIP, an annual, performance-based cash incentive plan. The STIP applies to all regular, full-time employees, and it includes weighting for corporate and individual performance goals. The Compensation Committee targets STIP award opportunities for executive officers to approximate the median of the annual cash incentive target award of the Comparator Group. Payouts are capped at 200% of target.

The table below presents the target STIP opportunities for the named executive officers in 2019:

NAME	TARGET AS % OF BASE SALARY
Mr. Fontenot	100%
Mr. Hasan	50%
Ms. Callis	50%
Mr. Bunting	50%
Mr. LaBorde	50%
Mr. Hilton(1)	50%

(1)
Mr. Hilton is a Cleco Power employee.

The 2019 STIP award for the named executive officers was based on the corporate and individual performance measures described below. This includes measures that apply to non-named executive officers and employees. The 2019 corporate performance measures consisted of the elements listed below based on the business unit (weighting):

	CONSOLIDATED		BUSINESS UNIT
	SAFETY	EBITDA	EFORd	PEAK EAF	CUSTOMER SATISFACTION	LPSC SAIDI	EBITDA	MILESTONE MEASURES
Cleco Power	10%	20%	10%	15%		5%	20%	20%
Support Group(1)	10%	20%	7.5%	7.5%	7.5%	2.5%	25%	20%
Cleco Cajun	10%	20%	5%	15%			30%	20%

(1)
Support Group business unit weighting evenly split (50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting)

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The Compensation Committee included Milestone Measures in the 2019 STIP corporate metrics for EMT and other corporate officers weighted at 20%. These Milestone Measures were associated with progress milestones on key strategic corporate projects related to affordability, the START project, cybersecurity, and the Human Resources strategy. The Committee put the greatest emphasis on financial performance with EBITDA at both the business unit and consolidated levels. In addition, to continually focus the entire organization on the importance of safety, system reliability, generation fleet availability, and to focus Cleco Power and Support Group executives and employees on customer satisfaction the remainder of the bonus opportunity was attributable to these operational measures.

Management recommended the STIP financial performance and other measures to the Compensation Committee. Based on the historical performance relative to target and the relative historical performance versus the Peer Group, the Compensation Committee reviews, revises as appropriate, and approves the STIP measures for the upcoming year.

Details Related to Corporate Performance Metrics Established to Determine 2019 STIP Award Levels

Metric # 1: Safety Consolidated — For 2019, the Company included both the frequency of incidents represented by the Total Recordable Incident Rate (“TRIR”) and the severity of incidents represented by the Days Away, Restricted or Transferred (“DART”) rate for its safety measure. Each of these measures represents 5% of the overall STIP award for the corporate measures totaling 10% for the safety metric. The targets for both safety measures were based on the average rates of the companies in the Southeastern Electric Exchange, of which Cleco is a member, over the period 2017-2018.

SAFETY - TRIR MATRIX (5%)
PERFORMANCE LEVEL	% OF TRIR TARGET AWARD PAID
Above 0.655	0%
0.586 - 0.655	50%
0.515 - 0.585	100%
0.444 - 0.514	150%
At or below 0.443	200%
2019 Result (0.490)	150%

SAFETY - DART MATRIX (5%)
PERFORMANCE LEVEL	% OF DART TARGET AWARD PAID
Above 0.359	0%
0.301 - 0.359	50%
0.242 - 0.300	100%
0.183 - 0.241	150%
At or below 0.182	200%
2019 Result (0.210)	150%

Metric # 2: EBITDA Consolidated — The following EBITDA matrix was developed to determine performance and payout ranges related to consolidated EBITDA performance in 2019. This measure represents 30% of the overall STIP award for the corporate measures for non-executives and 20% of the overall STIP award for the corporate measures for executives. The final percentage of the financial target award is interpolated based on the performance level.

EBITDA MATRIX - CONSOLIDATED (20%)
PERFORMANCE LEVEL	% OF FINANCIAL TARGET AWARD PAID
Below $496.3 million	0%
Below $534.3 and above $496.3 million	50%
Between $534.3 and $544.1 million	100%
Above $544.1 and below $582.1 million	150%
At or above $582.1 million	200%
2019 Result - $565.1 million	155.3%

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Metric # 3: EFORd — This metric represents the probability a generator will fail either completely or in part when its operation is required and is 10% of the overall STIP award for the Cleco Power measures, 7.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting), and 5% of the overall STIP award for the Cleco Cajun corporate measures. The 2019 target was based on the weighted average performance over the three-year period 2016-2018.

EFORd MATRIX - CLECO POWER (10%)
PERFORMANCE LEVEL	% OF EFORd TARGET AWARD PAID
Above 7.33%	0%
6.55% - 7.33%	50%
5.75% - 6.54%	100%
4.96% - 5.74%	150%
At or below 4.95%	200%
2019 Result (3.6%)	200%

EFORd MATRIX - CLECO CAJUN (5%)
PERFORMANCE LEVEL	% of EFORd TARGET AWARD PAID
Above 13.09%	0%
12.56% - 13.09%	50%
12.02% - 12.55%	100%
11.49% -12.01%	150%
At or below 11.48%	200%
2019 Result (7.5%)	200%

Metric # 4: Peak EAF - Cleco Cajun and Support Group — This metric represents the amount of time that the power generation plant is able to produce electricity over a peak period (defined as May through September, Monday through Friday, hours ending 0700 through 2200), divided by the amount of time in the peak period and is 15% of the overall STIP award for the Cleco Cajun corporate measures and 7.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Cajun weighting). The 2019 target was based on Cleco Cajun fleet’s weighted average of the 2018 peak EAF unit targets.

PEAK EAF MATRIX - CLECO CAJUN (15%)
PERFORMANCE LEVEL	% OF PEAK EAF TARGET AWARD PAID
Below 88.51%	0%
At or above 88.51%	100%
2019 Result (96.77%)	100%

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Metric # 5: Customer Satisfaction - Cleco Power and Support Group — The Company included Customer Satisfaction in its performance measures in 2019 using the JD Power South Midsize segment (“JD Power study”) for comparison. For the STIP metric, the Company used the 2018 performance of the JD Power study to set the target. In addition, the Company compared its overall performance against its peers in the JD Power study. This metric represents 15% of the overall STIP award for Cleco Power corporate measures and 7.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Power weighting). The Compensation Committee used discretion to decrease the payout for officers to 50% of the target based on its review of 2019 performance. The resulting payout for 2019 was calculated as follows:

CUSTOMER SATISFACTION MATRIX - CLECO POWER (15%)
PERFORMANCE LEVEL	% OF CUSTOMER SATISFACTION TARGET AWARD PAID
Below 675	0%
675 - 715	50%
716 - 736	100%
737 - 745	150%
At or above 746	200%
2019 Result (717)	100%
Committee Discretion	(50)%
Resulting Total Payout	50%

Metric # 6: LPSC SAIDI - Cleco Power and Support Group — SAIDI measures the average amount of time a customer’s service is interrupted during the year and is measured in hours per customer per year. The 2019 LPSC SAIDI goal was based on the long-term goal of consistent performance improvement compared to the LPSC target. This metric represents 5% of the overall STIP award for the Cleco Power corporate measures and 2.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Power weighting).

LPSC SAIDI MATRIX - CLECO POWER (5%)
PERFORMANCE LEVEL	% OF LPSC SAIDI TARGET AWARD PAID
Above 2.87	0%
At or below 2.87	100%
2019 Result (2.64)	100%

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Metric # 7: EBITDA — The following EBITDA matrix was developed to determine performance and payout ranges related to EBITDA performance in 2019. This measure represents 30% for Cleco Power, 35% for the Support Group (Support Group employees weighting 50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting), 40% for Cleco Cajun of the overall STIP award for the corporate measures for non-executives and 20% for Cleco Power, 25% for the Support Group (Support Group employees weighting is 50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting), 30% for Cleco Cajun of the overall STIP award for the corporate measures for executives. The final percentage of the financial target award is interpolated based on the performance level.

EBITDA MATRIX - CLECO POWER (20%)
PERFORMANCE LEVEL	% OF FINANCIAL TARGET AWARD PAID
Below $407.6 million	0%
Below $440.7 and above $407.6 million	50%
$440.7 million	100%
Above $440.7 and below $473.7 million	150%
At or above $473.7 million	200%
2019 Result - $438.7 million	97.0%

EBITDA MATRIX - CLECO CAJUN (30%)
PERFORMANCE LEVEL	% OF FINANCIAL TARGET AWARD PAID
Below $88.7 million	0%
Below $93.6 million and $88.7 million	50%
Between $93.6 and $103.4 million	100%
Above $103.4 and below $108.4 million	150%
At or above $108.4 million	200%
2019 Result - $126.4 million	200%

Metric # 8: Milestone Measures — Cleco officers had an additional STIP metric for 2019. This metric represents 20% of the overall STIP award for the corporate measures for executives and measures progress on certain strategic initiatives. The four broad initiatives included the affordability effort (5%), the business application strategy (5%), cybersecurity (5%), and the Human Resources strategy (5%). The Committee evaluated the performance of each initiative and determined the 2019 result for the Milestone Measures as follows.

MILESTONE MEASURES (20%)
2019 RESULTS	% OF MILESTONE TARGET AWARD PAID
Cleco Power	70%
Support Group	70%
Cleco Cajun	100%

Total Payout for EMT Cleco Power: The calculated STIP payout for Cleco Power was 112% of target. The resulting total STIP corporate payout for 2019 was calculated as follows:

	% OF TARGET	x	AWARD LEVEL	=	% OF PAYOUT
Safety Consolidated	10%		150%		15%
EBITDA Consolidated	20%		155.3%		31.1%
EFORd	10%		200%		20%
Customer Satisfaction	15%		50%		7.5%
LPSC SAIDI	5%		100%		5%
EBITDA	20%		97%		19.4%
Milestone Measures	20%		70%		14%
Total	100%				112%

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Total Payout for EMT Support Group: The calculated STIP payout for the Support Group was 128.5% of target. The resulting total STIP corporate payout for 2019 was calculated as follows:

	% OF TARGET	x	AWARD LEVEL	=	% OF PAYOUT
Safety Consolidated	10%		150%		15%
EBITDA Consolidated	20%		155.3%		31.1%
EFORd	7.5%		200%		15%
Peak EAF	7.5%		100%		7.5%
Customer Satisfaction	7.5%		50%		3.7%
LPSC SAIDI	2.5%		100%		2.5%
EBITDA	25%		158.9%		39.7%
Milestone Measures	20%		70%		14%
Total	100%				128.5%

Total Payout for EMT Cleco Cajun: The calculated STIP payout for Cleco Cajun was 151.1% of target. The resulting total STIP corporate payout for 2019 was calculated as follows:

	% OF TARGET	x	AWARD LEVEL	=	% OF PAYOUT
Safety Consolidated	10%		150%		15%
EBITDA Consolidated	20%		155.3%		31.1%
EFORd	5%		200%		10%
Peak EAF	15%		100%		15%
EBITDA	30%		200%		60%
Milestone Measures	20%		100%		20%
Total	100%				151.1%

The Compensation Committee also has the authority to adjust the amount of any individual STIP award upon recommendation by the CEO. Adjustments for the STIP participants, except for the named executive officers and other members of EMT, may be made by the CEO at his discretion. Adjustments are based on the annual performance review process.

Long-Term Compensation

In 2019, the Compensation Committee continued a cash-based LTIP and issued grants for the three-year cycle for the performance period ending December 31, 2021. The metrics for the LTIP cycle issued in 2019 are weighted 50% on the three-year average ROIC and 50% on the three-year cumulative total EBITDA.

Each executive officer’s target LTIP award level is set, so in combination with other pay elements, it will deliver a total compensation opportunity comparable to that of our Peer Group. The chart below details the targeted opportunity for each of the named executives expressed as a percentage of base salary:

NAME	TARGET AS % OF BASE SALARY
Mr. Fontenot	231%
Mr. Hasan	110%
Ms. Callis	110%
Mr. Bunting	110%
Mr. LaBorde	110%
Mr. Hilton	110%

2017-2019 LTIP Award

The Compensation Committee approved an overall award level of 106.04% of target for the LTIP three-year performance cycle that ended on December 31, 2019. This award level represents an average ROE of 9.432% and a cumulative EBITDA of $1,386.85 million over the three-year performance period. This award will be paid in cash and is included in column G of the Summary Compensation Table for 2019.

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Retirement Plans - Nonqualified Deferred Compensation Plan

The Company maintains a Deferred Compensation Plan so that members of the Boards, executive officers, and certain key employees may defer receipt and taxation of certain forms of compensation. Members of the Boards may defer up to 100% of their compensation; executive officers and other key employees may defer up to 50% of their base salary and up to 100% of their annual cash incentive. The use of deferred compensation plans is prevalent within our industry and within the companies in the Peer Group. The Company does not match deferrals or contribute to the plan. Actual participation in the plan is voluntary. The notional investment options made available to participants are selected by the CFO. The allocation of deferrals among investment options is made by individual participants. The notional investment options include money market, fixed income, and equity funds. No changes were made to the plan during 2019.

Retirement Plans - SERP

The Company maintains a SERP for the benefit of the executive officers who are designated as participants by the Compensation Committee. SERP was designed to attract and retain executive officers who have contributed and will continue to contribute to our overall success by ensuring that adequate compensation will be provided or replaced during retirement.

Benefits under SERP vest after ten years of service or upon death or disability while a participant is employed by the Company. The Compensation Committee may reduce the vesting period, which typically would occur in association with recruiting efforts. Benefits, whether or not vested, are forfeited in the event a participant is terminated for cause.

Generally, benefits are based upon a participant’s attained age at the time of separation from service. The maximum benefit is payable at age 65 and is 65% of final compensation. Payments from the Company’s defined benefit pension plan (“Pension Plan”), certain employer contributions to the 401(k) Plan and payments paid or payable from prior and subsequent employers’ defined benefit retirement or similar supplemental plans reduce or offset SERP benefits. If a participant has not attained age 55 at the time of separation and receives SERP benefits before attaining age 65, SERP benefits are actuarially reduced to reflect early payment. The “Pension Benefits” table lists the present value of accumulated SERP benefits for the named executive officers as of December 31, 2019.

In 2011, the Compensation Committee amended SERP to eliminate the business transaction benefit previously included in SERP, as well as the requirement that a SERP participant be a party to an employment agreement to receive change in control benefits.

In July 2014, the Cleco Corporation Board of Directors voted to close SERP to new participants. With regard to current SERP participants, two participants have agreed to fix the base compensation portion of their SERP calculation as of December 31, 2019. Additionally, they have agreed to use target rather than actual awards under the annual incentive plan for years 2016 and 2019 for the average incentive award portion of the SERP calculation. A third participant’s SERP benefit will be set at a specified amount based upon the year of separation.

In the event a SERP participant’s employment is involuntarily terminated by the Company without cause, or the participant terminates his or her employment on account of good reason, occurring within the 36-month period following a change in control event for all participants who commenced participation in SERP prior to October 28, 2011, or the 24-month period following a change in control event for all participants who commenced participation in SERP on or after October 28, 2011, such participant’s benefit shall: (i) become fully vested; (ii) be increased by adding three years to an affected participant’s age, subject to a minimum benefit of 50% of final compensation; and (iii) be subject to a modified reduction determined by increasing the executive’s age by three years.

Change in Employment Status and Change in Control Events

During 2019, the Company had no employment agreements with named executives other than the agreement with Mr. Fontenot as President & CEO. The Company may enter into employment agreements with its executives generally in connection with recruiting efforts. The standard agreement provides for a non-renewing term, generally two years, and does not contain a change in control tax gross-up provision.

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The Cleco Corporation Executive Severance Plan

In recognition of the non-renewal of executive employment contracts, the Cleco Corporation Board of Directors adopted the Cleco Corporation Executive Severance Plan (the “Executive Severance Plan”) on October 28, 2011. The Executive Severance Plan provides the executive officers and other key employees with cash severance benefits in the event of a termination of employment, including involuntary termination in connection with a change in control.

Perquisites and Other Benefits

The Company may make available the following perquisites to its executive officers:

• Executive officer physicals - as a condition of receiving their STIP award, we require and pay for an annual physical for the executive officers and their spouses;

• Spousal/companion travel - in connection with the various industry, governmental, civic, and entertainment activities of the executive officers, we pay for spousal/companion travel associated with such events;

• Relocation program - in addition to the standard relocation policy available to all employees, we maintain a policy whereby the executive officers and other key employees may request that the Company pay real estate agent and certain other closing fees should the officer or key employee sell his/her primary residence or that the Company purchase the executive officer’s or key employee’s primary residence at the greater of its documented cost (not to exceed 120% of the original purchase price) or average appraised value. Typically, this occurs when an executive officer or key employee relocates at the Company’s request; and

• Purchase program - under the Executive Severance Plan, a covered executive officer may request the Company to purchase his/her primary residence in the event he or she is involuntarily terminated without cause or separates for good reason, either in connection with a change in control and further provided the executive officer relocates more than 100 miles from the residence to be purchased. Limits on the purchase amount are the same as the relocation program described above.

The Compensation Committee approves the perquisites based on what it believes is prevailing market practice, as well as specific Company needs. The Company believes the relocation program is an important element in attracting executive talent.

See the section titled “All Other Compensation” for details of these perquisites and their value for the named executive officers.

The executive officers, including the named executive officers, participate in the other benefit plans on the same terms as other employees. These plans include paid time off for vacation, sick leave, and bereavement; group medical, dental, vision, and prescription drug coverage (including the annual wellness program); basic life insurance; supplemental life insurance; dependent life insurance; accidental death and dismemberment insurance; Pension Plan (for those hired prior to August 1, 2007); and the 401(k) Plan with a Company match for those employees hired before August 1, 2007, as well as a 401(k) Plan with an enhanced benefit for those employees hired on or after August 1, 2007.

Board Compensation

The Governance and Public Affairs Committee may engage the Compensation Committee’s independent consultant from time to time to conduct market competitive reviews of the Board compensation program. Details of the Boards’ compensation are shown in the “Board of Managers Compensation” table.

Other Tools and Analyses to Support Compensation Decisions

Tally Sheets

At least annually, the Compensation Committee reviews tally sheets that set forth the items listed below. This review is conducted as part of the comparison of the compensation and benefit components that are prevalent within the Comparator Group. The comparison facilitates discussion with the Compensation Committee’s outside independent consultant as to the use and amount of each compensation and benefit component versus the applicable Peer Group.

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• Annual compensation expense for each named executive officer - this includes the rate of change in total cash compensation from year-to-year; the annual periodic cost of providing retirement benefits; and the annual cost of providing other benefits such as health insurance, as well as the status of any deferred compensation.

• Reportable compensation - to further evaluate total compensation; to evaluate total compensation of the CEO compared to the other executive officers; and to otherwise evaluate internal equity among the named officers.

• Post-employment payments - reviewed pursuant to the potential separation events discussed in “Potential Payments at Termination or Change in Control.”

Trends and Regulatory Updates

As needed, and generally at least annually, the Compensation Committee reviews reports related to industry trends, legislative and regulatory developments, and compliance requirements based on management’s analysis and guidance provided by Pay Governance, as applicable. Plan revisions and compensation program design changes are implemented as needed.

Risk Assessment

The Compensation Committee also seeks to structure compensation that will provide sufficient incentives for the executive officers to drive results while avoiding unnecessary or excessive risk taking that could harm the long-term value of the Company. The Compensation Committee believes that the following actions and/or measures help achieve this goal:

• the Compensation Committee reviews the design of the executive compensation program to ensure an appropriate balance between business risk and resulting compensation;

• the Compensation Committee allocates pay mix between base salary and performance-based pay to provide a balance of incentives;

• the design of the incentive measures is structured to align management’s actions with the interests of the investors;

• incentive payments are dependent on the Company’s performance measured against pre-established targets and goals and/or compared to the performance of companies in the Peer Group;

• the range and sensitivity of potential payouts relative to target performance are reasonable;

• the Compensation Committee imposes checks and balances on the payment of compensation discussed herein;

• detailed processes establish the Company’s financial performance measures under its incentive plans; and

• incentive targets are designed to be challenging, yet achievable, to mitigate the potential for excessive risk-taking behaviors.

IRC Section 409A

IRC Section 409A generally was effective as of January 1, 2005. The section substantially modified the rules governing the taxation of nonqualified deferred compensation. The consequences of a violation of IRC Section 409A, unless corrected, are the immediate taxation of amounts deferred, the imposition of an excise tax and the assessment of interest on the amount of the income inclusion, each of which is imposed upon the recipient of the compensation. The plans, agreements and incentives subject to IRC Section 409A have been operated pursuant to and are in compliance with IRC Section 409A.

IRC Section 162(m)

IRC Section 162(m) limits to $1,000,000 the amount Cleco may deduct in a tax year for compensation paid to the CEO, CFO, and each of the four other most highly compensated executive officers.

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The Compensation Committee took actions considered appropriate to preserve the deductibility of compensation paid to executive officers, but the Compensation Committee did not adopt a formal policy that required all compensation to be fully deductible. As a result, the Compensation Committee may have paid or awarded compensation that it deemed necessary or appropriate to achieve our business goals and to align the interests of our executives with those of Cleco’s investors, whether or not the compensation was fully deductible under IRC Section 162(m).

Executive Officers’ Compensation

Summary Compensation Table

NAME AND PRINCIPAL POSITION	YEAR	SALARY ($)	BONUS ($)	NON-EQUITY INCENTIVE PLAN COMPENSATION ($)	​	CHANGE IN PENSION VALUE AND NONQUALIFIED DEFERRED COMPENSATION EARNINGS ($)(1)	ALL OTHER COMPENSATION ($)	TOTAL ($)
A	B	C	D	E	​	F	G	H
William G. Fontenot, President & CEO	2019	$639,616	$345,000	$1,171,839	​	$1,402,994	$17,293	$3,576,742
	2018	$552,885	$0	$819,412	​	$0	$12,921	$1,385,218
	2017	$362,904	$0	$475,460	​	$2,552,193	$13,681	$3,404,238
Kazi K. Hasan, CFO	2019	$400,008	$0	$257,005	​	$0	$31,324	$688,337
	2018	$46,155	$0	$0	​	$0	$942	$47,097
					​
Julia E. Callis,(2) Former Chief Compliance Officer & General Counsel	2019	$282,923	$67,500	$479,222	​	$544,561	$13,762	$1,387,968
	2018	$268,846	$0	$486,712	​	$0	$13,616	$769,174
	2017	$253,462	$0	$285,550	​	$439,225	$20,292	$998,529
					​
Anthony L. Bunting, Chief Transformation Officer	2019	$292,523	$61,500	$465,619	​	$598,968	$21,262	$1,439,872
	2018	$245,389	$0	$452,027	��	$886,982	$18,806	$1,603,204
	2017	$237,431	$0	$293,520	​	$562,686	$11,712	$1,105,349
					​
Robert R. LaBorde Jr., Chief Operations Officer	2019	$261,539	$60,000	$363,152	​	$519,366	$12,703	$1,216,760
	2018	$239,231	$0	$356,506	​	$0	$28,490	$624,227
	2017	$229,385	$0	$197,844	​	$374,676	$13,705	$815,610
					​
Justin S. Hilton, President - Cleco Power	2019	$253,769	$107,500	$269,359	​	$381,155	$7,033	$1,018,816

(1)
Amounts in this column include the change in pension value year over year. For 2019, this amount includes the change in pension value from 2018 to 2019. Negative changes in the pension value year over year are reported as $0.

(2)
Ms. Callis resigned from Cleco effective March 13, 2020.

General

The Summary Compensation Table sets forth individual compensation information for the CEO, the CFO, and the four other most highly compensated executive officers of Cleco and its affiliates for services rendered in all capacities to Cleco and its affiliates during the fiscal years ended December 31, 2019, December 31, 2018, and December 31, 2017 (the “named executives” or “named executive officers”). Compensation components represent both payments made to the named executive officers during the year and other forms of compensation, as follows:

• Column C, “Salary;” Column D, “Bonus;” Column E, “Non-Equity Incentive Plan Compensation;” and Column G, “All Other Compensation” represent cash compensation earned by the named executive in 2019, 2018, or 2017.

• The amounts shown in Column F, “Change in Pension Value and Nonqualified Deferred Compensation Earnings,” represent changes in the actuarial value of accrued benefits during 2019, 2018, and 2017

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under the Pension Plan and SERP, as applicable. Actuarial value computations are based on assumptions discussed in “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 10 — Pension Plan and Employee Benefits.” The 2019 changes shown in Column F are due in part to the actuarial impact from a decrease in the discount rate used to calculate future benefits under the Pension Plan and SERP. Negative changes, if any, are reported as zero. This compensation will be payable to the named executive in future years, generally as post-employment retirement payments.

Salary

Data in Column C includes pay for time worked, as well as pay for time not worked, such as vacation, sick leave, jury duty, bereavement, and holidays. The salary level of each of the named executives is determined by a review of market data for companies comparable in size and scope to Cleco, as discussed under “— Compensation Discussion and Analysis — Decisions Made in 2019 with Regard to Each Compensation and Benefit Component — Base Salary.” In some instances, merit lump sum payments are used to recognize positive performance when base pay has reached or exceeded the Company’s base pay policy target, and are included in the salary column. Deferral of 2019, 2018, and 2017 base pay made by Mr. Fontenot and Mr. LaBorde, and of 2019 base pay made by Mr. Hasan, pursuant to the Deferred Compensation Plan also is included in the salary column and is further detailed in the “Nonqualified Deferred Compensation” table. Adjustments to base pay are recommended to the Compensation Committee typically on an annual basis, and if approved, usually are implemented in January. Base salary changes made in 2019 for our named executives and the reasons for those changes are discussed in “— Compensation Discussion and Analysis — Decisions Made in 2019 with Regard to Each Compensation and Benefit Component — Base Salary.”

Bonus

Column D, “Bonus” includes non-plan-based, discretionary incentives earned during 2019, 2018, or 2017. Amounts in this column for 2019 represent special awards made to the named executive officers for completion of the Cleco Cajun Transaction. No such awards were earned in 2018 and 2017 by the named executive officers.

Non-Equity Incentive Plan Compensation

Column E, “Non-Equity Incentive Plan Compensation” contains cash awards earned during 2019 that were paid in March 2020 under the STIP; earned during 2018 and paid in March 2019 under the STIP; and earned during 2017 and paid in March 2018 under the STIP. Deferral of annual cash incentive payments made by Mr. Fontenot and Mr. LaBorde pursuant to the Deferred Compensation Plan also is included in Column E and is further detailed in the “Nonqualified Deferred Compensation” table. Column E also includes cash awards earned during 2019 that were paid in March 2020 and earned during 2018 that were paid in March 2019 for the LTIP performance periods ended December 31, 2019, and December 31, 2018, respectively.

Change in Pension Value and Nonqualified Deferred Compensation Earnings

The values in Column F represent the aggregate increase in the actuarial present value of benefits earned by each named executive officer during 2019, 2018, and 2017 under the Pension Plan and SERP, including SERP’s supplemental death benefit provision. These values do not represent cash received by the named executives in 2019, 2018, and 2017; rather, these amounts represent the present value of future retirement payments we project will be made to each named executive. Changes in the present value of the Pension Plan and SERP benefits from December 31, 2018, to December 31, 2019; from December 31, 2017 to December 31, 2018; and from December 31, 2016, to December 31, 2017, result from an additional year of earned service, compensation changes and the increase (or decrease) in value caused by the change in the discount rate used to compute present value. (Generally, a decrease in the discount rate will increase the present value of benefits and an increase in the discount rate will decrease the present value.) If the discount rate increases by a large enough amount, it can cause the accrued pension and SERP liability to decline versus the prior year. When this occurs, the values reported for Column F are zero.

The present value of the accumulated benefit obligation for each named executive officer is included in the table, “Pension Benefits.” These values are reviewed by the Compensation Committee in conjunction with its annual tally sheet analysis. An explanation of why the Company uses SERP and its relationship to other compensation elements can be found in “Decisions Made in 2019 With Regard to Each Compensation and Benefit Component.”

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Column F also would include any above-market or preferential earnings on deferred compensation paid by the Company. There were no such preferential earnings paid by the Company in 2019, 2018, and 2017.

All Other Compensation

Payments made to or on behalf of our named executive officers in Column G, “All Other Compensation,” include the following:

• Contributions by Cleco under the 401(k) Plan on behalf of the named executive officers;

• Term life insurance premiums paid for the benefit of the named executive officers;

• Spousal travel;

• For 2019, for Mr. Hasan, moving expenses reimbursed by the Company; and

• Federal Insurance Contributions Act (“FICA”) tax due currently and paid by the Company on the annual increase in the named executive officers’ future SERP benefits.

The value of the Column G items for 2019 for each named executive officer is as follows:

	MR. FONTENOT	MR. HASAN	MS. CALLIS	MR. BUNTING	MR. LABORDE	MR. HILTON
Cleco Contributions to 401(k) Plan	$11,200	$16,000	$12,918	$9,554	$12,141	$6,515
Taxable Group Term Life Insurance	830	158	350	1,382	350	350
Spousal Travel	5,263	145	0	0	0	168
Moving Expenses	0	15,021	0	0	0	0
FICA Tax on SERP	0	0	494	10,325	211	0
Total Other Compensation	$17,293	$31,324	$13,762	$21,261	$12,702	$7,033

		ESTIMATED FUTURE PAYMENTS UNDER NON-EQUITY INCENTIVE PLAN AWARDS (STIP)			ESTIMATED FUTURE PAYMENTS UNDER NON-EQUITY INCENTIVE PLAN AWARDS (2019-2021 LTIP GRANT)
NAME	GRANT DATE	THRESHOLD ($)	TARGET ($)	MAXIMUM ($)	THRESHOLD ($)	TARGET ($)	MAXIMUM ($)
A	B	C	D	E	F	G	H
Mr. Fontenot	01/01/19	$0	$650,000	$1,300,000	$0	$1,500,000	$3,000,000
Mr. Hasan	01/01/19	$0	$200,000	$400,000	$0	$440,000	$880,000
Ms. Callis	01/01/19	$0	$142,500	$285,000	$0	$313,500	$627,000
Mr. Bunting	01/01/19	$0	$150,000	$300,000	$0	$330,000	$660,000
Mr. LaBorde	01/01/19	$0	$132,500	$265,000	$0	$291,500	$583,000
Mr. Hilton	01/01/19	$0	$130,000	$260,000	$0	$286,000	$572,000

General

The target values for each of the Company’s incentive plans — the STIP and the LTIP — are determined as part of the Compensation Committee’s review of executive officer compensation. The Compensation Committee’s review, supported by data prepared by Pay Governance, includes comparisons of base salary and annual and long-term incentive levels of Cleco executive officers versus the Comparator Group as detailed in “— Compensation Discussion and Analysis — Evaluation and Design of the Compensation and Benefit Programs.” Targets for both the STIP and the LTIP are set as a percentage of base salary and stated in their dollar equivalent in the table above.

Estimated Future Payments under Non-Equity Incentive Plan Awards (STIP)

See “— Compensation Discussion and Analysis — Decisions Made in 2019 with Regard to Each Compensation and Benefit Component — Annual Cash Incentive” for a discussion of our 2019 STIP award calculations.

Estimated Future Payments under Non-Equity Incentive Plan Awards (LTIP)

See “�� Compensation Discussion and Analysis — Decisions Made in 2019 with Regard to Each Compensation and Benefit Component — Long-Term Compensation” for a discussion of our grants made in 2019.

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Pension Benefits

NAME	PLAN NAME (s)	NUMBER OF YEARS OF CREDITED SERVICE (#)	PRESENT VALUE OF ACCUMULATED BENEFIT ($)	PAYMENTS DURING LAST FISCAL YEAR ($)
Mr. Fontenot	Cleco Corporate Holdings LLC Pension Plan	33	$2,016,802	$0
	Cleco Corporation SERP	33	$4,563,348	$0
Mr. Hasan(1)	Cleco Corporate Holdings LLC Pension Plan	0	$0	$0
	Cleco Corporation SERP	0	$0	$0
Ms. Callis(2)	Cleco Corporate Holdings LLC Pension Plan	0	$0	$0
	Cleco Corporation SERP	12	$2,229,935	$0
Mr. Bunting	Cleco Corporate Holdings LLC Pension Plan	27	$1,848,982	$0
	Cleco Corporation SERP	27	$3,345,583	$0
Mr. LaBorde(3)	Cleco Corporate Holdings LLC Pension Plan	16	$609,978	$0
	Cleco Corporation SERP	11	$1,758,151	$0
Mr. Hilton(4)	Cleco Corporate Holdings LLC Pension Plan	30	$1,438,362	$0
	Cleco Corporation SERP	0	$0	$0

(1)
Mr. Hasan is not a participant in the SERP or the Pension Plan as he was hired after both plans were closed to new participants.

(2)
Ms. Callis is not a participant in the Pension Plan as she was hired after the plan was closed to new participants.

(3)
Mr. LaBorde has prior years of service credit under the Pension Plan. He is not currently a participant in the Pension Plan because he was rehired after the Pension Plan was closed to new participants in 2007.

(4)
Mr. Hilton is not a participant in the SERP as his appointment to his current position was after the plan was closed to new participants.

General

The Company provides executive officers who meet certain tenure requirements benefits from the Pension Plan and SERP. Vesting in the Pension Plan requires five years of service with the Company. With the exception of Mr. Hasan and Ms. Callis, each of the named executive officers is fully vested in the Pension Plan. Mr. Hasan and Ms. Callis, having been hired after August 1, 2007, were not eligible to participate in the Pension Plan and were included in an enhanced 401(k) Plan for those employees hired on or after August 1, 2007. Mr. LaBorde is fully vested in the Pension Plan based on previous service with the Company. Having been rehired after August 1, 2007, he was no longer eligible to participate in the Pension Plan and was included in an enhanced 401(k) Plan for those employees hired (or rehired) on or after August 1, 2007.

Vesting in SERP requires ten years of service. Under the terms of SERP, automatic vesting occurs upon a Change in Control if a participating executive is involuntarily terminated from the Company. Mr. Fontenot, Ms. Callis, Mr. Bunting, and Mr. LaBorde are all fully vested in the SERP based on years of service. Mr. Hasan and Mr. Hilton are not participants in the SERP.

The present value of each of the named executive officer’s accumulated benefit values was actuarially calculated and represents the values as of December 31, 2019. These calculations were made using the projected unit credit method for valuation purposes and a discount rate of 3.43%. Other material assumptions relating to the valuation include use of the Pri-2012 Employee and Healthy Retiree gender distinct mortality tables projected generationally using Scale MP-2019 (using White Collar for SERP present values and no collar for qualified plan present values), assumed retirement at age 65 and retirement payments in the form of joint and 100% survivor with 10 years certain payment.

The sum of the change in actuarial value of the Pension Plan during 2019 and the change in value of SERP is included in Column F, “Change in Pension Value and Nonqualified Deferred Compensation Earnings,” in the Summary Compensation Table. Negative changes, if any, are reported as zero.

Pension Plan

The Cleco Corporate Holdings LLC Pension Plan, restated effective May 10, 2017, is a defined benefit plan funded entirely by employer contributions. Effective August 1, 2007, the Pension Plan was closed to new participants. Employees hired or rehired on or after August 1, 2007 are eligible to participate in an enhanced 401(k) Plan. Mr. Fontenot, Mr. Bunting, and Mr. Hilton were hired prior to August 1, 2007.

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Benefits under the Pension Plan are determined by years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last ten years of employment. Earnings include base pay, cash incentives, merit lump sums, imputed income with respect to life insurance premiums paid by the Company, pre-tax contributions to the 401(k) Plan, salary and bonus deferrals to the Deferred Compensation Plan, and any other form of payment taxable under IRC Section 3401(a). Earnings exclude reimbursement of expenses, gifts, severance pay, moving expenses, outplacement assistance, relocation allowances, welfare benefits, benefits accrued (other than salary and bonus deferrals) or paid pursuant to the Deferred Compensation Plan, the value of benefits accrued or paid (including dividends) under the LTIP, income from the exercise of stock options and income from disqualifying stock dispositions. For 2019, the amount of earnings was further limited to $280,000 as prescribed by the IRS.

The formula for calculating the defined benefit under the Pension Plan is as follows:

1.
Defined Benefit = Annual Benefit + Supplement Benefit

2.
Annual Benefit = Final Average Earnings × Years of Service × Pension Factor

3.
Supplement Benefit = (Final Average Earnings - Social Security Covered Compensation) × Years of Service × .0065

The pension factor varies with the retirement year. For 2019, the applicable factor was 1.25%. Social Security-covered income is prescribed by the IRS based on the year of birth.

Benefits from the Pension Plan are generally paid at normal, late or early retirement dates and are subject to a limit prescribed by the IRS, generally $225,000 in 2019. Normal retirement at age 65 entitles the participant to a full pension. A participant may elect to delay retirement past age 65 as long as he/she is actively employed. Years of service continue to accumulate (up to a maximum of 35) and earnings continue to count toward the final earnings calculation. If a participant chooses to retire after age 55 but before normal retirement age, the amount of the annual pension benefit is reduced by 3% per year between ages 55 and 62. For example, the normal pension benefit at age 55 is reduced by 21%.

SERP

SERP is designed to provide retirement income of 65% of an executive officer’s final compensation at normal retirement, age 65. Final compensation under SERP is based on the sum of the highest annual salary paid during the five years prior to termination of employment and the average of the three highest pay-for-performance (PFP) plans or STIP awards paid to the participant during the preceding 60 months. Final compensation also is determined without regard to the IRS limit on compensation. SERP benefit rate at normal retirement is reduced by 2% per year for each year a participant retires prior to age 65, with a minimum benefit rate of 45% at age 55. The final benefit rate also may be reduced further if a participant separates from service prior to age 55. This actuarially determined reduction factor is equivalent to that used in our Pension Plan, which is 3% for each year from age 55 to 62. For example, if a SERP participant were to terminate service at age 50 and start receiving his or her SERP benefit at age 55, his or her SERP benefit rate would be 35.6%. This is the product of the minimum SERP benefit of 45% reduced by another 21% for early commencement. The actual SERP benefit payments are reduced if a participant is to receive benefit payments from our Pension Plan, has received certain employer contributions related to the 401(k) Plan and/or is eligible to receive retirement-type payments from former employers and subsequent employers, if applicable.

SERP provides survivor benefits, which are payable to a participant’s surviving spouse or other beneficiary. SERP also contains a supplemental death benefit that was added in 1999 to reflect market practice. If a SERP participant dies while actively employed, the amount of the supplemental death benefit is equal to the sum of two times the participant’s annual base salary as of the date of death and the participant’s target bonus payable under the annual incentive plan for the year in which death occurs. If a participant dies after termination of employment, the supplemental benefit is equal to the sum of the participant’s final annual base salary and target bonus payable under the annual incentive plan for the year in which the participant retired or otherwise terminated employment. The supplemental death benefit is not dependent on years of service.

In July 2014, Cleco Corporation’s Board of Directors closed SERP to new participants. In August 2016, the Company’s Board of Managers voted to freeze salary and bonus components used in the final compensation calculation as of December 31, 2017, for two current participants, Ms. Callis and Mr. LaBorde. In December

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2017, the Company entered into an employment agreement with Mr. Fontenot as its CEO, the terms of which amended the calculation of Mr. Fontenot’s SERP benefit to include a fixed benefit depending upon the year Mr. Fontenot separates from the Company. In May 2018, the Company amended the calculation of Mr. Bunting’s SERP benefit to include a predetermined benefit depending on the year that Mr. Bunting separates from the Company. With regard to former employees or their beneficiaries, all terms of SERP will continue.

Estimated Annual Payments

The following table shows the estimated annual payments at age 55 (or actual attained age if greater than 55) to each of the named executives under the Pension Plan and SERP as of December 31, 2019. Amounts shown for former executives reflect actual payments.

	ESTIMATED PAYMENTS AT 55 (OR ACTUAL ATTAINED AGE IF GREATER THAN 55)
	PENSION	SERP	TOTAL
Mr. Fontenot	$110,379	$109,621	$220,000
Mr. Hasan	$0	$0	$0
Ms. Callis	$0	$112,036	$112,036
Mr. Bunting	$97,134	$112,866	$210,000
Mr. LaBorde	$40,020	$61,478	$101,498
Mr. Hilton	$93,386	$0	$93,386

Nonqualified Deferred Compensation

NAME	EXECUTIVE OFFICER CONTRIBUTIONS IN 2019 ($)(1)	COMPANY CONTRIBUTIONS IN 2019 ($)	AGGREGATE EARNINGS IN 2019 ($)(2)	AGGREGATE WITHDRAWALS / DISTRIBUTIONS IN 2019 ($)	AGGREGATE BALANCE AT DECEMBER 31, 2019 ($)(3)
A	B	C	D	E	F
Mr. Fontenot	$239,481	$0	$251,007	$0	$1,625,061
Mr. Hasan	$10,000	$0	$877	$0	$10,877
Ms. Callis	$0	$0	$0	$0	$0
Mr. Bunting	$0	$0	$0	$0	$0
Mr. LaBorde	$37,727	$0	$84,215	$0	$523,513
Mr. Hilton	$0	$0	$0	$0	$0

(1)
The amounts in Column B represent deferrals of salary and non-equity incentive compensation payments made to the named executive officers during 2019 and are included in the amounts shown in Columns C and G, respectively, of the Summary Compensation Table.

(2)
The aggregate earnings shown in Column D are not included in the Summary Compensation Table. Negative returns are reflected as zero.

(3)
The aggregate balances shown in Column F include amounts reported as salary and non-equity incentive compensation payments in the Summary Compensation Table for the current fiscal year, as well as previous years and the earnings on those amounts.

Deferred Compensation

Named executives and other key employees are eligible to participate in the Company’s Deferred Compensation Plan. Participants are allowed to defer up to 50% of their base salary and up to 100% of their annual cash incentive, as reported in Columns C and G in the Summary Compensation Table. Consequently, the executive officer contributions listed in Column B above are made by the participant and not by Cleco. Mr. Fontenot, Mr. Hasan, and Mr. LaBorde elected to participate in the Deferred Compensation Plan during 2019. All deferral elections for 2019 were made prior to the beginning of 2019 as required by the regulations under IRC Section 409A. There are no matching contributions made by the Company.

Deferrals become general funds for use by the Company to be repaid to the participant at a pre-specified date. Short-term deferrals may be paid out as early as five years following the end of the plan year (i.e., the year in which compensation was earned). Retirement deferrals are paid at the later of termination of service or the attainment of an age specified by the participant. A bookkeeping account is maintained for each participant that records deferred salary and/or bonus, as well as earnings on deferred amounts. Earnings are determined by the

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performance of notional investment alternatives, which are similar to the investments available under the 401(k) Plan. Participants select which of these alternatives will be used to determine the earnings on their own accounts. The Deferred Compensation Plan is not intended to provide for the payment of above-market or preferential earnings (as these terms are defined under the SEC regulations) on compensation deferred under the plan. As such, the Deferred Compensation Plan does not provide a guaranteed rate of return.

Potential Payments at Termination or Change in Control

The following tables “Potential Payments at Termination or Change in Control” detail the estimated value of payments and benefits provided to each of our named executive officers assuming the following separation events occurred as of December 31, 2019: termination by the executive; disability; death; retirement; constructive termination; termination by the Company for cause; and termination in connection with a Change in Control. The Company has selected these events based on long-standing provisions in our employee benefit plans such as the Pension Plan and 401(k) Plan, or because their use is common within the industry and Comparator Group. Some of the potential severance payments are governed by the separate documents establishing the STIP, LTIP, and SERP.

At its October 2011 meeting, Cleco Corporation’s Compensation Committee approved the Executive Severance Plan to provide severance benefits to executive officers. In October and December 2014 and July 2015, Cleco Corporation’s Compensation Committee approved amendments to the Executive Severance Plan. At December 31, 2019, all of the named executive officers were covered by the Executive Severance Plan.

The following narrative describes the type and form of payments and benefits for each separation event. The tables under “Potential Payments at Termination or Change in Control” provide an estimate of potential payments and benefits to each named executive officer under each separation event. Throughout this section, reference to “executive officers” is inclusive of named executive officers.

Termination by the Executive

If an executive officer resigns voluntarily, no payments are made or benefits provided other than those required by law.

Disability

Annual disability benefits are payable when a total and permanent disability occurs and are paid until the executive officer’s normal retirement age, which is age 65. This benefit is provided under SERP and is paid regardless of whether the executive was vested in SERP at the time of disability. At age 65, a disabled executive is eligible to receive annual retirement benefits under the Pension Plan, for those who are participants, and SERP as outlined under the headings “Pension Plan” and “SERP,” respectively. The executive officer also is eligible to receive a one-time, prorated share of the current year’s STIP award and a prorated award for each LTIP performance cycle in which he/she participates to the extent those performance cycles award at their completion.

Death

A prorated share of the current year’s STIP award and a supplemental death benefit provided from SERP are paid to an executive officer’s designated beneficiary in the event of death in service. Both are one-time payments. The executive officer’s designated beneficiary also is eligible to receive a prorated award for each LTIP performance cycle in which the executive officer participates to the extent those performance cycles award at their completion.

Annual survivor benefits are payable to an executive officer’s surviving spouse for his/her life, or if there is no surviving spouse, to the executive officer’s designated beneficiary for a period of ten years or, if no designated beneficiary is named, to the executive officer’s estate for a period of ten years. Amounts are calculated under the provisions of the Pension Plan and SERP. Please see the discussion under the headings “Pension Plan” and “SERP,” respectively, as well as SERP provisions relating to death while in service. Survivor benefits are paid from SERP regardless of vested status in SERP at the time of death. The SERP supplemental death benefit is paid only to executives who were employed by the Company on or after December 17, 1999. All of our named executives are eligible for the death benefit.

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Retirement

In the event of early or normal retirement, the executive officer is eligible to receive a prorated share of the current year’s STIP award and at least a prorated award for each LTIP performance cycle in which he/she participates to the extent those performance cycles award at their completion. Retirement benefits are provided pursuant to the Pension Plan and SERP. Payments are made monthly and are calculated using the assumptions described in the discussion following the “Pension Benefits” table.

Constructive Termination

Payments made and benefits provided upon a constructive termination are ordinarily greater than payments made on account of an executive officer’s retirement, death or disability because separation effectively is initiated by the Company. Certain payments are made contingent upon the execution of a waiver, release and covenants agreement in favor of the Company. Constructive termination also may be initiated by an executive officer if there has been (i) a material reduction in his/her base compensation, other than a reduction uniformly applicable to all executive officers; and (ii) a contemporaneous, material reduction in his/her authority, job duties, or responsibilities.

Under the terms of the Executive Severance Plan, an executive would receive constructive termination payments including up to 52 weeks of base compensation, up to $50,000 in lieu of outplacement services and reimbursement of premiums paid to maintain coverage under our medical plan for up to 18 months. The executive also would be eligible for a prorated portion of the current year’s payout under the STIP and a prorated award for the LTIP performance cycles in which he/she participates to the extent those performance cycles award at their completion.

If the executive officer has vested retirement benefits and has attained eligible retirement age, he/she would receive retirement benefits as described under “Pension Benefits.”

Termination for Cause

“Cause” is defined as an executive’s (i) intentional act of fraud, embezzlement or theft in the course of employment or other intentional misconduct that is materially injurious to the Company’s financial condition or business reputation; (ii) intentional damage to Company property, including the wrongful disclosure of its confidential information; (iii) willful and intentional refusal to perform the essential duties of his/her position; (iv) failure to fully cooperate with government or independent agency investigations; (v) conviction of a felony or crime involving moral turpitude; (vi) willful, reckless, or negligent violation of the material provisions of Cleco’s Code of Conduct; (vii) intentional, reckless, or intentional acts or failures to act in a manner which materially compromises his/her ability to perform the essential duties of his/her position; or (viii) willful, reckless, or negligent violation of rules related to the Sarbanes-Oxley Act or rules adopted by the SEC. No payments, other than those required by law, are made or benefits provided under the Executive Severance Plan if an executive officer is terminated for cause. If an executive officer is vested in SERP, that benefit is forfeited. The value of that forfeiture is shown as a negative number in the separation payments tables.

Change in Control

The term “Change in Control” is defined in the LTIP. One or more of the following triggering events constitute a Change in Control:

• Any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), other than the Company or an affiliate or any “person” who on the effective date of this plan is a director, officer, or is the “beneficial owner” (as determined in Rule 13d-3 promulgated under the Exchange Act) of 20% or more of the combined voting power of outstanding securities of the Company or an employee stock ownership plan (within the meaning of IRC Section 4975(e)(7)) sponsored by the Company or an affiliate, is or becomes the “beneficial owner” (as determined in Rule 13d-3 promulgated under the Exchange Act) of 80% or more of the combined voting power of the outstanding securities of the Company;

• The Company is party to a merger or consolidation with another entity and, as a result of such transaction, 80% or more of the combined voting power of outstanding securities of the Company or its successor in the merger (or a direct or indirect parent company of the Company or its successor in the merger) is owned in the aggregate by persons who were not “beneficial owners” (as determined in Rule 13d-3 promulgated under the Exchange Act) of securities of the Company immediately before such transaction;

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• The Company sells, leases, or otherwise disposes of, in one transaction or in a series of related transactions, all or substantially all of its assets;

• The owners of the Company approve a plan of dissolution or liquidation; or

• All or substantially all of the assets or the issued and outstanding membership interests of Cleco Power is sold, leased or otherwise disposed of in one or a series of related transactions to a person, other than the Company or an affiliate.

Except as described below, payments are made and benefits provided only if an executive’s employment is terminated during the 60-day period preceding or the 24-month period following the Change in Control.

Termination must be involuntary and by the Company without cause or initiated by the executive on account of “Good Reason.” Good reason means that (i) a participant’s base compensation in effect immediately before the commencement of a Change in Control Period (as such term is defined in the LTIP) is materially reduced, or there is a material reduction or termination of such participant’s rights to any employee benefit in effect immediately prior to such period; (ii) a participant’s authority, duties or responsibilities are materially reduced from those in effect immediately before the commencement of a Change in Control Period, or such participant has reasonably determined that, as a result of a change in circumstances that materially affects his or her employment with the Company, he or she is unable to exercise the authority, power, duties and responsibilities assigned to him or her immediately before the commencement of such period; or (iii) a participant is required to transfer to an office or business location that is more than 60 miles from the primary location to which he or she was assigned prior to the commencement of a Change in Control Period. No event or condition shall constitute Good Reason hereunder unless (a) a participant provides to the Committee written notice of his or her objection to such event not later than 60 days after such participant first learns, or should have learned, of such event; (b) such event is not corrected by the Company promptly after receipt of such notice, but in no event more than 30 days after receipt thereof; and (c) such participant Separates from Service (as such term is defined in the LTIP) not more than 15 days following the expiration of the 30-day period described in clause (b) hereof. The executive also must satisfy the conditions included in the waiver, release and covenants agreement defined in the Executive Severance Plan.

Under the Executive Severance Plan, an executive would receive an amount up to two times the sum of annualized base salary and the average non-equity incentive plan bonus over the last three fiscal years and reimbursement of COBRA premiums for up to 24 months. Payments may also include the purchase of the executive officer’s primary residence and reimbursement of relocation expenses, but only if the executive relocates his/her primary residence more than 100 miles. No excise tax payments or gross-ups are made; instead, benefits will be reduced to avoid the imposition of the tax. The numbers shown below do not give effect to this reduction.

Subject to the conditions described above, upon a Change in Control, SERP benefits are: (i) fully vested; (ii) increased by adding three years to an affected executive’s age, subject to a minimum benefit of 50% of compensation; and (iii) subject to a modified actuarial reduction determined by increasing the executive’s age by three years.

If an executive officer is vested and of eligible retirement age, he or she may become eligible to begin to receive the annual retirement benefit described above upon a Change in Control.

The following tables set forth the value of post-employment payments and benefits that are not generally made available to all employees. Each separation event is assumed to occur on December 31, 2019. Retirement is assumed to occur at age 55 or the named executive officer’s actual attained age if greater than 55. Estimated payments under our STIP and LTIP for disability, death, retirement and constructive termination are uncertain until the completion of the performance period/cycle. In the case of the STIP, the performance period is the current fiscal year. The estimated payment for the home purchase and relocation is a projection of the expense to the Company to sell the named executive officer’s principal residence including any loss avoided by the named executive officer by having the right to sell the residence to the Company, plus the projected cost to the Company to relocate the named executive officer.

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Pursuant to Item 401(j) of Regulation S-K, the separation events disclosed in this prospectus are assumed to occur in the past, as of December 31, 2019.

Mr. Fontenot
VALUE OF PAYMENT/BENEFIT	TERMINATION BY EXECUTIVE	DISABILITY	DEATH	RETIREMENT	CONSTRUCTIVE TERMINATION	TERMINATION FOR CAUSE	CHANGE IN CONTROL
Cash Severance	$0	$0	$0	$0	$650,000	$0	$1,845,349
Annual Cash Bonus	$0	$821,907	$821,907	$821,907	$821,907	$0	$0
Long-Term Incentive	$0	$1,683,265	$1,683,265	$1,683,265	$1,683,265	$0	$3,099,932
Cash Payment in Lieu of Outplacement Services	$0	$0	$0	$0	$50,000	$0	$0
Present Value of Incremental SERP Payments(1)	$0	$886,726	$3,239,523	$0	$0	$(2,267,297)	$1,944,376
SERP Supplemental Death Benefit	$0	$0	$1,661,540	$0	$0	$0	$0
Purchase of Principal Residence/ Relocation	$0	$0	$0	$0	$0	$0	$83,500
COBRA Medical Coverage	$0	$0	$0	$0	$34,990	$0	$46,653
Total Incremental Value	$0	$3,391,898	$7,406,235	$2,505,172	$3,240,162	$(2,267,297)	$7,019,810

(1)
As of December 31, 2019, Mr. Fontenot was vested in SERP payments, which would be forfeited upon termination for cause.

Mr. Hasan
VALUE OF PAYMENT/BENEFIT	TERMINATION BY EXECUTIVE	DISABILITY	DEATH	RETIREMENT(1)	CONSTRUCTIVE TERMINATION	TERMINATION FOR CAUSE	CHANGE IN CONTROL
Cash Severance	$0	$0	$0	$0	$400,000	$0	$800,000
Annual Cash Bonus	$0	$257,005	$257,005	$0	$257,005	$0	$0
Long-Term Incentive	$0	$146,667	$146,667	$0	$146,667	$0	$440,000
Cash Payment in Lieu of Outplacement Services	$0	$0	$0	$0	$25,000	$0	$0
Present Value of Incremental SERP Payments	$0	$0	$0	$0	$0	$0	$0
SERP Supplemental Death Benefit	$0	$0	$0	$0	$0	$0	$0
Purchase of Principal Residence/Relocation Expenses	$0	$0	$0	$0	$0	$0	$83,500
COBRA Medical Coverage	$0	$0	$0	$0	$34,990	$0	$46,653
Total Incremental Value	$0	$403,672	$403,672	$0	$863,662	$0	$1,370,153

(1)
As of December 31, 2019, Mr. Hasan was not eligible for retirement.

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Ms. Callis (1)
VALUE OF PAYMENT/BENEFIT	TERMINATION BY EXECUTIVE	DISABILITY	DEATH	RETIREMENT(2)	CONSTRUCTIVE TERMINATION	TERMINATION FOR CAUSE	CHANGE IN CONTROL
Cash Severance	$0	$0	$0	$0	$285,000	$0	$830,461
Annual Cash Bonus	$0	$181,779	$181,779	$0	$181,779	$0	$0
Long-Term Incentive	$0	$599,943	$599,943	$0	$599,943	$0	$907,943
Cash Payment in Lieu of Outplacement Services	$0	$0	$0	$0	$25,000	$0	$0
Present Value of Incremental SERP Payments(3)	$0	$1,473,252	$976,101	$0	$0	$(2,155,924)	$414,080
SERP Supplemental Death Benefit	$0	$0	$734,713	$0	$0	$0	$0
Purchase of Principal Residence/Relocation Expenses	$0	$0	$0	$0	$0	$0	$83,500
COBRA Medical Coverage	$0	$0	$0	$0	$20,322	$0	$27,096
Total Incremental Value	$0	$2,254,974	$2,492,536	$0	$1,112,044	$(2,155,924)	$2,263,080

(1)
Ms. Callis resigned from Cleco effective March 13, 2020.

(2)
As of December 31, 2019, Ms. Callis was not eligible for retirement.

(3)
As of December 31, 2019, Ms. Callis was vested in SERP payments, which would be forfeited upon termination for cause.

Mr. Bunting
VALUE OF PAYMENT/BENEFIT	TERMINATION BY EXECUTIVE	DISABILITY	DEATH	RETIREMENT	CONSTRUCTIVE TERMINATION	TERMINATION FOR CAUSE	CHANGE IN CONTROL
Cash Severance	$0	$0	$0	$0	$300,000	$0	$852,985
Annual Cash Bonus	$0	$187,947	$187,947	$187,947	187,947	$0	$0
Long-Term Incentive	$0	$568,072	$568,072	$568,072	568,072	$0	$878,272
Cash Payment in Lieu of Outplacement Services	$0	$0	$0	$0	25,000	$0	$0
Present Value of Incremental SERP Payments(1)	$0	$474,070	$1,699,756	$0	0	$(2,315,525)	$913,669
SERP Supplemental Death Benefit	$0	$0	$760,155	$0	0	$0	$0
Purchase of Principal Residence/Relocation Expenses	$0	$0	$0	$0	0	$0	$83,500
COBRA Medical Coverage	$0	$0	$0	$0	22,207	$0	$29,610
Total Incremental Value	$0	$1,230,089	$3,215,930	$756,019	$1,103,226	$(2,315,525)	$2,758,036

(1)
As of December 31, 2019, Mr. Bunting was vested in SERP payments, which would be forfeited upon termination for cause.

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Mr. LaBorde
VALUE OF PAYMENT/BENEFIT	TERMINATION BY EXECUTIVE	DISABILITY	DEATH	RETIREMENT(1)	CONSTRUCTIVE TERMINATION	TERMINATION FOR CAUSE	CHANGE IN CONTROL
Cash Severance	$0	$0	$0	$0	$265,000	$0	$798,475
Annual Cash Bonus	$0	$168,038	$168,038	$0	$168,038	$0	$0
Long-Term Incentive	$0	$420,281	$420,281	$0	$420,281	$0	$678,614
Cash Payment in Lieu of Outplacement Services	$0	$0	$0	$0	$25,000	$0	$0
Present Value of Incremental SERP Payments(2)	$0	$1,413,217	$1,287,704	$0	$0	$(1,168,675)	$381,752
SERP Supplemental Death Benefit	$0	$0	$652,154	$0	$0	$0	$0
Purchase of Principal Residence/Relocation Expenses	$0	$0	$0	$0	$0	$0	$83,500
COBRA Medical Coverage	$0	$0	$0	$0	$30,691	$0	$40,922
Total Incremental Value	$0	$2,001,536	$2,528,177	$0	$909,010	$(1,168,675)	$1,983,263

(1)
As of December 31, 2019, Mr. LaBorde was not eligible for retirement.

(2)
As of December 31, 2019, Mr. LaBorde was vested in SERP payments, which would be forfeited upon termination for cause.

Mr. Hilton
VALUE OF PAYMENT/BENEFIT	TERMINATION BY EXECUTIVE	DISABILITY	DEATH	RETIREMENT(1)	CONSTRUCTIVE TERMINATION	TERMINATION FOR CAUSE	CHANGE IN CONTROL
Cash Severance	$0	$0	$0	$0	$260,000	$0	$732,925
Annual Cash Bonus	$0	$142,111	$142,111	$0	$142,111	$0	$0
Long-Term Incentive	$0	$308,581	$308,581	$0	$308,581	$0	$542,248
Cash Payment in Lieu of Outplacement Services	$0	$0	$0	$0	$25,000	$0	$0
Present Value of Incremental SERP Payments	$0	$0	$0	$0	$0	$0	$0
SERP Supplemental Death Benefit	$0	$0	$0	$0	$0	$0	$0
Purchase of Principal Residence/Relocation Expenses	$0	$0	$0	$0	$0	$0	$83,500
COBRA Medical Coverage	$0	$0	$0	$0	$30,691	$0	$40,922
Total Incremental Value	$0	$450,692	$450,692	$0	$766,383	$0	$1,399,595

(1)
As of December 31, 2019, Mr. Hilton was not eligible for retirement.

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BOARD OF MANAGERS COMPENSATION

2019 Board of Managers Compensation

NAME(1)	FEES EARNED OR PAID IN CASH AND/OR STOCK ($)	TOTAL ($)
A	B	C
Rick Gallot	$146,676	$146,676
Randy Gilchrist	$146,676	$146,676
Peggy Scott	$226,683	$226,683
Melissa Stark	$3,750	$3,750
Bruce Wainer	$146,676	$146,676

(1)
Messrs. Chapman, Fronimos, Hanrahan, Leslie, Perry, Rubin, and Turner were appointed to the Boards by the Cleco Group and do not receive additional compensation for their service on the Boards.

General

Column B, “Fees Earned or Paid in Cash and/or Stock” represents cash compensation earned and/or received in 2019.

A non-management Board Manager may elect to participate in the Company’s Deferred Compensation Plan and defer the receipt of all or part of his or her fees. Benefits are equal to the amount credited to each Board Manager’s individual account based on compensation deferred plus applicable investment returns as specified by the director upon election to participate in the plan. Investment options are similar to those provided to participants in the 401(k) Plan. Funds may be reallocated between investments at the discretion of the Board Manager. Accounts, which may be designated separately by deferral year, are payable in the form of a single-sum payment or in the form of substantially equal annual installments, not to exceed 15, when a Board Manager ceases to serve on the Cleco’s Boards or attains a specified age.

Fees Earned or Paid in Cash and/or Stock

From January to May 2019, each Board Manager who is not a Cleco employee or appointed by the Cleco Group, except Ms. Stark, received an annual cash retainer of $140,000. Ms. Stark received an annual cash retainer of $3,750. During this period, the non-management Chair was compensated with an additional retainer of $75,000. Beginning in May 2019, each Board Manager who is not a Cleco employee or appointed by the Cleco Group received an annual cash retainer of $150,000, and the non-management Chair received an additional retainer of $82,500. Ms. Stark’s retainer remained set at $3,750.

Board Managers are permitted to defer receipt of their fees under the Company’s Deferred Compensation Plan. Messrs. Gallot and Gilchrist elected to defer all or a portion of their fees in 2019.

Cleco reimburses Board Managers for travel and related expenses incurred for attending meetings of Cleco’s Boards and Board committees, including travel costs for spouses/companions. During 2019, both Messrs. Wainer and Gilchrist incurred $60 of expenses for spousal/companion travel.

Cleco also provides its Board Managers who are not employed by Cleco or appointed by the Cleco Group with $200,000 of life insurance and permanent total disability coverage under a group accidental death and dismemberment plan maintained by Cleco Power. The total 2019 premium for all coverage (exempt employees, officers and Board Managers) under this plan was $6,128.

Interests of the Board of Managers

In 2019, no non-management member of Cleco’s Boards performed services for or received compensation from Cleco or its affiliates except for those services relating to his or her duty as a member of Cleco’s Boards.

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REPORT OF THE LEADERSHIP DEVELOPMENT AND COMPENSATION COMMITTEE

The Leadership Development and Compensation Committee of the Boards (see “Management — Boards of Managers of Cleco” and “Certain Relationships and Related Party Transactions, and Director Independence — Director Independence and Related Party Transactions”), includes four managers, one of whom meets the additional requirements for independence which were adopted by the Board. The Leadership Development and Compensation Committee operates under a written charter last revised in November 2019, a copy of which is posted on Cleco’s web site at https://www.cleco.com; About Us; Leadership; Board Committees. A copy of this charter also is available free of charge by request sent to: Public Relations, Cleco, P.O. Box 5000, Pineville, LA 71361-5000.

The Leadership Development and Compensation Committee was established in April 2016.

Based on the review and discussions referred to above, the Leadership Development and Compensation Committee recommended to the Company’s Boards that the Compensation Discussion and Analysis and related required compensation disclosure tables be included in the Company’s 2019 Form 10-K and filed with the SEC.

The Leadership Development and Compensation Committee of the Boards of Managers of Cleco Holdings and Cleco Power

Christopher Leslie, Chair
Andrew Chapman
Rick Gallot
Steven Turner

Leadership Development and Compensation Committee Interlocks and Insider Participation

The members of the Leadership Development and Compensation Committee are set forth above. No members of the Leadership Development and Compensation Committee were officers or employees of the Company or any of its subsidiaries during 2019, were former Company officers, or had any relationship otherwise requiring disclosure.

CEO Pay Ratio

The aggregate compensation of the executive who served in the CEO role in 2019 (Mr. Fontenot) was $3,576,742. This amount differs from the aggregate amount reflected in the Summary Compensation Table included in this prospectus because of the inclusion of the value of the Company’s contribution to health and welfare benefits. The median employee’s annual total compensation for 2019 was $115,582, calculated including the same components of total pay as was used for Mr. Fontenot. As a result, we estimate that the CEO’s 2019 annual total compensation was 30.9 times that of the median employee’s annual total compensation. The median employee was determined based on employees of the Company on December 31, 2019, using the consistently applied compensation measure of target total cash compensation (including base salary and target bonus). Target total cash compensation was annualized for those employees that were not employed for the full year of 2019.

We believe that the above pay ratio is a reasonable estimate calculated in a manner consistent with Item 402(u) of Regulation S-K. In addition, because the SEC rules for identifying the median employee allow companies to adopt a variety of methodologies, to apply certain exclusions, and to make reasonable estimates and assumptions that reflect their compensation practices, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies may have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Directors and Management and Certain Beneficial Owners

Following the closing of the 2016 Merger, there are no longer any outstanding shares of Cleco Corporation common stock.

Equity Compensation Plan Information

Cleco has no compensation plans under which equity securities are awarded.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS,
AND DIRECTOR INDEPENDENCE

Director Independence and Related Party Transactions

Cleco’s Board has adopted categorical standards to assist it in making determinations of its managers’ independence. These categorical standards are posted on Cleco’s web site at http://www.cleco.com; About Us; Leadership; Corporate Governance; Governance Guidelines. A copy of the standards is also available free of charge by request sent to: Public Relations, Cleco, P.O. Box 5000, Pineville, LA 71361-5000. Cleco’s Board has determined that Rick Gallot, Randy Gilchrist, Peggy Scott and Bruce Wainer are independent within the meaning of the categorical standards adopted by Cleco’s Board.

Cleco has no relationships to report under Item 407(a)(3) of Regulation S-K.

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THE EXCHANGE OFFER

Purpose and Effect of Exchange Offer

We issued and sold the Outstanding Notes on September 11, 2019 in an unregistered private placement to certain initial purchasers of the Outstanding Notes. As part of that private offering, we entered into a registration rights agreement with the initial purchasers. Under the registration rights agreement, we agreed to file the registration statement, of which this prospectus forms a part, to offer to exchange the Outstanding Notes for the Exchange Notes in an offering registered under the Securities Act. The exchange offer satisfies that obligation. We also agreed to perform other obligations under the registration rights agreement. See “Registration Rights Agreement.”

By participating in the exchange offer, holders of Outstanding Notes will receive Exchange Notes that are freely tradable and not subject to restrictions on transfer, subject to the exceptions described under “— Resale of Exchange Notes” immediately below. In addition, holders of Exchange Notes generally will not be entitled to additional interest.

Resale of Exchange Notes

We believe that the Exchange Notes issued in exchange for the Outstanding Notes may be offered for resale, resold and otherwise transferred by any new noteholder without compliance with the registration and prospectus delivery provisions of the Securities Act if the conditions set forth below are met. We base this belief solely on interpretations of the federal securities laws by the staff of the Division of Corporation Finance of the Commission set forth in several no-action letters issued to third parties unrelated to us. A no-action letter is a letter from the staff of the Division of Corporation Finance of the Commission responding to a request for the staff’s views as to whether it would recommend any enforcement action to the Division of Enforcement of the Commission with respect to certain actions being proposed by the party submitting the request. We have not obtained, and do not intend to obtain, our own no-action letter from the Commission regarding the resale of the Exchange Notes. Instead, holders will be relying on the no-action letters that the Commission has issued to third parties in circumstances that we believe are similar to ours. Based on these no-action letters, the following conditions must be met:

• the holder must acquire the Exchange Notes in the ordinary course of its business;

• the holder must have no arrangements or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act; and

• the holder must not be our “affiliate,” as that term is defined in Rule 405 of the Securities Act.

Each holder of Outstanding Notes that wishes to exchange Outstanding Notes for Exchange Notes in the exchange offer must represent to us that it satisfies all of the above listed conditions. Any holder who tenders to exchange Outstanding Notes for Exchange Notes in the exchange offer who does not satisfy all of the above listed conditions:

• cannot rely on the position of the Commission set forth in the no-action letters referred to above; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the Exchange Notes.

The Commission considers broker-dealers that acquired Outstanding Notes directly from us, but not as a result of market-making activities or other trading activities, to be making a distribution of the Exchange Notes if they participate in the exchange offer. Consequently, these holders must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the Exchange Notes.

Each broker-dealer that receives Exchange Notes for its own account in exchange for Outstanding Notes acquired by that broker-dealer as a result of market-making activities or other trading activities must deliver a prospectus in connection with a resale of the Exchange Notes and provide us with a signed acknowledgement of this obligation. A broker-dealer may use this prospectus, as amended or supplemented from time to time, in connection with resales of Exchange Notes received in exchange for Outstanding Notes where the broker-dealer acquired the Outstanding Notes as a result of market-making activities or other trading activities. The letter of transmittal states that by acknowledging and delivering a prospectus, a broker-dealer will not be considered to

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admit that it is an “underwriter” within the meaning of the Securities Act. We have agreed that for a period of 180 days after the expiration date of the exchange offer, we will make this prospectus available to broker-dealers for use in connection with any resale of the Exchange Notes.

Except as described in the prior paragraph, holders may not use this prospectus for an offer to resell, a resale or other retransfer of Exchange Notes. We are not making the exchange offer to, nor will we accept tenders for exchange from, holders of Outstanding Notes in any jurisdiction in which the exchange offer or the acceptance of it would not be in compliance with the securities or blue sky laws of that jurisdiction.

Terms of the Exchange

Upon the terms and subject to the conditions set forth in this prospectus and the accompanying letter of transmittal, which we refer to together in this prospectus as the “exchange offer,” we will accept any and all Outstanding Notes validly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date. We will issue, on or promptly after the expiration date, an aggregate principal amount of up to $300.0 million of Exchange Notes for a like principal amount of Outstanding Notes tendered and accepted in connection with the exchange offer. Holders may tender some or all of their Outstanding Notes in connection with the exchange offer, but only in denominations of $2,000 and integral multiples of $1,000. The exchange offer is not conditioned upon any minimum amount of Outstanding Notes being tendered for exchange.

The terms of the Exchange Notes are identical in all material respects to the terms of the Outstanding Notes, except that:

• we have registered the Exchange Notes under the Securities Act and therefore the Exchange Notes will not bear legends restricting their transfer; and

• specified rights under the registration rights agreement, including the provisions providing for payment of additional interest in specified circumstances relating to the exchange offer, will be limited or eliminated.

The Exchange Notes will evidence the same debt as the Outstanding Notes. The Exchange Notes will be issued under the same indenture and entitled to the same benefits under that indenture as the Outstanding Notes being exchanged. As of the date of this prospectus, $300.0 million in aggregate principal amount of the Outstanding Notes were outstanding. Outstanding Notes accepted for exchange in the exchange offer will be retired and cancelled and will not be reissued.

In connection with the issuance of the Outstanding Notes, we arranged for the Outstanding Notes originally purchased by qualified institutional buyers to be issued and transferable in book-entry form through the facilities of DTC, acting as depositary. Except as described under “— Book-Entry Transfer,” we will issue the Exchange Notes in the form of a global note registered in the name of DTC or its nominee, and each beneficial owner’s interest in it will be transferable in book-entry form through DTC.

Holders of Outstanding Notes do not have any appraisal or dissenters’ rights in connection with the exchange offer. We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Act, the Exchange Act and the rules and regulations of the Commission.

We will be considered to have accepted validly tendered Outstanding Notes if and when we have given written notice to that effect to the exchange agent. The exchange agent will act as agent for the tendering holders of Outstanding Notes for the purposes of receiving the Exchange Notes from us.

If we do not accept any tendered Outstanding Notes for exchange because of an invalid tender, the occurrence of the other events described in this prospectus or otherwise, we will return these Outstanding Notes, without expense, to the tendering holder as quickly as possible after the expiration date of the exchange offer.

Holders who tender Outstanding Notes will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes on exchange of Outstanding Notes in connection with the exchange offer. We will pay all charges and expenses, other than the applicable taxes described under “— Fees and Expenses” in connection with the exchange offer.

If we successfully complete the exchange offer, any Outstanding Notes which holders do not tender or which we do not accept in the exchange offer will remain outstanding and continue to accrue interest. The holders of Outstanding Notes after the exchange offer in general will not have further rights under the registration rights

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agreement, including registration rights and any rights to additional interest. Holders wishing to transfer the Outstanding Notes would have to rely on exemptions from the registration requirements of the Securities Act.

Expiration Date; Extensions; Amendments

The expiration date for the exchange offer is 5:00 p.m., New York City time, on July 9, 2020. We may extend this expiration date in our sole discretion, unless otherwise required by applicable law. If we so extend the expiration date, the term “expiration date” shall mean the latest date and time to which we extend the exchange offer.

We reserve the right, in our sole discretion:

• to delay accepting any Outstanding Notes, for example, in order to allow for the confirmation of tendered notes or for the rectification of any irregularity or defect in the tender of Outstanding Notes;

• to extend the exchange offer;

• to terminate the exchange offer if, in our sole judgment, any of the conditions described below shall not have been satisfied; or

• to amend the terms of the exchange offer in any manner.

We will give notice by press release or other written public announcement of any delay, extension or termination of the exchange offer. In addition, we will give, as promptly as practicable, written notice regarding any delay in acceptance, extension or termination of the offer to the registered holders of Outstanding Notes. If we amend the exchange offer in a manner that we determine to constitute a material change, or if we waive a material condition, we will promptly disclose the amendment or waiver in a manner reasonably calculated to notify the holders of Outstanding Notes of the amendment or waiver, and extend the exchange offer as required by law to cause the exchange offer to remain open for at least five business days following such notice.

Without limiting the manner in which we may choose to make public announcements of any delay in acceptance, extension, termination, amendment or waiver regarding the exchange offer, we shall have no obligation to publish, advertise, or otherwise communicate any public announcement, other than by making a timely release to a financial news service.

Interest on the Exchange Notes

Interest on the Exchange Notes will accrue at the rate of 3.375% per annum on the principal amount, payable semiannually on March 15 and September 15, with the next payment due on September 15, 2020. Interest on the Exchange Notes will accrue from March 15, 2020.

Conditions to the Exchange Offer

Despite any other term of the exchange offer, we will not be required to accept for exchange, or issue Exchange Notes for, any Outstanding Notes and we may terminate the exchange offer as provided in this prospectus, if:

• the exchange offer, or the making of any exchange by a holder, violates, in our good faith determination, any applicable law, rule or regulation or any applicable interpretation of the staff of the Commission;

• any action or proceeding shall have been instituted or threatened with respect to the exchange offer which, in our reasonable judgment, would impair our ability to proceed with the exchange offer; or

• we have not obtained any governmental approval which we, in our sole discretion, exercised reasonably, consider necessary for the completion of the exchange offer as contemplated by this prospectus.

The conditions listed above are for our sole benefit. We may assert them regardless of the circumstances giving rise to any of these conditions or waive them in our sole discretion in whole or in part. A failure on our part to exercise any of our rights under any of the conditions shall not constitute a waiver of that right, and that right shall be considered an ongoing right which we may assert at any time prior to the expiration of the exchange offer. All such conditions, other than those subject to governmental approval, will be satisfied or waived prior to the expiration of the exchange offer.

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If we determine in our sole discretion, exercised reasonably, that any of the events listed above has occurred, we may, subject to applicable law:

• refuse to accept any Outstanding Notes and return all tendered Outstanding Notes to the tendering holders;

• extend the exchange offer and retain all Outstanding Notes tendered before the expiration of the exchange offer, subject, however, to the rights of holders to withdraw these Outstanding Notes; or

• waive unsatisfied conditions relating to the exchange offer and accept all properly tendered Outstanding Notes that have not been withdrawn.

Any determination by us concerning the above events will be final and binding.

In addition, we reserve the right in our sole discretion, exercised reasonably, to:

• purchase or make offers for any Outstanding Notes that remain outstanding subsequent to the expiration date of the exchange offer; and

• to the extent permitted by applicable law, purchase Outstanding Notes in the open market, in privately negotiated transactions or otherwise.

The terms of any purchases or offers to purchase Outstanding Notes may differ from the terms of the exchange offer. Those purchases may require the consent of the lenders under our $175.0 million credit facility.

Procedures for Tendering

Except in limited circumstances, only a Euroclear participant, Clearstream participant or DTC participant listed on a DTC securities position listing with respect to the Outstanding Notes may tender Outstanding Notes in the exchange offer. To tender Outstanding Notes in the exchange offer:

• holders of Outstanding Notes that are DTC participants may follow the procedures for book-entry transfer as set forth under “— Book-Entry Transfer” and in the letter of transmittal; or

• Euroclear participants and Clearstream participants on behalf of the beneficial owners of Outstanding Notes are required to use book-entry transfer pursuant to the standard operating procedures of Euroclear or Clearstream. These procedures include the transmission of a computer-generated message to Euroclear or Clearstream in lieu of a letter of transmittal. See the description of “agent’s message” under “— Book-Entry Transfer.”

In addition, you must comply with one of the following:

• the exchange agent must receive, before expiration of the exchange offer, a timely confirmation of book-entry transfer of Outstanding Notes into the exchange agent’s account at DTC, Euroclear or Clearstream according to their respective standard operating procedures for electronic tenders and a properly transmitted agent’s message as described below; or

• the exchange agent must receive any corresponding certificate or certificates representing Outstanding Notes along with the letter of transmittal.

The tender by a holder of Outstanding Notes will constitute an agreement between the holder and us in accordance with the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal. If less than all the Outstanding Notes held by a holder are tendered, the tendering holder should fill in the amount of Outstanding Notes being tendered in the specified box on the letter of transmittal. The entire amount of Outstanding Notes delivered or transferred to the exchange agent will be deemed to have been tendered unless otherwise indicated.

The method of delivery of Outstanding Notes, the letter of transmittal and all other required documents or transmission of an agent’s message, as described under “— Book-Entry Transfer,” to the exchange agent is at the election and risk of the holder. Instead of delivery by mail, we recommend that holders use an overnight or hand delivery service. In all cases, sufficient time should be allowed to assure timely delivery to the exchange agent prior to the expiration of the exchange offer. No letter of transmittal or Outstanding Notes should be sent to us, DTC, Euroclear or Clearstream. Delivery of documents to DTC, Euroclear or Clearstream in accordance with their respective procedures will not constitute delivery to the exchange agent.

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Any beneficial holder whose Outstanding Notes are registered in the name of his or its broker, dealer, commercial bank, trust company or other nominee and who wishes to tender should contact the registered holder promptly and instruct it to tender on the beneficial holder’s behalf. If any beneficial holder wishes to tender on its own behalf, it must, prior to completing and executing the letter of transmittal and delivering its Outstanding Notes, either:

• make appropriate arrangements to register ownership of the Outstanding Notes in its name; or

• obtain a properly completed bond power from the registered holder.

The transfer of record ownership may take considerable time and may not be completed prior to the expiration date.

Signatures on a letter of transmittal or a notice of withdrawal, as described in “Withdrawal of Tenders,” must be guaranteed by a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc., a commercial bank or trust company having an office or correspondent in the United States or an “eligible guarantor institution,” within the meaning of Rule 17Ad-15 under the Exchange Act, which we refer to in this prospectus as an “eligible institution,” unless the Outstanding Notes are tendered:

• by a registered holder who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

• for the account of an eligible institution.

If the letter of transmittal is signed by a person other than the registered holder of any Outstanding Notes listed therein, the Outstanding Notes must be endorsed or accompanied by appropriate bond powers which authorize the person to tender the Outstanding Notes on behalf of the registered holder, in either case signed as the name of the registered holder or holders appears on the Outstanding Notes. If the letter of transmittal or any Outstanding Notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should so indicate when signing, and, unless waived by us, evidence satisfactory to us of their authority to so act must be submitted with the letter of transmittal.

We will determine in our sole discretion, exercised reasonably, all questions as to the validity, form, eligibility, including time of receipt, and acceptance and withdrawal of tendered Outstanding Notes. We reserve the absolute right to reasonably reject any and all Outstanding Notes not properly tendered or any Outstanding Notes whose acceptance by us would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects or irregularities as to any particular Outstanding Notes. Our interpretation of the form and procedures for tendering Outstanding Notes in the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, holders must cure any defects or irregularities in connection with tenders of Outstanding Notes within a period we will determine. Although we intend to request the exchange agent to notify holders of defects or irregularities relating to tenders of Outstanding Notes, neither we, the exchange agent nor any other person will have any duty or incur any liability for failure to give this notification. We will not consider tenders of Outstanding Notes to have been made until these defects or irregularities have been cured or waived. The exchange agent will return any Outstanding Notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived to the tendering holders, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

In addition, we reserve the right, as set forth under “— Conditions to the Exchange Offer,” to terminate the exchange offer.

By tendering, each holder of Outstanding Notes represents to us, among other things, that:

• the holder acquired Exchange Notes pursuant to the exchange offer in the ordinary course of its business;

• the holder has no arrangement or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act; and

• the holder is not our “affiliate,” as defined in Rule 405 under the Securities Act.

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If the holder is a broker-dealer that will receive Exchange Notes for its own account in exchange for Outstanding Notes acquired by the broker-dealer as a result of market-making activities or other trading activities, the holder must acknowledge that it will deliver a prospectus in connection with any resale of the Exchange Notes.

Book-Entry Transfer

We understand that the exchange agent will make a request promptly after the date of this prospectus to establish accounts with respect to the Outstanding Notes at DTC for the purpose of facilitating the exchange offer. Any financial institution that is a participant in DTC’s system may make book-entry delivery of Outstanding Notes by causing DTC to transfer the Outstanding Notes into the exchange agent’s DTC account in accordance with DTC’s Automated Tender Offer Program procedures for the transfer. Any participant in Euroclear or Clearstream may make book-entry delivery of Outstanding Notes by causing Euroclear or Clearstream to transfer the Outstanding Notes into the exchange agent’s account in accordance with established Euroclear or Clearstream procedures for transfer. The exchange of Exchange Notes for tendered Outstanding Notes will only be made after a timely confirmation of a book-entry transfer of the Outstanding Notes into the exchange agent’s account and timely receipt by the exchange agent of an agent’s message.

The term “agent’s message” means a message, transmitted by DTC, Euroclear or Clearstream, and received by the exchange agent and forming part of the confirmation of a book-entry transfer, which states that DTC, Euroclear or Clearstream has received an express acknowledgment from a participant tendering Outstanding Notes that the participant has received an appropriate letter of transmittal and agrees to be bound by the terms of the letter of transmittal, and that we may enforce the agreement against the participant. Delivery of an agent’s message will also constitute an acknowledgment from the tendering DTC, Euroclear or Clearstream participant that the representations contained in the letter of transmittal and described under “— Resale of Exchange Notes” are true and correct.

Guaranteed Delivery Procedures

There is no procedure for guaranteed delivery of the Outstanding Notes.

Withdrawal of Tenders

Your tender of Outstanding Notes pursuant to the exchange offer is irrevocable except as otherwise provided in this section. You may withdraw tenders of Outstanding Notes at any time prior to 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective:

• the exchange agent must receive a written notice, which may be by facsimile transmission or letter, of withdrawal at the address set forth below under “Exchange Agent,” or

• for DTC, Euroclear or Clearstream participants, holders must comply with their respective standard operating procedures for electronic tenders and the exchange agent must receive an electronic notice of withdrawal from DTC, Euroclear or Clearstream.

Any notice of withdrawal must:

• specify the name of the person who tendered the Outstanding Notes to be withdrawn;

• identify the Outstanding Notes to be withdrawn, including the certificate number or numbers and principal amount of the Outstanding Notes to be withdrawn;

• include a statement that the person is withdrawing his election to have such Outstanding Notes exchanged;

• be signed by the person who tendered the Outstanding Notes in the same manner as the original signature on the letter of transmittal, including any required signature guarantees; and

• specify the name in which the Outstanding Notes are to be re-registered, if different from that of the withdrawing holder.

If Outstanding Notes have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC, Euroclear or Clearstream to be

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credited with the withdrawn Outstanding Notes and otherwise comply with the procedures of the applicable facility. We will determine in our sole discretion, exercised reasonably, all questions as to the validity, form and eligibility, including time of receipt, for the withdrawal notices, and our determination will be final and binding on all parties. Any Outstanding Notes so withdrawn will be deemed not to have been validly tendered for purposes of the exchange offer and no Exchange Notes will be issued with respect to them unless the Outstanding Notes so withdrawn are validly retendered. Any Outstanding Notes which have been tendered but which are not accepted for exchange will be returned to the holder without cost to the holder promptly after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn Outstanding Notes may be re-tendered by following the procedures described under “— Procedures for Tendering” at any time prior to the expiration date.

Fees and Expenses

We will not make any payments to brokers, dealers or other persons soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and its related reasonable out-of-pocket expenses, including accounting and legal fees. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the Outstanding Notes and in handling or forwarding tenders for exchange.

Holders who tender their Outstanding Notes for exchange will not be obligated to pay any transfer taxes. If, however:

• Exchange Notes are to be delivered to, or issued in the name of, any person other than the registered holder of the Outstanding Notes tendered;

• tendered Outstanding Notes are registered in the name of any person other than the person signing the letter of transmittal; or

• a transfer tax is imposed for any reason other than the exchange of Outstanding Notes in connection with the exchange offer;

then the tendering holder must pay the amount of any transfer taxes due, whether imposed on the registered holder or any other persons. If the tendering holder does not submit satisfactory evidence of payment of these taxes or exemption from them with the letter of transmittal, the amount of these transfer taxes will be billed directly to the tendering holder.

Accounting Treatment

The Exchange Notes will be recorded at the same carrying value as the Outstanding Notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the completion of the exchange offer.

Consequences of Failures to Properly Tender Outstanding Notes in the Exchange Offer

We will issue the Exchange Notes in exchange for Outstanding Notes in the exchange offer only after timely receipt by the exchange agent of the Outstanding Notes, a properly completed and duly executed letter of transmittal and all other required documents. Therefore, holders of the Outstanding Notes desiring to tender Outstanding Notes in exchange for Exchange Notes should allow sufficient time to ensure timely delivery. We are under no duty to give notification of defects or irregularities of tenders of Outstanding Notes for exchange. Outstanding Notes that are not tendered or that are tendered but not accepted by us will, following completion of the exchange offer, continue to be subject to the existing restrictions upon transfer under the Securities Act. If we successfully complete the exchange offer, specified rights under the registration rights agreement, including registration rights and any right to additional interest, will be either limited or eliminated.

Participation in the exchange offer is voluntary. In the event the exchange offer is completed, we will not be required to register the remaining Outstanding Notes. Remaining Outstanding Notes will continue to be subject to the following restrictions on transfer:

• holders may resell Outstanding Notes only if we register the Outstanding Notes under the Securities Act, if an exemption from registration is available, or if the transaction requires neither registration under nor an exemption from the requirements of the Securities Act; and

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• the remaining Outstanding Notes will bear a legend restricting transfer in the absence of registration or an exemption.

We do not currently anticipate that we will register any remaining Outstanding Notes under the Securities Act. To the extent that Outstanding Notes are tendered and accepted in connection with the exchange offer, any trading market for remaining Outstanding Notes could be adversely affected.

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DESCRIPTION OF THE EXCHANGE NOTES

We have summarized selected provisions of the Exchange Notes below. We will issue the Exchange Notes, and we issued the Outstanding Notes, under an Indenture, dated as of September 11, 2019 (the “base indenture”), between us and Regions Bank, as trustee, as supplemented by Supplemental Indenture No. 1 thereto, dated as of September 11, 2019 (the “supplemental indenture”). We have filed the base indenture and the supplemental indenture as exhibits to the registration statement, of which this prospectus is a part. In this “Description of the Exchange Notes” section, when we refer to the “indenture,” we mean the base indenture as supplemented by the supplemental indenture. The terms of the Exchange Notes and the Outstanding Notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

We urge you to read the base indenture and the supplemental indenture because they, and not this description, define your rights as holders of the Exchange Notes.

If the exchange offer is consummated, holders of Outstanding Notes who do not exchange their Outstanding Notes for Exchange Notes will vote together with the holders of the Exchange Notes for all relevant purposes under the indenture. In that regard, the indenture requires that certain actions by the holders under the indenture (including acceleration after an event of default, as described under “— Events of Default”) may be taken, and certain rights may only be exercised, by specified minimum percentages of the aggregate principal amount of all Outstanding Notes and Exchange Notes of a series issued under the indenture. In determining whether holders of the requisite percentage in principal amount have given any notice, direction, waiver, consent or taken any other action permitted under the indenture, any Outstanding Notes that remain outstanding after the exchange offer will be aggregated with the Exchange Notes, and the holders of the Outstanding Notes and the Exchange Notes will vote together as a single series for all such purposes. Accordingly, all references in this “Description of the Exchange Notes” to specified percentages in aggregate principal amount of the Notes mean, at any time after the exchange offer is consummated, such percentage in aggregate principal amount of the Outstanding Notes and the Exchange Notes then outstanding.

For purposes of this summary, the terms “we,” “our,” “ours” and “us” refer to Cleco Corporate Holdings LLC and not any of our subsidiaries and references to the “Notes” are references to the Exchange Notes offered hereby.

Ranking of the Notes

The Notes will:

• be our general unsecured obligations;

• rank equally in right of payment with all of our other existing and future unsecured and unsubordinated indebtedness;

• be subordinated to all of our secured indebtedness, to the extent of the value of such collateral; and

• be structurally subordinated to all of the liabilities of our subsidiaries.

As of March 31, 2020, we had $1.77 billion of senior unsecured and unsubordinated indebtedness outstanding, including outstanding borrowings of $88.0 million under our $175.0 million revolving credit facility, and no secured indebtedness. As of March 31, 2020, our subsidiaries had $1.53 billion of indebtedness outstanding, including outstanding borrowings of $150.0 million under Cleco Power’s $300.0 million revolving credit facility.

Subject to exceptions, and subject to compliance with the applicable requirements, set forth in the indenture, we may discharge our obligations under the indenture with respect to the Notes as described below under “— Defeasance.”

Structural Subordination

The Notes will be structurally subordinated to all of the liabilities of our subsidiaries with regard to the assets and earnings of Cleco Power, Cleco Cajun and our other subsidiaries. Since a substantial portion of our operations are conducted through Cleco Power, a primary source of funds for the repayment of our indebtedness, including the Notes, is distributions and dividends from Cleco Power, which is subject to numerous restrictions on its ability to make such distributions and dividends, including from state corporate law, Cleco Power’s

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indentures and credit agreements, and state and local regulations. Cleco Power has also made certain regulatory commitments which restrict its ability to make distributions and dividends to us.

Principal, Maturity and Interest

We issued $300.0 million aggregate principal amount of the Outstanding Notes in September 2019. We may issue Additional Notes from time to time, without the consent of the holders of the Outstanding Notes and the Notes. We will issue the Notes only in minimum denominations of $2,000 principal amount and integral multiples of $1,000 in excess thereof.

The Notes will mature on September 15, 2029.

Interest on the Notes will:

• accrue at the rate of 3.375% per annum;

• be payable semi-annually in arrears on each March 15 and September 15;

• be payable to the person in whose name the Notes are registered at the close of business on the March 1 and September 1 immediately preceding the applicable interest payment date, which we refer to with respect to the Notes as “regular record dates”;

• be computed on the basis of a 360-day year comprised of twelve 30-day months; and

• be payable on overdue interest to the extent permitted by law at the same rate as interest is payable on principal.

If any interest payment date, the maturity date or any redemption date falls on a day that is not a business day, the required payment will be made on the next business day with the same force and effect as if made on the relevant interest payment date, maturity date or redemption date and no additional amounts will accrue on that payment for the period from and after the interest payment date, maturity date or redemption date, as the case may be, to the date of that payment on the next succeeding business day. Unless we default on a payment, no interest will accrue for the period from and after the applicable maturity date or redemption date. No interest will be paid on either the Exchange Notes or the Outstanding Notes at the time of exchange. Interest on the Exchange Notes will accrue from March 15, 2020. Assuming the Exchange Notes are issued prior to September 15, 2020, holders of Outstanding Notes that are accepted for exchange in the exchange offer will be deemed to have waived the right, if any, to receive any payment in respect of interest accrued on the Outstanding Notes from March 15, 2020 until the date of the issuance of the Exchange Notes. Holders of the Exchange Notes will receive the same interest payments that they would have received had their Outstanding Notes not been accepted for exchange in the exchange offer.

Optional Redemption

At any time and from time to time, we may redeem the Notes at our option in whole or in part on any date prior to June 15, 2029 (the “Par Call Date”) at a redemption price equal to the greater of:

• 100% of the principal amount of the Notes to be redeemed; or

• the sum of the present values of the remaining scheduled payments of principal and interest on the Notes to be redeemed that would be due if such Notes matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the date of redemption) discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable treasury rate plus 30 basis points;

plus, in each case, accrued and unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date.

At any time on or after the Par Call Date, we may redeem the Notes, in whole or in part, at our option, by paying 100% of the principal amount of the Notes to be redeemed plus accrued and unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date.

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“treasury rate” means, with respect to any redemption date:

• the yield calculated on the third business day preceding the redemption date, as follows: for the latest day that appears in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as “Selected Interest Rates (Daily) — H.15” (or any successor publication) under the caption “Treasury Constant Maturities — Nominal,” the independent investment banker shall select two yields — one for the maturity immediately before and one for the maturity immediately after the remaining maturity of the Notes to be redeemed (assuming the Notes matured on the Par Call Date) — and shall interpolate on a straight-line basis using such yields; if there is no such maturity either before or after, the independent investment banker shall select the maturity closest to the Par Call Date that appears on the release; or

• if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the applicable comparable treasury issue, calculated by the independent investment banker using a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date.

The treasury rate will be calculated by the independent investment banker on the third business day preceding the date fixed for redemption.

“comparable treasury issue” means the United States Treasury security selected by an independent investment banker as having an actual or interpolated maturity comparable to the remaining term (remaining life) of the Notes to be redeemed (assuming for this purpose that the Notes matured on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Notes.

“comparable treasury price” means (a) the average of three reference treasury dealer quotations for such redemption date, after excluding the highest and lowest reference treasury dealer quotations, or (b) if the independent investment banker obtains fewer than three such reference treasury dealer quotations, the average of all such quotations.

“independent investment banker” means one of Mizuho Securities USA LLC, Credit Agricole Securities (USA) Inc. or Scotia Capital (USA) Inc. and their respective affiliates or successors as specified by us, or, if these firms are unwilling or unable to select the comparable treasury issue, an independent investment banking institution of national standing appointed by us.

“reference treasury dealer” means each of (a) Mizuho Securities USA LLC and Scotia Capital (USA) Inc. and their respective affiliates or successors, each of which is a primary United States government securities dealer in New York City (a “Primary Treasury Dealer”) and a Primary Treasury Dealer selected by Credit Agricole Securities (USA) Inc., provided, however, that if any of the foregoing shall cease to be a Primary Treasury Dealer, we will substitute therefor another Primary Treasury Dealer and (b) any other Primary Treasury Dealer selected by us after consultation with the independent investment banker.

“reference treasury dealer quotations” means, with respect to each reference treasury dealer and any redemption date, the average, as determined by the independent investment banker, of the bid and asked prices for the applicable comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the independent investment banker at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

The trustee, at our written direction, will send a notice of redemption to each holder of Notes to be redeemed by first-class mail (or in accordance with the procedures of DTC with respect to Notes registered in the name of Cede & Co.) at least 15 and not more than 60 days prior to the date fixed for redemption. Unless we default on payment of the redemption price, interest will cease to accrue on the Notes or portions thereof called for redemption on the date fixed for redemption. If fewer than all of the Notes are to be redeemed, not more than 60 days prior to the redemption date, the particular Notes or portions thereof for redemption will be selected from the outstanding Notes not previously called by such method as the trustee deems fair and appropriate. In the case of a partial redemption of Notes registered in the name of Cede & Co., the Notes to be redeemed will be determined in accordance with the procedures of DTC.

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Purchase of Notes Upon Change of Control Repurchase Event

In the event of the occurrence of both a Change of Control and a Ratings Event (a “Change of Control Repurchase Event”) each holder of a Note will have the right, at such holder’s option, subject to the terms and conditions of the indenture, to require us to repurchase all or any part of that holder’s Notes on a date selected by us that is no earlier than 60 days nor later than 90 days (the “Purchase Date”) after written notice is sent by us of the occurrence of such Change of Control Repurchase Event, at a repurchase price payable in cash equal to 101% of the principal amount of such Notes plus accrued interest, including additional interest, if any, thereon, but excluding, to the Purchase Date (the “Change of Control Purchase Price”) pursuant to an offer to repurchase on the terms set forth in the indenture (a “Change of Control Offer”).

Within 30 days after the date of the Change of Control Repurchase Event, we are obligated to mail (or send in accordance with the procedures of DTC), to each holder of a Note a notice (with a copy to the trustee) regarding the Change of Control Repurchase Event, which notice shall state, among other things:

• that a Change of Control Repurchase Event has occurred and that each such holder has the right to require us to repurchase all or any part of such holder’s Notes at the Change of Control Purchase Price;

• the Change of Control Purchase Price;

• the Purchase Date;

• that any Note not tendered will continue to accrue interest;

• the name and address of the paying agent;

• the procedures to withdraw a holder’s election to have any Notes repurchased pursuant to the Change of Control Repurchase Event; and

• that holders whose Notes are being purchased only in part will be issued new Notes equal in principal amount to the unpurchased portion of the Notes surrendered, which unpurchased portion must be equal to $2,000 in principal amount or an integral multiple of $1,000 in excess of $2,000.

To exercise this right, a holder must deliver a written notice (the “Change of Control Purchase Notice”) to the paying agent (initially the trustee) at its corporate trust office, or any other office of the paying agent maintained for such purposes (or if Notes are held in book entry form, in accordance with DTC’s applicable procedures), not later than 30 days prior to the Purchase Date. The Change of Control Purchase Notice shall state:

• the portion of the principal amount of any Notes to be repurchased, which must be a minimum of $2,000 or an integral multiple of $1,000 in excess thereof;

• that such Notes are to be repurchased by us pursuant to the applicable Change of Control Repurchase Event provisions of the indenture; and

• unless the Notes are represented by one or more global Notes, the certificate numbers of the Notes to be repurchased.

Any Change of Control Purchase Notice may be withdrawn by the holder by a written notice of withdrawal delivered to the paying agent (or if Notes are held in book entry form, in accordance with DTC’s applicable procedures) not later than three business days prior to the Purchase Date. The notice of withdrawal shall state the principal amount and, if applicable, the certificate numbers of the Notes as to which the withdrawal notice relates and the principal amount, if any, that remains subject to a Change of Control Purchase Notice.

If a Note is represented by a global Note, DTC or its nominee will be the holder of such Note and therefore will be the only entity that can require us to repurchase Notes upon a Change of Control Repurchase Event. To obtain repayment with respect to such Note upon a Change of Control Repurchase Event, the beneficial owner of such Note must provide to the broker or other entity through which it holds the beneficial interest in such Note (a) the Change of Control Purchase Notice signed by such beneficial owner, and such signature must be guaranteed by a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc. or a commercial bank or trust company having an office or correspondent in the United States, and (b) instructions to such broker or other entity to notify DTC of such beneficial owner’s desire to cause us to repurchase such Notes. Such broker or other entity will provide to the paying agent (i) a Change of Control

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Purchase Notice received from such beneficial owner and (ii) a certificate satisfactory to the paying agent from such broker or other entity that it represents such beneficial owner. Such broker or other entity will be responsible for disbursing any payments it receives upon the repurchase of such Notes by us.

Payment of the Change of Control Purchase Price for a Note in registered, certificated form for which a Change of Control Purchase Notice has been delivered and not withdrawn is conditioned upon delivery of such certificated Note (together with necessary endorsements) to the trustee, as our paying agent, at its corporate trust office, or any other office of the paying agent maintained for such purpose, at any time (whether prior to, on or after the Purchase Date) after the delivery of such Change of Control Purchase Notice. Payment of the Change of Control Purchase Price for such certificated Note will be made promptly following the later of the Purchase Date or the time of delivery of such certificated Note.

If the paying agent holds, in accordance with the terms of the indenture, money sufficient to pay the Change of Control Purchase Price of a Note on the business day following the Purchase Date for such Note, then, on and after such date, interest on such Note will cease to accrue, whether or not such Note is delivered to the paying agent, and all other rights of the holders shall terminate (other than the right to receive the Change of Control Purchase Price upon delivery of the Note).

We will not be required to make a Change of Control Offer upon a Change of Control Repurchase Event if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by us and purchases all Notes properly tendered and not withdrawn in accordance with such Change of Control Offer or if notice of redemption has been given pursuant to the requirements set forth in the indenture unless and until there is a default in payment of the applicable redemption price. Notwithstanding anything to the contrary contained herein, a Change of Control Offer may be made in advance of a Change of Control, conditioned upon the occurrence of such Change of Control and without regard to the occurrence of a Ratings Event, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer is made; provided any such Change of Control Offer will be deemed to satisfy our obligation to make a Change of Control Offer upon the occurrence of any related Change of Control Repurchase Event.

The definition of Change of Control set forth in the indenture with respect to the Notes differs from the definition of change in control in the senior unsecured credit facilities. Depending on the circumstances, it is possible that a change in control may occur for purposes of the senior unsecured credit facilities without constituting a Change of Control for purposes of the indenture.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, transfer, assignment, lease, conveyance or other disposition of “all or substantially all” of the assets of us and our subsidiaries, considered as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of Notes to require us to repurchase the Notes as a result of a sale, transfer, assignment, lease, conveyance or other disposition of less than all of the assets of us and our subsidiaries, considered as a whole, may be uncertain.

Under the third bullet point of the definition of Change of Control below, a Change of Control will occur when a majority of our board of managers (for so long as the Operating Agreement is in effect, together with any replacement or new managers appointed to such board of managers in accordance with the terms of the Operating Agreement, and to the extent the terms of the Operating Agreement are no longer in effect, together with any new managers whose election or appointment by such board of managers or whose nomination for election by our members was approved by a vote of a majority of the managers then still in office who were either managers at the beginning of such period or whose election or nomination for election was previously so approved), during any period, cease to constitute a majority of our board of managers then in office. In San Antonio Fire & Police Pension Fund v. Amylin Pharmaceuticals, Inc. et al. (May 2009), the Delaware Court of Chancery held that the occurrence of a change of control under a similar indenture provision may nevertheless be avoided if the existing directors were to approve the slate of new director nominees, provided the incumbent directors gave their approval in the good faith exercise of their fiduciary duties owed to the corporation and its stockholders. Therefore, in certain circumstances involving a significant change in the composition of our board of managers, the holders of the Notes may not be entitled to require us to repurchase the Notes as described above.

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The indenture requires us to comply with the provisions of Regulation 14E and any other tender offer rules under the Exchange Act that may then be applicable in connection with any offer by us to purchase Notes at the option of holders upon a Change of Control Repurchase Event. The Change of Control Repurchase Event purchase feature of the Notes may in certain circumstances make more difficult or discourage a takeover and, thus, the removal of incumbent management. The Change of Control Repurchase Event purchase feature, however, is not the result of management’s knowledge of any specific effort to obtain control of us, or part of a plan by management to adopt a series of anti-takeover provisions. Instead, the Change of Control Repurchase Event purchase feature is a term contained in many similar debt offerings and the terms of such feature result from negotiations between us and the initial purchasers of the Outstanding Notes. Our management has no present intention to propose any anti-takeover measures although it is possible that we could decide to do so in the future.

No Note may be repurchased by us as a result of a Change of Control Repurchase Event if there has occurred and is continuing an event of default described under “— Events of Default” (other than a default in the payment of the Change of Control Purchase Price with respect to the Notes). In addition, our ability to purchase Notes may be limited by our financial resources and our inability to raise the required funds because of restrictions on issuance of securities contained in other contractual arrangements.

Sinking Fund

We are not obligated to make mandatory redemption or sinking fund payments with respect to the Notes.

Certain Covenants

Merger, Consolidation, Sale, Lease or Conveyance

The indenture provides that we may not, directly or indirectly, (a) consolidate or merge with or into another person, whether or not we are the surviving corporation, or (b) sell, assign, transfer, convey or otherwise dispose of all or substantially all of our or our subsidiaries’ properties or assets taken as a whole, in one or more related transactions, to another person, unless:

• either (A) we are the surviving corporation or (B) the person formed by or surviving any such consolidation or merger (if other than us) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation, partnership or limited liability company organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

• the person formed by or surviving any such consolidation or merger (if other than us) or the person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all of our obligations under the Notes and the indenture pursuant to a supplemental indenture or other documents and agreements reasonably satisfactory to the trustee;

• immediately after such consolidation or merger, no event of default under the indenture exists; and

• we deliver an officer’s certificate and opinion of counsel to the trustee stating that such transaction is authorized under the indenture.

In addition, we may not, directly or indirectly, lease all or substantially all of our properties or assets, in one or more related transactions, to any other person.

Limitations on Liens

The indenture provides that we may not pledge, mortgage, hypothecate or grant a security interest in, or permit any mortgage, pledge, security interest or other Lien upon, any of our assets or property, whether owned on the date of delivery of the Notes or acquired thereafter, to secure any Indebtedness, other than Permitted Liens; provided, however, that any Lien on such property or assets will be permitted notwithstanding that it is not a Permitted Lien if the Notes are equally and ratably secured with (or on a senior basis to, in the case of obligations subordinated in right of payment to the Notes) the obligations so secured until such time as such obligations are no longer secured by a Lien (other than Permitted Liens).

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Reports and Other Information

The indenture provides that whether or not required by the SEC’s rules and regulations, so long as any Notes are outstanding, we will furnish to the trustee, within the time periods specified in the SEC’s rules and regulations for a filer that is a “non-accelerated filer”:

• all annual and quarterly reports that would be required to be filed with the SEC on Forms 10-K and 10-Q if we were required to file such reports; and

• all current reports that would be required to be filed with the SEC on Form 8-K if we were required to file such reports.

All such reports will be prepared, within the time periods specified above, in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on our consolidated financial statements by our independent registered public accounting firm or independent auditors. In addition, we will file a copy of each of the reports referred to in the two bullet points immediately above with the SEC for public availability within the time periods specified in the two bullet points immediately above (unless the SEC will not accept such a filing). If, notwithstanding the foregoing, the SEC will not accept our filings for any reason, we will use our reasonable best efforts to post the reports referred to in the preceding paragraph on our website within the time periods specified above. To the extent such filings are made, the reports will be deemed to be furnished to the trustee on the date filed.

In addition, for so long as any Notes remain outstanding, we will furnish to prospective purchasers of Notes, upon their request, the information described above as well as any other information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act for compliance with Rule 144A.

Delivery of such reports, information and documents to the trustee is for informational purposes only, and the trustee’s receipt of such shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including our compliance with any of their covenants under the indenture (as to which the trustee is entitled to rely exclusively on officer’s certificates).

We will be deemed to have furnished the reports to the trustee if we have filed such reports with the SEC on the EDGAR filing system and such reports are publicly available.

Certain Definitions

“Advisor” means, with respect to any Fund, any entity which provides advice in relation to the management of investments of such Fund in a manner which is substantially the same as the manner in which a Manager would provide such advice.

An “Affiliate” of, or a person “Affiliated” with, a specific person means (a) with respect to any person that is not a Fund or a direct or indirect subsidiary of a Fund, any other person that, directly or indirectly through one or more intermediaries, Controls, is Controlled by, or is under common Control with such person and (b) with respect to any person that is a Fund or is a direct or indirect subsidiary of a Fund, any Manager or Advisor of such Fund and any other person that, directly or indirectly through one or more intermediaries, Controls, is Controlled by, or is under common Control with, any such Manager or Advisor (including, for the avoidance of doubt, any Fund or any direct or indirect subsidiary of any Fund which is Controlled by any such person).

“Change of Control” means the occurrence of any of the following events:

• any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act or any successor provisions to either of the foregoing), other than the Permitted Holders, becomes the “beneficial owners” (as used in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person or group will be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of a majority of the total voting power of our Voting Stock, whether as a result of the issuance of our securities, any merger, consolidation, liquidation or dissolution of us or otherwise;

• the sale, transfer, assignment, lease, conveyance or other disposition, directly or indirectly, of all or substantially all the assets of us and our subsidiaries, considered as a whole (other than a disposition of such assets as an entirety or virtually as an entirety to a wholly-owned subsidiary) to any person other

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than the Permitted Holders occurs, or we merge, consolidate or amalgamate with or into any other person or any other person merges, consolidates or amalgamates with or into us, in any such event pursuant to a transaction in which our outstanding Voting Stock is reclassified into or exchanged for cash, securities or other property, other than any such transaction where (i) our outstanding Voting Stock is reclassified into or exchanged for other Voting Stock of us or for Voting Stock of the surviving corporation and (ii) the holders of our Voting Stock immediately prior to such transaction own, directly or indirectly, a majority of our Voting Stock or the surviving corporation immediately after such transaction;

• during any period, individuals who at the beginning of such period constituted our board of managers (for so long as our Operating Agreement, adopted April 13, 2016 (as amended from time to time, the “Operating Agreement”) is in effect, together with any replacement or new managers appointed to such board of managers in accordance with the terms of the Operating Agreement, and to the extent the terms of the Operating Agreement are no longer in effect, together with any new managers whose election or appointment by such board of managers or whose nomination for election by our members was approved by a vote of a majority of the managers then still in office who were either managers at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of our board of managers then in office; or

• our members approve any plan of liquidation or dissolution of us.

“Change of Control Repurchase Event” means the occurrence of both a Change of Control and a Ratings Event.

“Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a person, whether through the ownership of securities, by contract or otherwise, which, for the avoidance of doubt, shall include, with respect to any Fund, any Manager or Advisor of such Fund. “Controlling” and “Controlled” have meanings correlative thereto.

“Equity Interests” means, with respect to any person, all of the shares, membership interests, rights, participations or other equivalents (however designated) of capital stock of (or other ownership or profit interests or units in) such person and all of the warrants, options or other rights for the purchase, acquisition or exchange from such person of any of the foregoing (including through convertible securities).

“Fair Market Value” means the value that would be paid by a willing buyer to a willing seller in a transaction not involving distress or necessity of either party, determined in good faith by our chief financial officer or our board of managers.

“Fund” means any investment company, limited partnership, general partnership or other collective investment scheme or any body corporate or other entity, in each case, the business, operations or assets of which are managed professionally for investment purposes.

“Governmental Authority” means any nation, state, sovereign or government, any federal, regional, state or local government or political subdivision thereof, any central bank or other entity exercising executive, legislative, judicial, treasury, regulatory or administrative functions of or pertaining to government and having jurisdiction over the person or matters in question (including any supra national body exercising such powers or functions, such as the European Union or the European Central Bank).

“Governmental Rule” means any statute, law, regulation, ordinance, rule, judgment, order, decree, permit, concession, grant, franchise, license, agreement, directive requirement, treaty or other governmental restriction or any similar form of decision of or determination by or any interpretation or administration of any of the foregoing, in each case, having the force of law by, any Governmental Authority, which is applicable to any person, whether now or hereafter in effect.

“Indebtedness,” as applied to any person, means bonds, debentures, notes and other instruments or arrangements representing obligations created or assumed by such person, in respect of:

• obligations for money borrowed, other than unamortized debt discount or premium;

• obligations evidenced by a note or similar instrument given in connection with the acquisition of any business, properties or assets of any kind;

• obligations as lessee under a capital lease;

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• any amendments, renewals, extensions, modifications and refundings of any such indebtedness or obligations listed in the three immediately preceding bullet points; and

• all guarantees of such person in respect of obligations of the kind referred to above.

All indebtedness of such type secured by a lien upon property owned by such person, although such person has not assumed or become liable for the payment of such indebtedness, is also deemed to be Indebtedness of such person. All indebtedness for borrowed money incurred by any other persons which is directly guaranteed as to payment of principal by such person will for all purposes of the indenture be deemed to be indebtedness of such person, but no other contingent obligation of such person in respect of indebtedness incurred by any other persons shall be deemed indebtedness of such person.

“Investment Grade” means BBB- or higher by S&P and Baa3 or higher by Moody’s, or the equivalent of such ratings by S&P or Moody’s or, if either S&P or Moody’s does not make a rating on the Notes publicly available, another Rating Agency.

“Investors” means MIP Cleco Partners L.P. (f/k/a Como B L.P.), bcIMC Como Investment Limited Partnership and John Hancock Life Insurance Company (U.S.A.), and each of their respective Affiliates.

“Lien” means any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge, or preference, priority or other security interest or preferential arrangement, of any kind or nature whatsoever (including any conditional sale or other title retention agreement, any easement, right of way or other encumbrance on title to real property, and any capitalized lease having substantially the same economic effect as any of the foregoing).

“Manager” means, with respect to any Fund, any general partner, trustee, responsible entity, nominee, manager, or other entity performing a similar function with respect to such Fund.

“Moody’s” means Moody’s Investors Service, Inc. or its successors.

“Permitted Contest Conditions” means a contest, pursued in good faith, challenging the enforceability, validity, interpretation, amount or application of any Governmental Rule, any Taxes, assessment, fee, government charge or levy or any Lien or other claim or payment of any nature or other matter (legal, contractual or other) by appropriate proceedings timely instituted if (a) the Issuer diligently pursues such contest, (b) the Issuer establishes adequate reserves with respect to the contested claim to the extent required by GAAP and (c) such contest would not reasonably be expected to result in a breach of the covenant described in an event of default described in the last bullet of “— Events of Default” or such contest would not reasonably be expected to result in any criminal or unindemnified civil liability (in the case of any such civil liability, otherwise required to be indemnified by us under the indenture), being incurred by the trustee or any of the holders.

“Permitted Holders” means each of the Investors and members of our management (or of our direct or indirect parent) who are holders of our Voting Stock (or any of its direct or indirect parent companies) on the issue date of the Notes and any “group” (as such term is used in Section 13(d) and 14(d) of the Exchange Act or any successor provision) of which any of the foregoing are members; provided that, in the case of such group and without giving effect to the existence of such group or any other group, such Investors and members of management, collectively, have beneficial ownership of a majority of the total voting power of our Voting Stock.

“Permitted Liens” means:

• mechanics’, materialmen’s, workers’, repairmens, employees’, warehousemen’s, carriers’ or other like Liens arising in the ordinary course of business or under Governmental Rules securing obligations which are not yet due, or which are adequately bonded and which are being contested pursuant to the Permitted Contest Conditions;

• Liens for Taxes, assessments or governmental charges, which are not yet due or which are being contested pursuant to the Permitted Contest Conditions;

• Liens arising out of judgments or awards fully covered by insurance or with respect to which an appeal or proceeding for review is being prosecuted pursuant to the Permitted Contest Conditions;

• Liens arising in the ordinary course of business from netting services, overdraft protection, banking services obligations and otherwise in connection with deposit, securities and commodities accounts;

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• Liens securing judgments that do not constitute an event of default described in the last bullet of “— Events of Default”;

• zoning, building and other generally applicable land use restrictions, which, in the aggregate, do not in any case materially interfere with the ordinary conduct of our business;

• Liens that have been placed by a third party on the fee title of leased real property or property over which we have easement rights, and subordination or similar agreements relating thereto;

• Liens securing Indebtedness in an aggregate principal amount not to exceed 15% of the Fair Market Value of our property and assets;

• agreements for an obligation (other than repayment of borrowed money) relating to the joint or common ownership, operation, and use of property, including Liens under joint venture or similar agreements securing obligations incurred in the conduct of operations or consisting of a purchase option, call or right of first refusal with respect to the Equity Interests in such jointly owned person or assets;

• Liens created for the sole purpose of extending, renewing or replacing in whole or in part Indebtedness secured by any lien, mortgage or security interest referred to in this definition of “Permitted Liens”; provided, however, that the principal amount of Indebtedness secured thereby shall not exceed the principal amount of Indebtedness so secured at the time of such extension, renewal or replacement and that such extension, renewal or replacement, as the case may be, shall be limited to all or a part of the property or Indebtedness that secured the lien or mortgage so extended, renewed or replaced (and any improvements on such property);

• leases or subleases granted to others that do not materially interfere with the business of the Issuer and its subsidiaries, or Liens arising from Uniform Commercial Code financing statements filed on a precautionary basis in respect of operating leases intended by the parties to be true leases;

• Liens securing or deposits securing obligations of us and our subsidiaries with respect to workers’ compensation, unemployment insurance and other types of social security; and

• Liens permitted under the senior unsecured credit facilities (or any amendments, modifications, refinancings or replacements thereof).

“Rating Agency” means each of S&P and Moody’s or, if S&P or Moody’s or both does not make a rating on the Notes publicly available, a nationally recognized statistical rating organization or organizations, as the case may be, selected by us (as certified by a resolution of our board of managers), which will be substituted for S&P or Moody’s, or both, as the case may be.

“Ratings Event” means a decrease in the ratings of the Notes by one or more gradations (including gradations within categories as well as between rating categories) by each of the Rating Agencies on any date from the date of the public notice of an arrangement that could result in a Change of Control until the end of the 30-day period following public notice of the occurrence of the Change of Control (which 30-day period will be extended so long as the rating of the Notes is under publicly announced consideration for possible downgrade by either of the Rating Agencies and the other Rating Agency has either downgraded, or publicly announced that it is considering downgrading, the Notes). Notwithstanding the foregoing, if the rating of the Notes by each of the Rating Agencies is Investment Grade, then “Ratings Event” means a decrease in the ratings of the Notes by one or more gradations (including gradations within categories as well as between rating categories) by each of the Rating Agencies such that the rating of the Notes by each of the Rating Agencies falls below Investment Grade on any date from the date of the public notice of an arrangement that could result in a Change of Control until the end of the 30-day period following public notice of the occurrence of the Change of Control (which 30-day period will be extended so long as the rating of the Notes is under publicly announced consideration for possible downgrade by either of the Rating Agencies and the other Rating Agency has either downgraded, or publicly announced that it is considering downgrading, the Notes).

“Significant Subsidiary” means any subsidiary that would be considered a “significant subsidiary” under Article 1 of Regulation S-X under the Exchange Act.

“S&P” means S&P Global Ratings, a division of S&P Global Inc., or its successors.

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“Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other similar charges now or hereafter imposed, levied, collected, withheld or assessed by any Governmental Authority, including any interest, additions to tax, penalties or similar liability with respect thereto.

“Voting Stock” means securities of any class or classes the holders of which are ordinarily, in the absence of contingencies, entitled to vote for corporate directors (or persons performing similar functions).

Events of Default

Each of the following is an event of default under the indenture with respect to the Notes:

• our failure to pay the principal of or premium, if any, on the Notes when due, including at maturity, upon required purchase, upon redemption or upon acceleration;

• our failure to pay any interest, including additional interest, on the Notes for 30 days after the interest becomes due;

• our failure to perform, or our breach in any material respect of, any other covenant or warranty in the indenture, other than a covenant or warranty included in the indenture solely for the benefit of another series of our debt securities issued under the indenture, for 90 days after either the trustee or holders of at least 25% in principal amount of the outstanding Notes have given us written notice of the breach in the manner required by the indenture;

• the default by us or any Significant Subsidiary of ours in a scheduled payment at maturity, upon redemption or otherwise in the aggregate principal amount of $50 million or more, after the expiration of any applicable grace period, of any Indebtedness, or the acceleration of any Indebtedness of us in such aggregate principal amount so that it becomes due and payable prior to the date on which it would otherwise have become due and payable and such payment default is not cured or such acceleration default is not rescinded within 30 days after notice to us in accordance with the terms of the Indebtedness;

• specified events involving bankruptcy, insolvency or reorganization of us or any Significant Subsidiary of ours; and

• the failure by us to pay final judgments aggregating in excess of $50 million, which judgments are not paid, discharged or stayed for a period of 60 days;

provided, however, that no event described in the third bullet point above will be an event of default until an officer of the trustee, assigned to and working in the trustee’s corporate trust department, has actual knowledge of the event or until the trustee receives written notice of the event. (Section 501)

If an event of default occurs and is continuing with respect to the Notes, either the trustee or the holders of at least 25% in principal amount of the outstanding Notes may declare the principal amount of the Notes due and immediately payable. To declare the principal amount of the Notes due and immediately payable, the trustee or the holders must deliver a notice that satisfies the requirements of the indenture. Upon a declaration by the trustee or the holders, we will be obligated to pay the principal amount of the Notes plus accrued and unpaid interest, if any.

This right does not apply if an event of default described in the fifth bullet point above occurs, or an event of default described in the fourth bullet point above that applies to all debt securities outstanding under the indenture occurs. If one of the events of default described in the fifth bullet point above occurs and is continuing, the debt securities, including the Notes, then outstanding under the indenture will be due and payable immediately. In addition, if the event of default described in the fourth bullet point occurs and is continuing and is common to all debt securities outstanding under the indenture, either the trustee or holders of at least 25% in principal amount of all of the debt securities then outstanding under the indenture, treated as one class, may declare the principal amount of all of the debt securities then outstanding under the indenture due and payable immediately.

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At any time after any declaration of acceleration of the Notes, but before a judgment or decree for payment of the money due has been obtained by the trustee, the event of default giving rise to the declaration of acceleration will, without further act, be deemed to have been waived, and such declaration and its consequences will, without further act, be deemed to have been rescinded and annulled if:

• we have paid or deposited with the trustee a sum sufficient to pay:

○ all overdue installments of interest, if any, on the Notes,

○ the principal of (and premium, if any, on) the Notes that have become due otherwise than by such declaration of acceleration and any interest thereon at the rate or rates prescribed therefor,

○ to the extent lawfully permitted, interest upon overdue interest, and

○ all sums paid or advanced by, and certain sums owed to, the trustee under the indenture; and

• all events of default, other than the non-payment of the principal amount of the Notes that became due solely by such declaration of acceleration, have been cured or waived as provided in the indenture. (Section 502)

For more information regarding waiver of defaults, please read “— Modification and Waiver.”

If an event of default occurs and is continuing, the trustee will generally have no obligation to exercise any of its rights or powers under the indenture at the request or direction of any of the holders, unless the holders offer indemnity satisfactory to the trustee. (Section 603) The holders of a majority in principal amount of the outstanding Notes will generally have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee for the Notes, provided that:

• the direction is not in conflict with any law or the indenture;

• the trustee may take any other action it deems proper which is not inconsistent with the direction; and

• the trustee will generally have the right to decline to follow the direction if an officer of the trustee determines, in good faith, that the proceeding would involve the trustee in personal liability or would otherwise be contrary to applicable law. (Section 512)

A holder of a Note may only pursue a remedy under the indenture if:

• the holder has previously given the trustee written notice of a continuing event of default for the Notes;

• holders of at least 25% in principal amount of the outstanding Notes have made a written request to the trustee to pursue that remedy;

• the holders have offered indemnity satisfactory to the trustee against the costs, expenses and liabilities to be incurred in conjunction with such request;

• the trustee fails to pursue that remedy within 60 days after receipt of the request; and

• during that 60-day period, the holders of a majority in principal amount of the Notes do not give the trustee a direction inconsistent with the request. (Section 507)

However, these limitations do not apply to a suit by a holder of a Note demanding payment of the principal, premium, if any, or interest on a Note on or after the date the payment is due. (Section 508)

We will be required to furnish to the trustee annually a statement by some of our officers regarding our performance or observance of any of the terms of the indenture and specifying all of our known defaults, if any. (Section 1004)

Modification and Waiver

We may enter into one or more supplemental indentures to the indenture with the trustee without the consent of the holders of the Notes to:

• evidence the succession of another corporation to us, or successive successions and the assumption of our covenants, agreements and obligations by a successor;

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• add to our covenants for the benefit of the holders of any series of debt securities or to surrender any of our rights or powers;

• add events of default for any series of debt securities;

• add to or change any provision of the indenture to the extent necessary to issue debt securities in bearer form;

• add to, change or eliminate any provision of the indenture applying to one or more series of debt securities, provided that if such action adversely affects the interests of any holder of any series of debt securities issued thereunder, the addition, change or elimination will become effective with respect to that series only when no security of that series remains outstanding;

• convey, transfer, assign, mortgage or pledge any property to or with the trustee or to surrender any right or power conferred upon us by the indenture;

• establish the form or terms of any series of debt securities;

• provide for uncertificated securities in addition to certificated securities;

• evidence and provide for successor trustees or to add to or change any provisions to the extent necessary to appoint a separate trustee or trustees for a specific series of debt securities;

• correct any ambiguity, defect or inconsistency under the indenture, provided that such action does not adversely affect the interests of the holders of any series of debt securities issued thereunder;

• supplement any provisions of the indenture necessary to defease and discharge any series of debt securities, provided that such action does not adversely affect the interests of the holders of any series of debt securities issued thereunder;

• comply with the rules or regulations of any securities exchange or automated quotation system on which any debt securities are listed or traded;

• add, change or eliminate any provisions of the indenture in accordance with any amendments to the Trust Indenture Act, provided that the action does not adversely affect the rights or interests of any holder of debt securities issued thereunder; or

• conform the text of the indenture or the Notes to any provisions of this “Description of the Exchange Notes,” as described in any officer’s certificate. (Section 901)

We may enter into one or more supplemental indentures to the indenture with the trustee to add to, change or eliminate provisions of the indenture or to modify the rights of the holders of one or more series of debt securities if we obtain the consent of the holders of a majority in principal amount of the outstanding debt securities of each series affected by the supplemental indenture, treated as one class. However, without the consent of the holders of each outstanding debt security affected by the supplemental indenture, we may not enter into a supplemental indenture that:

• changes the stated maturity of the principal of, or any installment of principal of or interest on, any debt security, except to the extent permitted by the indenture;

• reduces the principal amount of, or any premium or interest on, any debt security;

• reduces the amount of principal of an original issue discount security or any other debt security payable upon acceleration of the maturity thereof;

• changes the place or currency of payment of principal, premium, if any, or interest;

• impairs the right to institute suit for the enforcement of any payment on any debt security;

• reduces the percentage in principal amount of outstanding debt securities of any series, the consent of whose holders is required for modification of the indenture, for waiver of compliance with certain provisions of such indenture or for waiver of certain defaults;

• makes certain modifications to the provisions for modification of the indenture and for certain waivers, except to increase the principal amount of debt securities necessary to consent to any such charge;

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• makes any change that adversely affects the right to convert or exchange any debt security or decreases the conversion or exchange rate or increases the conversion price of any convertible or exchangeable debt security; or

• changes the terms and conditions pursuant to which any series of debt securities is secured in a manner adverse to the holders of the debt securities. (Section 902)

Holders of a majority in principal amount of the outstanding debt securities of any series may waive past defaults or noncompliance with restrictive provisions of the indenture with respect to such series. However, the consent of holders of each outstanding debt security of a series is required to:

• waive any default in the payment of principal, premium, if any, or interest, or

• waive any covenants and provisions of the indenture that may not be amended without the consent of the holder of each outstanding debt security of the series affected. (Sections 513 and 1006)

To determine whether the holders of the requisite principal amount of the outstanding debt securities have taken an action under the indenture as of a specified date:

• the principal amount of an “original issue discount security” that will be deemed to be outstanding will be the amount of the principal that would be due and payable as of that date upon acceleration of the maturity to that date;

• if, as of that date, the principal amount payable at the stated maturity of a debt security is not determinable, for example, because it is based on an index, the principal amount of the debt security deemed to be outstanding as of that date will be an amount determined in the manner prescribed for the debt security;

• the principal amount of a debt security denominated in one or more foreign currencies or currency units that will be deemed to be outstanding will be the United States dollar equivalent, determined as of that date in the manner prescribed for the debt security, of the principal amount of the debt security or, in the case of a debt security described in the two preceding bullet points, of the amount described above; and

• debt securities owned by us or any other obligor upon the debt securities or any of our or their Affiliates will be disregarded and deemed not to be outstanding.

An “original issue discount security” means a debt security issued under the indenture which provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration of maturity. Some debt securities, including those for the payment or redemption of which money has been deposited or set aside in trust for the holders and those that have been fully defeased pursuant to Section 1402 of the indenture, will not be deemed to be outstanding. (Section 101)

We will generally be entitled to set any day as a record date for determining the holders of outstanding debt securities of any series entitled to give or take any direction, notice, consent, waiver or other action under the indenture. In limited circumstances, the trustee will be entitled to set a record date for action by holders of outstanding debt securities. If a record date is set for any action to be taken by holders of a particular series of debt securities, the action may be taken only by persons who are holders of outstanding debt securities of that series on the record date. To be effective, the action must be taken by holders of the requisite principal amount of debt securities within a specified period following the record date. For any particular record date, this period will be 180 days or such shorter period as we may specify, or the trustee may specify, if it set the record date. (Section 104)

Satisfaction and Discharge

We may discharge our obligations under the indenture with respect to the Notes while Notes remain outstanding if (1) all outstanding Notes have become due and payable, (2) all outstanding Notes have or will become due and payable at their scheduled maturity within one year, or (3) all outstanding Notes are scheduled for redemption in one year, and in each case, we have deposited with the trustee an amount sufficient to pay and discharge all outstanding Notes on the date of their scheduled maturity or the scheduled date of redemption.

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Defeasance

If we deposit with the trustee funds or government securities sufficient to make payments on the Notes on the dates those payments are due and payable, then, at our option, either of the following will occur:

• we will be discharged from our obligations with respect to the Notes (“legal defeasance”); or

• with respect to the Notes, we will no longer have any obligation to comply with the events of default in the third bullet point under “— Events of Default” and the events of default described in the fourth bullet point under “— Events of Default” and the restrictions described under “— Certain Covenants — Merger, Consolidation, Sale, Lease or Conveyance” will no longer apply to us, but some of our other obligations under the indenture and the Notes, including our obligation to make payments on the Notes, will survive.

If we defease the Notes, the holders of the Notes will not be entitled to the benefits of the indenture, except for our obligations to:

• register the transfer or exchange of the Notes;

• replace mutilated, destroyed, lost or stolen Notes; and

• maintain paying agencies and hold moneys for payment in trust.

We will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the Notes to recognize gain or loss for federal income tax purposes and that the holders would be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the deposit and related defeasance had not occurred. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the United States Internal Revenue Service or a change in law to that effect. (Sections 1401, 1402, 1403 and 1404)

Paying Agent and Registrar

We will initially designate the trustee as the sole paying agent and registrar for the Notes.

We will pay interest on the Notes to the persons in whose names the Notes are registered at the close of business on the regular record date for each interest payment. However, we will pay the interest payable on the Notes at their stated maturity to the persons to whom we pay the principal amount of the Notes.

Any money deposited with the trustee or any paying agent for the payment of principal, premium, if any, and interest on the Notes that remains unclaimed for two years after the date the payments became due, may be repaid to us upon our request. After we have been repaid, holders entitled to those payments may only look to us for payment as our unsecured general creditors. The trustee and any paying agents will not be liable for those payments after we have been repaid. (Section 1003)

Exchange and Transfer of the Notes

We will issue the Notes in registered form, without coupons. We will issue Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

Holders may present Notes for exchange or for registration of transfer at the office of the security registrar or at the office of any transfer agent we designate for that purpose. The security registrar or designated transfer agent will exchange or transfer the Notes if it is satisfied with the documents of title and identity of the person making the request. We will not charge a service charge for any exchange or registration of transfer of Notes. However, we may require payment of a sum sufficient to cover any tax or other governmental charge payable for the exchange or registration of transfer. The trustee will serve as the security registrar. (Section 305)

At any time we may:

• designate additional transfer agents;

• rescind the designation of any transfer agent; or

• approve a change in the office of any transfer agent.

However, we are required to maintain a transfer agent in each place of payment for the Notes at all times. (Sections 305 and 1002)

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In the event we elect to redeem the Notes, neither we nor the trustee will be required to register the transfer or exchange of the Notes:

• during the period beginning at the opening of business 15 days before the day we send the notice of redemption for the Notes and ending at the close of business on the day the notice is sent; or

• if we have selected the Notes for redemption, in whole or in part, except for the unredeemed portion of the Notes. (Section 305)

Notices

Holders will receive notices by mail (or in accordance with the procedures of DTC) at their addresses as they appear in the security register. (Section 106)

Title

We may treat the person in whose name a Note is registered on the applicable record date as the owner of the Note for all purposes, whether or not it is overdue. (Section 309)

Governing Law

New York law will govern the indenture and the Notes. (Section 112)

Regarding the Trustee

Regions Bank will be the trustee, security registrar and paying agent under the indenture for the Notes. We maintain brokerage and lending relationships with the trustee and its affiliates, each of whom may maintain other relationships with us or our affiliates in the ordinary course of business.

If an event of default occurs under the indenture and is continuing, the trustee will be required to use the degree of care and skill of a prudent person in the conduct of that person’s own affairs. The trustee will become obligated to exercise any of its powers under the indenture at the request of any of the holders of any Notes issued under the indenture only after those holders have offered the trustee indemnity satisfactory to it.

If the trustee becomes one of our creditors, its rights to obtain payment of claims in specified circumstances, or to realize for its own account on certain property received in respect of any such claim as security or otherwise will be limited under the terms of the indenture. (Section 613) The trustee may engage in certain other transactions; however, if the trustee acquires any conflicting interest (within the meaning specified under the Trust Indenture Act), it will be required to eliminate the conflict or resign. (Section 608)

Book-Entry Delivery and Settlement

We will issue the Notes in the form of one or more global Notes in definitive, fully registered form. The global Notes will be registered in the name of Cede & Co., as nominee of DTC, and will remain in the custody of the trustee.

Beneficial interests in the global Notes will be represented through book-entry accounts of financial institutions acting on behalf of beneficial owners as direct and indirect participants in DTC. Investors may hold interests in the global Notes through DTC either directly if they are participants in DTC or indirectly through organizations that are participants in DTC. DTC has advised us as follows:

• DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered under Section 17A of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

• DTC holds securities that its participants deposit with DTC and facilitates the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in participants’ accounts, thereby eliminating the need for physical movement of securities certificates.

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• Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and other organizations.

• DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is owned by the users of its regulated subsidiaries.

• Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly.

The rules applicable to DTC and its direct and indirect participants are on file with the SEC.

We have provided the description of the operations and procedures of DTC in this prospectus solely as a matter of convenience. These operations and procedures are solely within the control of DTC and are subject to change by it from time to time. Neither we, the initial purchasers of the Outstanding Notes or the trustee takes any responsibility for these operations or procedures, and you are urged to contact DTC or its participants directly to discuss these matters.

We expect that under procedures established by DTC:

• upon deposit of the global Notes with DTC or its custodian, DTC will credit on its internal system the accounts of direct participants designated by the initial purchasers of the Outstanding Notes with portions of the principal amounts of the global Notes; and

• ownership of the Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC or its nominee, with respect to interests of direct participants, and the records of direct and indirect participants, with respect to interests of persons other than participants.

The laws of some jurisdictions may require that purchasers of securities take physical delivery of those securities in definitive form. Accordingly, the ability to transfer interests in the Notes represented by a global Note to those persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person having an interest in Notes represented by a global Note to pledge or transfer those interests to persons or entities that do not participate in DTC’s system, or otherwise to take actions in respect of such interest, may be affected by the lack of a physical definitive security in respect of such interest.

So long as DTC or its nominee is the registered owner of a global Note, DTC or that nominee will be considered the sole owner or holder of the Notes represented by that global Note for all purposes under the indenture and under the Notes. Except as provided below, owners of beneficial interests in a global Note will not be entitled to have Notes represented by that global Note registered in their names, will not receive or be entitled to receive physical delivery of certificated Notes and will not be considered the owners or holders thereof under the indenture or under the Notes for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee. Accordingly, each holder owning a beneficial interest in a global Note must rely on the procedures of DTC and, if that holder is not a direct or indirect participant, on the procedures of the participant through which that holder owns its interest, to exercise any rights of a holder of Notes under the indenture or the global Note.

Neither we nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of the Notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to the Notes.

Payments on the Notes represented by the global Notes will be made to DTC or its nominee, as the case may be, as the registered owner thereof. We expect that DTC or its nominee, upon receipt of any payment on the Notes represented by a global Note, will credit participants’ accounts with payments in amounts proportionate to their respective beneficial interests in the global Note as shown in the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in the global Note held through such participants will be governed by standing instructions and customary practice as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. The participants will be responsible for those payments.

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Initial settlement for the Notes will be made in immediately available funds. Secondary market trading between DTC participants will occur in the ordinary way in accordance with DTC rules and will be settled in immediately available funds. Although DTC has agreed to the foregoing procedures to facilitate transfers of the Notes among its participants, it is under no obligation to perform or continue to perform such procedures and such procedures may be changed or discontinued at any time.

Secondary market trading between Clearstream Banking, société anonyme (“Clearstream”) participants and/or Euroclear Bank S.A./N.V., as operator of the Euroclear System (“Euroclear”) participants will occur in the ordinary way in accordance with the applicable rules and operating procedures of Clearstream and Euroclear, as applicable.

Cross-market transfers between participants in DTC, on the one hand, and participants in Euroclear or Clearstream, on the other hand, will be effected through DTC in accordance with the DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective United States depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (European time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its United States depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the global securities through DTC, and making or receiving payment in accordance with normal procedures for same-day fund settlement. Participants in Euroclear or Clearstream may not deliver instructions directly to their respective United States depositaries.

Due to time zone differences, the securities accounts of a participant in Euroclear or Clearstream purchasing an interest in a global security from a direct participant in DTC will be credited, and any such crediting will be reported to the relevant participant in Euroclear or Clearstream, during the securities settlement processing day (which must be a business day for Euroclear or Clearstream) immediately following the settlement date of DTC. Cash received in Euroclear or Clearstream as a result of sales of interests in a global security by or through a participant in Euroclear or Clearstream to a direct participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Certificated Notes

Certificated Notes will be issued to each person that DTC identifies as the beneficial owner of the Notes represented by the global Notes, upon surrender by DTC of the global Notes, if (i) DTC or any successor depositary (the “depositary”) notifies us that it is no longer willing or able to act as a depositary for the global Notes or DTC ceases to be registered as a clearing agency under the Exchange Act, and a successor depositary is not appointed within 90 days of such notice or cessation, (ii) we, at our option and subject to DTC procedures, notify the trustee in writing that we elect to cause the issuance of Notes in definitive form under the indenture or (iii) upon the occurrence of certain other events as provided pursuant to the indenture.

150

REGISTRATION RIGHTS AGREEMENT

We entered into a registration rights agreement with the initial purchasers of the Outstanding Notes on September 11, 2019 in connection with the closing of the private offering of the Outstanding Notes. In the registration rights agreement, we agreed for the benefit of the holders of the Outstanding Notes to use commercially reasonable efforts to (a) as soon as practicable after the closing of the private offering of the Outstanding Notes, but in any event within 365 days after the closing date of the private offering of the Outstanding Notes, file a registration statement on an appropriate registration form with respect to registered offers to exchange the Outstanding Notes for new notes with terms substantially identical in all material respects to the Outstanding Notes (except that the Exchange Notes will not be subject to additional interest provisions or restrictions on ownership or transfer), (b) cause the registration statement to be declared effective under the Securities Act within 365 days after the closing date of the private offering of the Outstanding Notes and (c) file any pre- and post-effective amendments, if applicable, and any filings required in connection with the registration and qualification of the Exchange Notes under state securities laws.

When the SEC declares the exchange offer registration statement effective, we will offer the Exchange Notes in return for the Outstanding Notes. The exchange offer will remain open for at least 20 business days (or longer if required by applicable law) after the date we send notice of the exchange offer to the holders of Outstanding Notes. For each Outstanding Note surrendered to us in the exchange offer, the holders of the Outstanding Notes will receive an Exchange Note of equal principal amount. Interest on each Exchange Note will accrue (a) from the last interest payment date on which interest was paid on the Outstanding Note surrendered in exchange therefor or (b) if no interest has been paid on the Outstanding Note, from the closing date of the private offering of the Outstanding Notes. A holder of Outstanding Notes that participates in the exchange offer will be required to make certain representations to us (as described in the registration rights agreement). We will use commercially reasonable efforts to commence the exchange offer not later than 30 days after the registration statement has become effective. Under existing interpretations of the SEC contained in several no-action letters to third parties, the Exchange Notes will generally be freely transferable after the exchange offer without further registration under the Securities Act, except that any broker-dealer that participates in the exchange offer must deliver a prospectus meeting the requirements of the Securities Act when it resells the Exchange Notes.

We will agree to use commercially reasonable efforts to make available, for a period ending on the earlier of (a) 180 days after the date the registration statement is declared effective and (b) the date upon which a broker-dealer is no longer required to deliver a prospectus, a prospectus meeting the requirements of the Securities Act for use by participating broker-dealers and other persons, if any, with similar prospectus delivery requirements for use in connection with any resale of Exchange Notes. Outstanding Notes not tendered in the exchange offer will bear interest at the rates set forth on the cover page of this prospectus and be subject to all the terms and conditions specified in the indenture, including transfer restrictions, but will not retain any rights under the registration rights agreement (including with respect to increases in annual interest rate described below) after the consummation of the exchange offer.

If (a) we are not required to file a registration statement or consummate the exchange offer because it would violate any applicable law or applicable policies of the SEC or (b) with respect to any holder of the Outstanding Notes (i) such holder is prohibited by applicable law or SEC policy from participating in the exchange offer, (ii) such holder may not resell the Outstanding Notes acquired by it in the exchange offer to the public without delivering a prospectus and the prospectus contained in the registration statement is not appropriate or available for such resales by such holder or (iii) such holder is a broker-dealer and holds Outstanding Notes acquired directly from us or one of our affiliates, then we will use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the Outstanding Notes and to keep that shelf registration statement effective, supplemented and amended and to ensure that it conforms with the requirements of the registration rights agreement, the Securities Act and the policies of the SEC for at least two years following the effective date of such shelf registration statement, or such shorter period that will terminate when all Outstanding Notes covered by the shelf registration statement have been sold pursuant to the shelf registration statement. A holder of Outstanding Notes that sells Outstanding Notes under the shelf registration statement will be required to provide us with certain information for use in connection with any shelf registration statement or prospectus included therein within 20 business days after receiving a request by us to do so. Each holder as to which any shelf registration statement is being effected agrees to furnish promptly to us all information required to be disclosed in order to make the information previously provided by such holder not materially misleading.

151

A holder of Outstanding Notes that sells Outstanding Notes under the shelf registration statement will be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with those sales and will be bound by the provisions of the registration rights agreement that are applicable to such a holder of Outstanding Notes (including certain indemnification obligations). Holders of Outstanding Notes will also be required to suspend their use of the prospectus included in the shelf registration statement under specified circumstances upon receipt of notice from us. Under applicable interpretations of the staff of the SEC, our affiliates will not be permitted to exchange their Outstanding Notes for Exchange Notes in the exchange offer.

If (a) any of the registration statements required to be filed by the registration rights agreement have not been filed on or before the date specified, (b) any of such registration statements have not been declared effective on or before the date specified, (c) the exchange offer has not been consummated within 30 days or 45 days, as applicable, after the registration statement has been declared effective or (d) any registration statement has been declared effective and such registration statement ceases to be effective or fails to be usable without being succeeded immediately by a post-effective amendment to such registration statement that is immediately declared effective (each, a “Registration Default”), then additional interest shall accrue on the principal amount of the Outstanding Notes at a rate of 0.25% per annum for the first 90-day period following a Registration Default and an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue (provided that the rate at which such additional interest accrues may in no event exceed 1.00% per annum in the aggregate for all Registration Defaults). Following the cure of a Registration Default, the interest rate will be reduced to the original interest rate. If a different Registration Default occurs after such reduction, the interest rate will again be increased as described above.

Any amounts of additional interest due will be payable in cash on the same original interest payment dates as interest on the Outstanding Notes is payable. The Exchange Notes will be accepted for clearance through DTC.

This summary of the provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, copies of which are available from us upon request.

152

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following discussion is a summary of the material United States federal income tax considerations, as of the date of this prospectus, relevant to a beneficial owner of Outstanding Notes (for the purposes of this section, a “holder”) relating to the exchange of Outstanding Notes for Exchange Notes pursuant to the exchange offer. This summary is based upon provisions of the IRC, applicable Treasury regulations, administrative rulings and judicial decisions, all as of the date of this prospectus, any of which may subsequently be changed, possibly retroactively, so as to result in United States federal income tax consequences different from those discussed below.

We cannot assure you that the IRS will not challenge one or more of the tax consequences described in this discussion. We have not obtained, nor do we intend to obtain, a ruling from the IRS with respect to the United States federal income tax consequences described below. If the IRS contests a conclusion set forth herein, no assurance can be given that a holder would ultimately prevail in a final determination by a court.

This summary only applies to holders that acquired their Outstanding Notes upon original issuance, exchange their Outstanding Notes for Exchange Notes, and hold the Outstanding Notes and Exchange Notes as capital assets for United States federal income tax purposes (generally property held for investment). This summary does not discuss any aspect of United States federal tax law other than income taxation, and does not address state, local or foreign tax considerations. Moreover, this summary does not address all aspects of United States federal income taxation that may be relevant to holders, nor does it address all tax consequences that may be relevant to such holders in light of their personal circumstances or particular situations, such as:

• tax consequences to investors that may be subject to special tax treatment, including brokers, dealers in securities, banks, financial institutions, regulated investment companies, real estate investment trusts, tax-exempt entities, retirement plans and other tax-deferred accounts, insurance companies, partnerships or other pass-through entities for United States federal income tax purposes (or investors in such entities), certain former citizens or former long-term residents of the United States, or traders in securities that elect to use a mark-to-market method of tax accounting for their securities;

• tax consequences to persons holding Outstanding Notes or Exchange Notes as a part of an integrated or conversion transaction or a straddle, or persons deemed to sell Exchange Notes under the constructive sale provisions of the IRC;

• tax consequences to United States holders whose “functional currency” is not the United States dollar; and

• tax consequences under the alternative minimum tax provisions of the IRC.

Investors should consult their own tax advisors concerning the United States federal income tax consequences in light of their own specific situations, as well as consequences arising under other federal tax laws (such as the federal estate or gift tax laws) and the laws of any state, local, foreign or other taxing jurisdiction.

If an entity or arrangement treated as a partnership for United States federal income tax purposes holds Outstanding Notes, the tax treatment of a partner of such partnership will generally depend upon the status of the partner and the activities of the partner and the partnership. Any beneficial owner holding Outstanding Notes through an entity or arrangement that may be treated as a partnership for United States federal income tax purposes is urged to consult its own tax advisor regarding the tax consequences of the exchange offer to such partner.

Exchange of Outstanding Notes Pursuant to the Exchange Offer

The exchange of Outstanding Notes for Exchange Notes in the exchange offer will not constitute a taxable exchange. As a result, (1) a holder will not recognize a taxable gain or loss as a result of exchanging such holder’s Outstanding Notes for Exchange Notes in the exchange offer; (2) the holding period of the Exchange Notes received will include the holding period of the Outstanding Notes exchanged therefor; and (3) the adjusted tax basis of the Exchange Notes received will be the same as the adjusted tax basis of the Outstanding Notes exchanged therefor immediately before such exchange. Holders should consult their own tax advisors regarding the potential United States federal income tax consequences of the exchange of the Outstanding Notes for Exchange Notes in the exchange offer.

153

THE PRECEDING DISCUSSION OF UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. WE URGE EACH HOLDER TO CONSULT ITS OWN TAX ADVISOR REGARDING THE PARTICULAR UNITED STATES FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF EXCHANGING OUTSTANDING NOTES FOR EXCHANGE NOTES PURSUANT TO THE EXCHANGE OFFER, INCLUDING THE CONSEQUENCES OF ANY PROPOSED CHANGE IN APPLICABLE LAWS.

154

PLAN OF DISTRIBUTION

Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe that you may transfer Exchange Notes issued in the exchange offer in exchange for the Outstanding Notes if:

• any Exchange Notes to be received by you will be acquired in the ordinary course of your business; and

• you have no arrangement or understanding with any person or entity to participate in the distribution (within the meaning of the Securities Act) of the Exchange Notes in violation of the provisions of the Securities Act.

You may not participate in the exchange offer if you are:

• an “affiliate,” as defined in Rule 405 under the Securities Act, of us; or

• a broker-dealer that will receive Exchange Notes for your own account in exchange for Outstanding Notes that were acquired as a result of market-making or other trading activities, unless you agree to deliver this prospectus (or, to the extent permitted by law, make this prospectus available to purchasers) in connection with any resale of your Exchange Notes.

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer must acknowledge that it will deliver this prospectus in connection with any resale of such Exchange Notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as the exchange offer, other than a resale of an unsold allotment from the original sale of the Outstanding Notes, with this prospectus. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received for their own account in exchange for Outstanding Notes where such Outstanding Notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period ending on December 7, 2020, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until such date, all dealers effecting transactions in Exchange Notes may be required to deliver this prospectus.

If you wish to exchange your Outstanding Notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer — Procedures for Tendering” in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your Outstanding Notes in the exchange offer. In addition, if you are a broker-dealer who receives Exchange Notes for your own account in exchange for Outstanding Notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver this prospectus in connection with any resale by you of such Exchange Notes.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers. Exchange Notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:

• in the over-the-counter market;

• in negotiated transactions;

• through the writing of options on the Exchange Notes; or

• a combination of such methods of resale; at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such Exchange Notes. Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act. Each letter of transmittal states that by acknowledging that it will deliver and by delivering this prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

155

For the period described in Section 4(3) of and Rule 174 under the Securities Act that is applicable to transactions by brokers or dealers with respect to the Exchange Notes, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents.

We have agreed to indemnify the holders of the Outstanding Notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

LEGAL MATTERS

The validity of the Exchange Notes offered hereby will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Baker Botts L.L.P. will deliver an opinion stating that the Exchange Notes will be binding obligations of Cleco. In rendering its opinion, Baker Botts L.L.P. will rely on the opinion of Phelps Dunbar, L.L.P., with respect to certain matters regarding Louisiana law.

EXPERTS

The financial statements for Cleco Corporate Holdings LLC as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019 included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements for Cleco Power LLC as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019 included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

EXCHANGE AGENT

We have appointed Regions Bank as exchange agent in connection with the exchange offer. Holders of Outstanding Notes should direct questions, requests for assistance or additional copies of this prospectus or letters of transmittal to the exchange agent as follows:

REGIONS BANK
By Air Courier or By Registered or Certified Mail
Corporate Trust Operations
Lakeshore Operations Center
201 Milan Parkway, 2^nd Floor
Birmingham, Alabama 35211

Holders can inquire about the exchange of Outstanding Notes for Exchange Notes in the exchange offer by calling Regions Bank at 1-866-512-3479. Please refer to the following numbers when making inquiries: CUSIPs: 144A: 18551Q AA5; Reg. S U1851U AA6.

Delivery of a letter of transmittal to any address or facsimile number other than the one set forth above will not constitute a valid delivery.

156

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

Consolidated Financial Statements (Audited)
Managements’ Reports on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-4
Financial Statements of Cleco
Consolidated Statements of Income for the years ended December 31, 2019, 2018, and 2017	F-5
Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018, and 2017	F-6
Consolidated Balance Sheets at December 31, 2019, and 2018	F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018, and 2017	F-9
Consolidated Statements of Changes in Equity for the years ended December 31, 2019, 2018, and 2017	F-11
Report of Independent Registered Public Accounting Firm	F-12
Financial Statements of Cleco Power
Consolidated Statements of Income for the years ended December 31, 2019, 2018, and 2017	F-13
Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018, and 2017	F-14
Consolidated Balance Sheets at December 31, 2019, and 2018	F-15
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018, and 2017	F-17
Consolidated Statements of Changes in Equity for the years ended December 31, 2019, 2018, and 2017	F-19
Notes to the Audited Financial Statements	F-21
Financial Statement Schedules
Schedule I—Financial Statements of Cleco Holdings (Parent Company Only)
Condensed Statements of Income for the years ended December 31, 2019, 2018, and 2017	F-85
Condensed Statements of Comprehensive Income for the years ended December 31, 2019, 2018, and 2017	F-86
Condensed Balance Sheets at December 31, 2019, and 2018	F-87
Condensed Statements of Cash Flows for the years ended December 31, 2019, 2018, and 2017	F-88
Notes to the Condensed Financial Statements	F-89
Schedule II—Valuation and Qualifying Accounts	F-92
Condensed Consolidated Financial Statements (Unaudited)
Financial Statements of Cleco
Condensed Consolidated Statements of Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-94
Condensed Consolidated Statements of Comprehensive Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-95
Condensed Consolidated Balance Sheets (Unaudited) at March 31, 2020, and at December 31, 2019	F-96
Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2020, and 2019	F-98
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited) for the three months ended March 31, 2020, and 2019	F-99
Financial Statements of Cleco Power
Condensed Consolidated Statements of Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-100
Condensed Consolidated Statements of Comprehensive Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-101
Condensed Consolidated Balance Sheets (Unaudited) at March 31, 2020, and at December 31, 2019	F-102
Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2020, and 2019	F-104
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited) for the three months ended March 31, 2020, and 2019	F-106
Notes to the Unaudited Interim Financial Statements	F-108

Financial Statement Schedules other than those shown in the above index are omitted because they are either not required or are not applicable or the required information is shown in the Consolidated Financial Statements and Notes thereto.

F-1

Managements’ Reports on Internal Control Over Financial Reporting

The management of Cleco are 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’s internal control over financial reporting is a process designed by, or under the supervision of, Cleco’s principal executive and financial officers and effected by Cleco’s board of managers, 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 generally accepted accounting principles.

As a result of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness in 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.

The management of Cleco, under the supervision of Cleco’s principal executive officer and principal financial officer, conducted an assessment of the effectiveness of Cleco’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control-Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission.

Based on this assessment, the management of Cleco concluded that, as of December 31, 2019, Cleco’s internal control over financial reporting was not effective due to the material weaknesses in internal control over financial reporting discussed below.

On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in South Central Generating in a purchase business combination. Management has excluded South Central Generating from Cleco’s assessment of internal control over financial reporting as of December 31, 2019. South Central Generating is a wholly-owned subsidiary and represented approximately 14% of consolidated total assets as of December 31, 2019, and 30% of consolidated total revenues for the year ended December 31, 2019.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.

During the three months ended June 30, 2019, Cleco transitioned to a new enterprise business application (ERP) which required it to modify certain existing and implement new processes and internal controls to adapt to the new application. Subsequent to the implementation, a material weakness related to the design and operation of certain information technology (IT) general controls for information systems that are relevant to the preparation of the financial statements were identified.

Specifically, Cleco did not sufficiently design and maintain (i) testing and approval controls for program development to ensure the implementation of a new ERP system is aligned with business and IT requirements which contributed to deficiencies related to (ii) user access controls to ensure appropriate segregation of duties and that adequately restrict user and privileged access to certain financial applications, programs, and data to appropriate personnel, and (iii) program change management controls for certain financial systems to ensure that information technology program and data changes affecting financial IT applications and underlying accounting records are identified, tested, authorized, and implemented appropriately.

These IT deficiencies did not result in a material misstatement to the financial statements; however, the deficiencies, when aggregated, could impact maintaining effective segregation of duties, as well as the effectiveness of IT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports) that could result in misstatements potentially impacting all financial statement accounts and disclosures that would not be prevented or detected. Accordingly, management has determined these deficiencies in the aggregate constitute a material weakness.

Cleco also identified a material weakness in the design and operating effectiveness of controls over the completeness and accuracy of billed and unbilled revenue from contracts with customers. Specifically, there were deficiencies in controls to (i) verify the accuracy of billing estimates, (ii) record revenue in the appropriate period, and (iii) validate the completeness and accuracy of reports used in recording unbilled revenue.

F-2

The deficiencies resulted in immaterial errors and out-of-period adjustments in recorded retail revenue, customer accounts receivable, and unbilled revenue for the interim periods ended June 30, 2019, and September 30, 2019. However, the identified control deficiencies could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Because of these material weaknesses, the management of Cleco concluded that Cleco did not maintain effective internal control over financial reporting as of December 31, 2019.

Remediation Plan

Cleco began taking steps to remediate the underlying cause of these material weaknesses and improve the design and operating effectiveness of its internal control over financial reporting during the three month period ending September 30 2019, and continued this effort through December 31, 2019. This plan includes, but is not limited to the following:

• Providing additional training and instructional guidance to control owners on management’s expectations for control performance and related evidence to maintain.

• Reassessing extent of access assigned to users to ensure the access granted is commensurate with each user’s respective roles and responsibilities.

• Enabled configurations to allow for automated exception identification in key processes.

• Enhancing the level of precision and addressing identified gaps in the design of existing controls.

• Designing and implementing new controls (both preventive and detective) to address any gaps in how relevant risks are being addressed.

• Performing additional monitoring and testing over the implementation and operating effectiveness of existing controls.

• Performing an assessment of the newly implemented ERP system to identify opportunities for more comprehensive control coverage over identified risks as well as opportunities for enhanced system automation.

As the management of Cleco continues to evaluate and work to improve Cleco’s internal control over financial reporting, Cleco may take additional measures to address these control deficiencies, or Cleco may modify some of the remediation measures to improve the design and/or operating effectiveness of those measures. Management of Cleco has made significant progress in its remediation efforts. However, the material weakness in IT general controls and the material weakness over revenue will not be considered remediated until the applicable new controls operate for a sufficient period of time where management is able to conclude, through testing, that these controls are operating effectively.

Changes in Internal Control over Financial Reporting

There have been no changes in Cleco’s internal control over financial reporting that occurred during the quarter ended December 31, 2019, that have materially affected, or are reasonably likely to materially affect, Cleco’s internal control over financial reporting, with the exception of the remediation efforts discussed above.

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Member of Cleco Corporate Holdings LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Cleco Corporate Holdings LLC and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive income, of member's equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes and schedules of condensed financial information of parent as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019 and of valuation and qualifying accounts for each of the three years in the period ended December 31, 2019 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 4 to the consolidated financial statements, the Company changed the manner in which it accounts for leases as of January 1, 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
New Orleans, LA
March 3, 2020

We have served as the Company’s auditor since 2016.

F-4

CLECO
Consolidated Statements of Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating revenue
Electric operations	$1,496,736	$1,181,907	$1,097,632
Other operations	182,832	82,332	79,580
Gross operating revenue	1,679,568	1,264,239	1,177,212
Electric customer credits	(39,963)	(33,195)	(1,566)
Operating revenue, net	1,639,605	1,231,044	1,175,646
Operating expenses
Fuel used for electric generation	466,831	382,556	339,346
Purchased power	280,991	168,180	152,913
Other operations and maintenance	291,031	197,032	197,608
Depreciation and amortization	216,320	170,414	166,854
Taxes other than income taxes	61,870	48,791	48,546
Merger transaction and commitment costs	7,668	19,514	5,152
Total operating expenses	1,324,711	986,487	910,419
Operating income	314,894	244,557	265,227
Interest income	6,090	6,073	1,424
Allowance for equity funds used during construction	15,397	14,159	8,320
Other income (expense), net	758	(14,328)	(6,899)
Interest charges
Interest charges, net	147,346	131,348	125,200
Allowance for borrowed funds used during construction	(6,037)	(4,706)	(2,287)
Total interest charges	141,309	126,642	122,913
Income before income taxes	195,830	123,819	145,159
Federal and state income tax expense	43,165	29,382	7,079
Net income	$152,665	$94,437	$138,080

The accompanying notes are an integral part of the consolidated financial statements.

F-5

CLECO
Consolidated Statements of Comprehensive Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Net income	$152,665	$94,437	$138,080
Other comprehensive (loss) income, net of tax
Postretirement benefits (loss) gain (net of tax benefit of $6,808, tax expense of $1,868, and tax benefit of $2,764, respectively)	(19,299)	5,296	(4,421)
Total other comprehensive (loss) income, net of tax	(19,299)	5,296	(4,421)
Comprehensive income, net of tax	$133,366	$99,733	$133,659

The accompanying notes are an integral part of the consolidated financial statements.

F-6

CLECO
Consolidated Balance Sheets

	AT DEC. 31,
(THOUSANDS)	2019	2018
Assets
Current assets
Cash and cash equivalents	$116,292	$110,175
Restricted cash and cash equivalents	11,100	11,241
Customer accounts receivable (less allowance for doubtful accounts of $3,005 in 2019 and $814 in 2018)	83,591	50,043
Other accounts receivable	35,731	27,196
Unbilled revenue	33,207	35,314
Fuel inventory, at average cost	83,061	82,836
Materials and supplies, at average cost	118,858	92,671
Energy risk management assets	7,023	23,355
Accumulated deferred fuel	22,910	20,112
Cash surrender value of company-/trust-owned life insurance policies	86,096	80,391
Prepayments	7,711	7,911
Regulatory assets	19,807	22,461
Other current assets	12,688	1,256
Total current assets	638,075	564,962
Property, plant, and equipment
Property, plant, and equipment	4,982,255	3,728,477
Accumulated depreciation	(454,874)	(303,727)
Net property, plant, and equipment	4,527,381	3,424,750
Construction work in progress	117,630	354,045
Total property, plant, and equipment, net	4,645,011	3,778,795
Equity investment in investee	17,072	18,172
Goodwill	1,490,797	1,490,797
Prepayments	25,949	2,251
Operating lease right of use assets	28,791	—
Restricted cash and cash equivalents	15,203	18,670
Note receivable	15,198	15,829
Regulatory assets	422,431	425,330
Intangible assets	138,103	84,307
Other deferred charges	39,668	37,701
Total assets	$7,476,298	$6,436,814

The accompanying notes are an integral part of the consolidated financial statements.

F-7

	AT DEC. 31,
(THOUSANDS)	2019	2018
Liabilities and member’s equity
Liabilities
Current liabilities
Long-term debt and finance leases due within one year	$125,986	$21,128
Accounts payable	158,863	156,589
Accounts payable- affiliate	33,780	—
Customer deposits	58,289	61,736
Provision for rate refund	38,903	35,842
Taxes payable, net	8,931	43,674
Interest accrued	19,001	15,828
Energy risk management liabilities	4,113	468
Regulatory liabilities – other	6,675	2,496
Deferred compensation	12,115	10,753
Other current liabilities	44,683	30,536
Total current liabilities	511,339	379,050
Long-term liabilities and deferred credits
Accumulated deferred federal and state income taxes, net	657,058	608,030
Postretirement benefit obligations	283,075	249,264
Regulatory liabilities – other	—	2,496
Regulatory liabilities – deferred taxes, net	146,948	155,537
Restricted storm reserve	12,285	15,485
Deferred lease revenue	49,862	—
Intangible liabilities	31,872	—
Asset retirement obligations	23,173	6,881
Operating lease liabilities	25,779	—
Other deferred credits	27,222	20,846
Total long-term liabilities and deferred credits	1,257,274	1,058,539
Long-term debt and finance leases, net	3,064,679	2,874,485
Total liabilities	4,833,292	4,312,074
Commitments and contingencies (Note 15)
Member’s equity	2,643,006	2,124,740
Total liabilities and member’s equity	$7,476,298	$6,436,814

The accompanying notes are an integral part of the consolidated financial statements.

F-8

CLECO
Consolidated Statements of Cash Flows

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating activities
Net income	$152,665	$94,437	$138,080
Adjustment to reconcile net income to net cash provided by operating activities
Depreciation and amortization	245,682	187,426	186,326
Provision for doubtful accounts	2,348	797	2,778
Unearned compensation expense	5,409	5,837	3,745
Allowance for equity funds used during construction	(15,397)	(14,159)	(8,320)
Loss on risk management assets and liabilities, net	10,180	—	—
Deferred lease revenue	(8,439)	—	—
Deferred income taxes	40,081	6,543	(41,966)
Deferred fuel costs	11,132	(18,549)	11,909
Cash surrender value of company-/trust-owned life insurance	(5,705)	2,726	(5,892)
Changes in assets and liabilities
Accounts receivable	(9,532)	3,123	(25,584)
Accounts receivable – affiliate	(1,041)	635	(622)
Unbilled revenue	2,107	1,084	(2,129)
Fuel inventory and materials and supplies	18,463	(2,981)	(44,995)
Prepayments	(14,479)	153	2,852
Accounts payable	13,507	18,898	14,705
Accounts payable – affiliate	3,175	—	—
Customer deposits	5,888	13,757	12,381
Provision for merger commitments	(1,848)	(3,273)	(12,971)
Postretirement benefit obligations	(10,981)	4,646	4,884
Regulatory assets and liabilities, net	90	3,032	12,531
Other deferred accounts	(7,147)	(9,748)	(8,380)
Taxes accrued	(3,619)	20,976	23,118
Interest accrued	3,173	1,124	(582)
Deferred compensation	1,316	(1,521)	308
Other operating	(6,909)	2,798	3,252
Net cash provided by operating activities	430,119	317,761	265,428
Investing activities
Additions to property, plant, and equipment	(323,791)	(291,061)	(236,932)
Allowance for equity funds used during construction	15,397	14,159	8,320
Proceeds from sale of property, plant, and equipment	739	995	17,499
Reimbursement for property loss	141	1,375	187
Return of equity investment in investee	1,100	—	500
Return of investment in company-owned life insurance	3,761	—	—
Return of equity investment in tax credit fund	1,625	2,775	7,502
Issuance of note receivable	—	(16,800)	—
Payment to acquire business, net of cash received	(814,969)	—	—
Other investing	574	397	(630)
Net cash used in investing activities	(1,115,423)	(288,160)	(203,554)

The accompanying notes are an integral part of the consolidated financial statements.

F-9

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Financing activities
Draws on credit facilities	108,000	—	179,000
Payments on credit facilities	(108,000)	—	(179,000)
Issuances of long-term debt	700,000	50,000	125,000)
Repayments of long-term debt	(390,571)	(19,193)	(17,896)
Payment of financing costs	(5,959)	(791)	(463)
Contribution from member	384,900	—	—
Distributions to member	—	(71,350)	(84,065)
Other financing	(557)	(383)	(1,819)
Net cash provided by (used in) financing activities	687,813	(41,717)	20,757
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents	2,509	(12,116)	82,631
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period	140,086(1)	152,202	69,571
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period	$142,595(2)	$140,086	$152,202
Supplementary cash flow information
Interest paid, net of amount capitalized	$130,988	$124,154	$118,009
Income taxes (refunded) paid, net	$(19)	$272	$(6)
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$16,124	$56,450	$31,083
Non-cash additions to property, plant, and equipment	$52	$1,224	$3,015
Incurrence of finance lease obligation – barges	$—	$16,800	$—

(1)
Includes cash and cash equivalents of $110,175, current restricted cash and cash equivalents of $11,241, and non-current restricted cash and cash equivalents of $18,670.

(2)
Includes cash and cash equivalents of $116,292, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $15,203.

The accompanying notes are an integral part of the consolidated financial statements.

F-10

CLECO
Consolidated Statements of Changes in Member’s Equity

(THOUSANDS)	MEMBERSHIP INTEREST	RETAINED EARNINGS / (ACCUMULATED DEFICIT)	AOCI	TOTAL MEMBER’S EQUITY
Balances, Dec. 31, 2016	$2,069,376	$(24,113)	$1,500	$2,046,763
Distributions to member	—	(84,065)	—	(84,065)
Net income	—	138,080	—	138,080
Other comprehensive loss, net of tax	—	—	(4,421)	(4,421)
Balances, Dec. 31, 2017	$2,069,376	$29,902	$(2,921)	$2,096,357
Distributions to member	—	(71,350)	—	(71,350)
Net income	—	94,437	—	94,437
Other comprehensive income, net of tax	—	—	5,296	5,296
Reclassification of effect of tax rate change	—	589	(589)	—
Balances, Dec. 31, 2018	$2,069,376	$53,578	$1,786	$2,124,740
Contributions from member	—	384,900	—	384,900
Net income	—	152,665	—	152,665
Other comprehensive loss, net of tax	—	—	(19,299)	(19,299)
Balances, Dec. 31, 2019	$2,069,376	$591,143	$(17,513)	$2,643,006

The accompanying notes are an integral part of the consolidated financial statements.

F-11

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Member of Cleco Power LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Cleco Power LLC and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive income, of member's equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes and schedule of valuation and qualifying accounts for each of the three years in the period ended December 31, 2019 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

Change in Accounting Principle

As discussed in Note 4 to the consolidated financial statements, the Company changed the manner in which it accounts for leases as of January 1, 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
New Orleans, LA
March 3, 2020

We have served as the Company’s auditor since 2016.

F-12

CLECO POWER
Consolidated Statements of Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating revenue
Electric operations	$1,130,928	$1,191,587	$1,108,389
Other operations	$72,833	$82,330	$77,522
Affiliate revenue	$3,125	$874	$851
Gross operating revenue	$1,206,886	$1,274,791	$1,186,762
Electric customer credits	$(38,516)	$(33,195)	$(1,566)
Operating revenue, net	$1,168,370	$1,241,596	$1,185,196
Operating expenses
Fuel used for electric generation	$385,317	$382,556	$339,346
Purchased power	$111,208	$168,180	$152,913
Other operations and maintenance	$207,164	$202,552	$202,738
Depreciation and amortization	$172,471	$162,069	$158,415
Taxes other than income taxes	$43,742	$47,267	$46,539
Total operating expenses	$919,902	$962,624	$899,951
Operating income	$248,468	$278,972	$285,245
Interest income	$4,744	$5,052	$1,283
Allowance for equity funds used during construction	$15,397	$14,159	$8,320
Other expense, net	$(3,616)	$(8,699)	$(7,417)
Interest charges
Interest charges, net	$77,316	$76,009	$71,649
Allowance for borrowed funds used during construction	$(6,037)	$(4,706)	$(2,287)
Total interest charges	$71,279	$71,303	$69,362
Income before income taxes	$193,714	$218,181	$218,069
Federal and state income tax expense	$45,452	$55,924	$67,331
Net income	$148,262	$162,257	$150,738

The accompanying notes are an integral part of the consolidated financial statements.

F-13

CLECO POWER
Consolidated Statements of Comprehensive Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Net income	$148,262	$162,257	$150,738
Other comprehensive income (loss), net of tax
Postretirement benefits gain (loss) (net of tax benefit of $3,408, tax expense of $968, and tax benefit of $296, respectively)	$(9,657)	$2,743	$(472)
Amortization of interest rate derivatives to earnings (net of tax expense of $90, $90, and $132, respectively)	$254	$254	$211
Total other comprehensive (loss) income, net of tax	$(9,403)	$2,997	$(261)
Comprehensive income, net of tax	$138,859	$165,254	$150,477

The accompanying notes are an integral part of the consolidated financial statements.

F-14

CLECO POWER
Consolidated Balance Sheets

	AT DEC. 31,
(THOUSANDS)	2019	2018
Assets
Utility plant and equipment
Property, plant, and equipment	$5,489,457	$5,015,004
Accumulated depreciation	$(1,905,031)	$(1,804,563)
Net property, plant, and equipment	$3,584,426	$3,210,441
Construction work in progress	$111,687	$351,828
Total utility plant and equipment, net	$3,696,113	$3,562,269
Current assets
Cash and cash equivalents	$55,489	$31,987
Restricted cash and cash equivalents	$11,100	$11,241
Customer accounts receivable (less allowance for doubtful accounts of $3,005 in 2019 and $814 in 2018)	$39,165	$50,043
Accounts receivable - affiliate	$14,481	$3,318
Other accounts receivable	$24,604	$24,523
Unbilled revenue	$33,207	$35,314
Fuel inventory, at average cost	$59,602	$82,836
Materials and supplies, at average cost	$91,941	$92,671
Energy risk management assets	$6,311	$23,355
Accumulated deferred fuel	$22,910	$20,112
Cash surrender value of company-owned life insurance policies	$17,574	$20,497
Prepayments	$4,786	$6,143
Regulatory assets	$10,973	$13,603
Other current assets	$655	$1,162
Total current assets	$392,798	$416,805
Equity investment in investee	$17,072	$18,172
Prepayments	$2,693	$2,251
Operating lease right of use assets	$28,633	—
Restricted cash and cash equivalents	$14,363	$18,649
Note receivable	$15,198	$15,829
Regulatory assets	$272,289	$261,569
Intangible asset	$517	$21,093
Other deferred charges	$36,854	$32,419
Total assets	$4,476,530	$4,349,056

The accompanying notes are an integral part of the consolidated financial statements.

F-15

	AT DEC. 31,
(THOUSANDS)	2019	2018
Liabilities and member’s equity
Member’s equity	$1,713,392	$1,594,533
Long-term debt and finance leases, net	$1,327,372	$1,387,774
Total capitalization	$3,040,764	$2,982,307
Current liabilities
Long-term debt and finance leases due within one year	$61,587	$21,128
Accounts payable	$110,096	$146,314
Accounts payable - affiliate	$14,123	$7,843
Customer deposits	$58,289	$61,736
Provision for rate refund	$38,241	$35,842
Taxes payable, net	$38,888	$48,177
Interest accrued	$7,972	$8,252
Energy risk management liabilities	$586	$468
Regulatory liabilities - other	$6,675	$2,496
Other current liabilities	$22,802	$22,263
Total current liabilities	$359,259	$354,519
Commitments and contingencies (Note 15)
Long-term liabilities and deferred credits
Accumulated deferred federal and state income taxes, net	$657,834	$630,765
Postretirement benefit obligations	$206,270	$182,721
Regulatory liabilities - other	—	$2,496
Regulatory liabilities - deferred taxes, net	$146,948	$155,537
Restricted storm reserve	$12,285	$15,485
Asset retirement obligations	$7,325	$6,881
Operating lease liabilities	$25,658	—
Other deferred credits	$20,187	$18,345
Total long-term liabilities and deferred credits	$1,076,507	$1,012,230
Total liabilities and member’s equity	$4,476,530	$4,349,056

The accompanying notes are an integral part of the consolidated financial statements.

F-16

CLECO POWER
Consolidated Statements of Cash Flows

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating activities
Net income	$148,262	$162,257	$150,738
Adjustment to reconcile net income to net cash provided by operating activities
Depreciation and amortization	$178,245	$168,248	$165,200
Provision for doubtful accounts	$2,348	$797	$2,677
Unearned compensation expense	$974	$1,873	$1,972
Allowance for equity funds used during construction	$(15,397)	$(14,159)	$(8,320)
Deferred income taxes	$21,799	$(11,545)	$(34,191)
Deferred fuel costs	$11,132	$(18,549)	$11,909
Cash surrender value of company-owned life insurance	$2,923	$(219)	$(260)
Changes in assets and liabilities
Accounts receivable	$(4,740)	$3,967	$(25,696)
Accounts receivable - affiliate	$728	$426	$1,865
Unbilled revenue	$2,107	$1,084	$(2,129)
Fuel inventory and materials and supplies	$21,121	$(2,981)	$(44,995)
Prepayments	$386	$107	$2,745
Accounts payable	$14,659	$22,419	$11,005
Accounts payable - affiliate	$5,912	$(4,700)	$1,349
Customer deposits	$5,888	$13,757	$12,381
Provision for merger commitments	$(1,848)	$(3,273)	$(12,971)
Postretirement benefit obligations	$(10,078)	$4,252	$4,849
Regulatory assets and liabilities, net	$(1,897)	$1,044	$10,544
Other deferred accounts	$(6,338)	$(5,421)	$(8,137)
Taxes accrued	$(20,881)	$16,566	$44,101
Interest accrued	$(280)	$1,169	$(59)
Other operating	$(2,541)	$2,569	$2,501
Net cash provided by operating activities	$352,484	$339,688	$287,078
Investing activities
Additions to property, plant, and equipment	$(313,962)	$(289,153)	$(235,252)
Allowance for equity funds used during construction	$15,397	$14,159	$8,320
Proceeds from sale of property, plant, and equipment	$739	$995	$4,078
Reimbursement for property loss	$141	$1,375	$187
Issuance of note receivable	—	$(16,800)	—
Return of equity investment in investee	$1,100	—	$500
Return of investment in company-owned life insurance	$3,761	—	—
Other investing	$574	$397	—
Net cash used in investing activities	$(292,250)	$(289,027)	$(222,167)

The accompanying notes are an integral part of the consolidated financial statements.

F-17

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Financing activities
Draws on credit facility	$33,000	—	$106,000
Payments on credit facility	$(33,000)	—	$(106,000)
Issuances of long-term debt	—	$50,000	$125,000
Repayments of long-term debt	$(20,571)	$(19,193)	$(17,896)
Distributions to member	$(20,000)	$(121,400)	$(135,000)
Other financing	$(588)	$(1,148)	$(2,013)
Net cash used in financing activities	$(41,159)	$(91,741)	$(29,909)
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents	$19,075	$(41,080)	$35,002
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period	$61,877(1)	$102,957	$67,955
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period	$80,952(2)	$61,877(1)	$102,957
Supplementary cash flow information
Interest paid, net of amount capitalized	$67,391	$70,357	$65,984
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$14,894	$55,718	$30,883
Non-cash additions to property, plant, and equipment	$52	$1,224	$3,015
Incurrence of finance lease obligation - barges	$—	$16,800	$—

(1)
Includes cash and cash equivalents of $31,987, current restricted cash and cash equivalents of $11,241, and non-current restricted cash and cash equivalents of $18,649.

(2)
Includes cash and cash equivalents of $55,489, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $14,363.

The accompanying notes are an integral part of the consolidated financial statements.

F-18

CLECO POWER
Consolidated Statements of Changes in Member’s Equity

(THOUSANDS)	MEMBER’S EQUITY	AOCI	TOTAL MEMBER’S EQUITY
Balances, Dec. 31, 2016	$1,548,624	$(13,422)	$1,535,202
Distributions to member	$(135,000)	—	$(135,000)
Net income	$150,738	—	$150,738
Other comprehensive loss, net of tax	—	(261)	$(261)
Balances, Dec. 31, 2017	$1,564,362	$(13,683)	$1,550,679
Distributions to member	$(121,400)	—	$(121,400)
Net income	$162,257	—	$162,257
Other comprehensive income, net of tax	—	$2,997	$2,997
Reclassification of effect of tax rate change	$2,496	$(2,496)	—
Balances, Dec. 31, 2018	$1,607,715	$(13,182)	$1,594,533
Distributions to member	$(20,000)	—	$(20,000)
Net income	$148,262	—	$148,262
Other comprehensive loss, net of tax	—	$(9,403)	$(9,403)
Balances, Dec. 31, 2019	$1,735,977	$(22,585)	$1,713,392

The accompanying notes are an integral part of the consolidated financial statements.

F-19

Index to Applicable Notes to the Financial Statements of Registrants

Note 1	The Company	Cleco and Cleco Power
Note 2	Summary of Significant Accounting Policies	Cleco and Cleco Power
Note 3	Business Combinations	Cleco
Note 4	Leases	Cleco and Cleco Power
Note 5	Revenue Recognition	Cleco and Cleco Power
Note 6	Regulatory Assets and Liabilities	Cleco and Cleco Power
Note 7	Jointly Owned Generation Units	Cleco and Cleco Power
Note 8	Fair Value Accounting	Cleco and Cleco Power
Note 9	Debt	Cleco and Cleco Power
Note 10	Pension Plan and Employee Benefits	Cleco and Cleco Power
Note 11	Income Taxes	Cleco and Cleco Power
Note 12	Disclosures about Segments	Cleco
Note 13	Regulation and Rates	Cleco and Cleco Power
Note 14	Variable Interest Entities	Cleco and Cleco Power
Note 15	Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees	Cleco and Cleco Power
Note 16	Affiliate Transactions	Cleco and Cleco Power
Note 17	Intangible Assets, Intangible Liabilities, and Goodwill	Cleco and Cleco Power
Note 18	Accumulated Other Comprehensive Loss	Cleco and Cleco Power
Note 19	Miscellaneous Financial Information (Unaudited)	Cleco and Cleco Power

F-20

Notes to the Financial Statements

Note 1 — The Company

Cleco is composed of the following:

• Cleco Power, a regulated electric utility subsidiary, which owns 10 generating units with a total nameplate capacity of 3,360 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi. 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.

• Cleco Cajun, an unregulated electric utility subsidiary, which owns eight generating assets with a rated capacity of 3,555 MW and supplies wholesale power and capacity in Arkansas, Louisiana, and Texas. Cleco Cajun owns all of the outstanding membership interest in Cottonwood Energy. Upon the closing of the Cleco Cajun Transaction, Cottonwood Energy entered into the Cottonwood Sale Leaseback. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”

• Cleco’s other operations consist of the following:

○ Cleco Holdings, a holding company,

○ Support Group, a shared services subsidiary,

○ Diversified Lands, an investment subsidiary, and

○ Attala and Perryville, two subsidiaries that owned and operated transmission interconnection facilities prior to the assets being sold by Cleco on December 29, 2017.

Note 2 — Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements 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 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. Cleco’s consolidated financial statements include the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, through December 31, 2019. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”

Goodwill

Goodwill is the excess of the purchase price (consideration transferred and liabilities assumed) over the estimated fair value of net assets of the acquired business and is not subject to amortization. Goodwill is assessed annually or more often if an event occurs or circumstances change that would indicate the carrying amount may be impaired. For more information on goodwill, see Note 17 — “Intangible Assets, Intangible Liabilities, and Goodwill.”

Intangible Assets and Liabilities

Intangible assets include Cleco Katrina/Rita’s right to bill and collect storm recovery charges, fair value adjustments for long-term wholesale power supply agreements as well as a fair value adjustment for the valuation of the Cleco trade name. Intangible liabilities also include fair value adjustments for long-term wholesale power supply agreements and a fair value adjustment for the LTSA assumed for maintenance services related to the Cottonwood Plant. The intangible assets and liabilities are being amortized over their estimated useful lives in a manner that best reflects the economic impact derived from such assets and liabilities.

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Impairment will be tested if there are events or circumstances that indicate that an impairment analysis should be performed. If such an event or circumstance occurs, intangible impairment testing will be performed prior to goodwill impairment testing. Impairment is calculated as the excess of the asset and liabilities’ respective carrying amounts over their respective fair values. For more information on intangible assets and liabilities, see Note 17 — “Intangible Assets, Intangible Liabilities, and Goodwill.”

Statements of Cash Flows

Cleco and Cleco Power’s Consolidated Statements of Cash Flows are prepared using the indirect method. This method requires adjusting net income to remove the effects of all deferrals and accruals of operating cash receipts and payments and to remove items whose cash effects are related to investing and financing cash flows. Derivatives meeting the definition of an accounting hedge are classified in the same category as the item being hedged.

Regulation

Cleco Power is subject to regulation by FERC and the LPSC. Cleco Cajun is subject to regulation by FERC. Cleco complies with the accounting policies and practices prescribed by its regulatory commissions. Cleco Power’s retail rates are regulated by the LPSC. Cleco and Cleco Cajun’s rates for transmission services are regulated by FERC. Rates for wholesale power sales are based on market-based rates, pending FERC review of Cleco’s generation market power analysis. Cleco Power capitalizes or defers certain costs for recovery from its customers and recognizes a liability for amounts expected to be returned to its customers based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered through the ratemaking process. Regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process. Pursuant to this regulatory approval, Cleco has recorded 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 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 will be enacted or adopted and, if enacted, what form such legislation or regulation may take.

For more information regarding the regulatory assets and liabilities recorded by Cleco Power, see Note 6 — “Regulatory Assets and Liabilities.”

AROs

Cleco and Cleco Power recognize 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.

Cleco and Cleco Power recognize AROs at the present value of the projected liability in the period in which it is incurred, if a reasonable estimate of fair value can be made. The liability 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. Concurrent with the recognition of the liability, Cleco and Cleco Power capitalize these costs to the related property, plant, and equipment asset. 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.

As part of the Cleco Cajun Transaction, Cleco recognized $15.3 million of AROs primarily related to the retirement of Cleco Cajun’s ash management areas. At December 31, 2019, management’s analysis confirmed that no additional adjustments were needed to update Cleco or Cleco Power’s ARO balance. For more information on Cleco Power’s current AROs, see Note 6 — “Regulatory Assets and Liabilities — AROs.”

Property, Plant, and Equipment

Property, plant, and equipment consists primarily of utility generation and energy transmission and distribution assets. Assets utilized primarily for retail and wholesale operations and electric transmission and distribution are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits,

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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 and Cleco Cajun’s share of the cost to construct or purchase the respective assets. For information on jointly owned assets, see Note 7 — “Jointly Owned Generation Units.”

At the date of the 2016 Merger, Cleco’s gross balance of fixed depreciable assets was adjusted to be net of accumulated depreciation, as no accumulated depreciation existed on such date. Since pushdown accounting was not elected at the Cleco Power level, Cleco Power retained its accumulated depreciation.

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. On August 1, 2019, Cleco and Cleco Power began amortizing the computer software related to the START project. The amounts of unamortized computer software costs on Cleco’s Consolidated Balance Sheets at December 31, 2019, and 2018 were $168.6 million and $7.2 million, respectively. The amounts of unamortized computer software costs on Cleco Power’s Consolidated Balance Sheets at December 31, 2019, and 2018 were $166.2 million and $5.8 million, respectively. Amortization of capitalized computer software costs charged to expense in Cleco and Cleco Power’s Consolidated Statements of Income for the years ending December 31, 2019, 2018, and 2017 is shown in the following tables:

Cleco
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Amortization	$4,917	$2,154	$2,367

Cleco Power
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Amortization	$4,321	$1,607	$1,887

Upon retirement or disposition, the cost of Cleco Power and Cleco Cajun’s depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. For Cleco’s other subsidiaries, upon disposition or retirement of depreciable assets, 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.

Cleco Cajun’s depreciation on property, plant, and equipment is calculated primarily on a composite basis over the useful lives of the assets. Depreciation on all other property, plant, and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The following table presents the useful lives of depreciable assets for Cleco and Cleco Power:

CATEGORY (YEARS)	CLECO	CLECO POWER
Utility Plants
Generation	6 – 95	10 – 95
Distribution	15 – 50	15 – 50
Transmission	5 – 55	5 – 55
Other utility plant	2 – 45	5 – 45
Other property, plant, and equipment	5 – 45	5 – 45

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At December 31, 2019, and 2018, Cleco and Cleco Power’s property, plant, and equipment consisted of the following:

Cleco
	AT DEC. 31,
(THOUSANDS)	2019	2018
Utility plants
Generation	$2,812,843	$1,949,042
Distribution	1,153,086	1,081,650
Transmission	660,279	519,269
Other utility plant	350,683	174,010
Other property, plant, and equipment	5,364	4,506
Total property, plant, and equipment	4,982,255	3,728,477
Accumulated depreciation	(454,874)	(303,727)
Net property, plant, and equipment	$4,527,381	$3,424,750

Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Regulated utility plants
Generation	$2,633,590	$2,476,733
Distribution	1,593,104	1,523,885
Transmission	805,701	731,432
Other utility plant	457,062	282,954
Total property, plant, and equipment	5,489,457	5,015,004
Accumulated depreciation	(1,905,031)	(1,804,563)
Net property, plant, and equipment	$3,584,426	$3,210,441

On February 4, 2019, Cleco acquired $741.2 million of unregulated property, plant, and equipment as a result of the Cleco Cajun Transaction. These assets were recorded at fair market value at the date of the acquisition. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”

During 2019, Cleco Power’s regulated utility property, plant, and equipment increased primarily due to the in-service of the START project, St. Mary Clean Energy Center project, Terrebonne to Bayou Vista Transmission project, Coughlin Pipeline project, and general installation and rehabilitation of transmission, distribution, and generation assets.

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. At December 31, 2019, and 2018, Cleco Power had deferred $1.4 million, for projects that are in the initial stages of development. These amounts are classified as Other deferred charges on Cleco Power’s Consolidated Balance Sheets.

Fuel Inventory and Materials and Supplies

Fuel inventory consists primarily of petroleum coke, coal, limestone, lignite, and natural gas used to generate electricity.

Materials and supplies 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 inventory and materials and supplies are recorded at the lower of cost or market value using the average cost method and are issued from stock using the average cost of existing stock. Materials and supplies are recorded when purchased and subsequently charged to expense or capitalized to property, plant, and equipment when installed.

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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.

Reserves

Cleco maintains property insurance on generating stations, buildings and contents, and substations. Cleco is self-insured for any damage to its power lines. To mitigate the exposure to potential financial loss for damage to lines, Cleco Power 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 within certain self-insured limits, Cleco maintains reserves. At December 31, 2019, and 2018, the general liability and workers compensation reserves together were $4.3 million and $4.8 million, respectively.

Additionally, Cleco maintains directors and officers insurance to protect managers from claims which may arise from their decisions and actions taken within the scope of their regular duties.

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

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 company purposes.

Cleco and Cleco Power’s restricted cash and cash equivalents consisted of:

Cleco		​
	AT DEC. 31,
(THOUSANDS)	2019	​	2018
Current		​
Cleco Katrina/Rita’s storm recovery bonds	$9,632	​	$9,505
Cleco Power’s charitable contributions	1,200	​	1,200
Cleco Power’s rate credit escrow	268	���	536
Total current	11,100	​	11,241
Non-current		​
Diversified Lands’ mitigation escrow	21	​	21
Cleco Cajun’s defense fund	719	​	—
Cleco Cajun’s margin deposits	100	​	—
Cleco Power’s future storm restoration costs	12,269	​	15,391
Cleco Power’s charitable contributions	2,094	​	2,753
Cleco Power’s rate credit escrow	—	​	505
Total non-current	15,203	​	18,670
Total restricted cash and cash equivalents	$26,303	​	$29,911

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Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Current
Cleco Katrina/Rita’s storm recovery bonds	$9,632	$9,505
Charitable contributions	1,200	1,200
Rate credit escrow	268	536
Total current	11,100	11,241
Non-current
Future storm restoration costs	12,269	15,391
Charitable contributions	2,094	2,753
Rate credit escrow	—	505
Total non-current	14,363	18,649
Total restricted cash and cash equivalents	$25,463	$29,890

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 administration fees, interest, and principal on storm recovery bonds. During 2019, Cleco Katrina/Rita collected $22.2 million net of administration fees and remitted $20.6 million for scheduled storm recovery bond principal payments and $1.5 million for related interest payments.

As part of the Cleco Cajun Transaction, Cleco acquired restricted cash of $0.7 million to be used by Cleco Cajun’s cooperative customers for defense funds in the event of potential takeovers. There is no further obligation of Cleco with respect to such expenses, including the replenishment of the fund.

Equity Investments

Cleco and Cleco Power account for investments in unconsolidated affiliated companies using the equity method of accounting. The amounts reported on Cleco and Cleco Power’s Consolidated Balance Sheets represent assets contributed by Cleco 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 (excluding income taxes) of these affiliates are netted and reported on one line item as equity income from investees on Cleco and Cleco Power’s Consolidated Statements of Income.

Cleco evaluates for impairments of equity method investments at each balance sheet date to determine if 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. There were no impairments recorded for 2019, 2018, or 2017. For more information on Cleco’s equity investments, see Note 14 — “Variable Interest Entities.”

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. Deferred tax assets and liabilities are classified as non-current on Cleco and Cleco Power’s Consolidated Balance Sheets. 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 Group files a federal income tax return for all wholly owned subsidiaries. Cleco Power computes its federal and state income taxes as if it were a stand-alone taxpayer. The LPSC generally requires Cleco Power to flow the effects of state income taxes to customers. For more information on income taxes, see Note 11 — “Income Taxes.”

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Investment Tax Credits

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

Debt Issuance Costs, Premiums, and Discounts

Issuance costs, premiums, and discounts applicable to debt securities are amortized to interest expense ratably over the lives of the related issuances. Expenses and call premiums related to refinanced Cleco Power debt are deferred and amortized over the life of the new issuance. Debt issuance costs, premiums, and discounts are presented as a direct deduction from the carrying value of the related debt liability.

Revenue and Fuel Costs

Utility Revenue

Revenue from sales of electricity is recognized when the service is provided. The costs of fuel and purchased power used for Cleco Power’s retail customers currently are recovered from its customers through Cleco Power’s 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 used by customers but not yet billed. The monthly estimated unbilled revenue amounts are recorded as unbilled revenue and a receivable. Cleco Power uses actual customer energy consumption data available from AMI to calculate unbilled revenues.

Other Operations Revenue

Other operations revenue is recognized at the time products or services are provided to and accepted by customers, and collectability is reasonably assured.

Sales/Excise Taxes

Cleco collects a sales and use tax on the sale of electricity that subsequently is remitted to the state in accordance with state law. These amounts are not recorded as income or expense on Cleco and Cleco Power’s Consolidated Statements of Income but are reflected at gross amounts on Cleco and Cleco Power’s Consolidated Balance Sheets as a receivable until the tax is collected and as a payable until the liability is paid. Cleco currently does not have any excise taxes reflected on its income statement.

Franchise Fees

Cleco Power collects a consumer fee for one of its franchise agreements. This fee is not recorded on Cleco and Cleco Power’s Consolidated Statements of Income as revenue and expense, but is reflected at gross amounts on Cleco and Cleco Power’s Consolidated Balance Sheets as a receivable until it is collected and as a payable until the liability is paid.

AFUDC

The capitalization of AFUDC by Cleco Power is a utility accounting practice prescribed by FERC and the LPSC. AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance construction of new and existing facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement over the same life of the plant through a higher rate base and higher depreciation. 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 10.71% on a pretax basis (8.37% net of tax) for 2019, 9.58% on a pretax basis (7.08% net of tax) for 2018, and 11.07% on a pretax basis (6.81% net of tax) for 2017.

Fair Value Measurements and Disclosures

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values. Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance. Cleco and Cleco Power disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes. For more information about fair value levels, see Note 8 — “Fair Value Accounting.”

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Derivatives and Other Risk Management Activity

Cleco’s Energy Market Risk Management Policy authorizes hedging of commodity price risk with physical or financially settled derivative instruments. Some of these contracts may qualify for the normal purchase, normal sale (NPNS) exception under derivative accounting guidance. Contracts that do not qualify for NPNS accounting treatment or are not elected for NPNS accounting treatment are marked-to-market and recorded on the balance sheet at their fair value.

Cleco Power and Cleco Cajun are awarded and/or purchase FTRs in auctions facilitated by MISO. The majority of these FTRs are purchased in annual auctions during the second quarter, but additional FTRs may be purchased in monthly auctions. FTRs represent economic hedges of future congestion charges that will be incurred in serving customer load. FTRs are derivatives not designated as hedging instruments for accounting purposes.

Cleco Power’s FTRs are marked-to-market with the resulting unrealized gains or losses deferred as a component of deferred fuel assets or liabilities in accordance with regulatory policy. At settlement, realized gains or losses are included in the FAC and reflected on customers’ bills as a component of the fuel charge.

Cleco Cajun’s FTRs are marked-to-market with the resulting unrealized gains and losses recorded on the income statement as a component of purchased power expense. At settlement, realized gains or losses are also recorded on the income statement as a component of purchased power expense.

Cleco Cajun entered into other commodity derivative contracts during 2019. Management did not elect to apply hedge accounting to these contracts as allowed under applicable accounting standards. When these contracts are marked-to-market, the resulting unrealized gain or loss is recorded on the income statement as a component of fuel expense. At settlement, realized gains or losses are also recorded on the income statement as a component of fuel expense.

For more information on FTRs and other commodity derivatives, see Note 8 — “Fair Value Accounting — Commodity Contracts.”

Cleco may also enter into 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 each reporting period presented, the Registrants did not enter into any contracts to mitigate the volatility in interest rate risk.

Accounting for MISO Transactions

Cleco Power and Cleco Cajun participate in MISO’s Energy and Operating Reserve market where sales and purchases are netted hourly. If the hourly activity nets to sales, the result is reported in Electric operations on Cleco and Cleco Power’s Consolidated Statements of Income. If the hourly activity nets to purchases, the result is reported in Purchased power on Cleco and Cleco Power’s Consolidated Statements of Income.

Leases

Cleco accounts for leases in accordance with accounting guidance effective January 1, 2019. For more information on this guidance, see — “Recent Authoritative Guidance.”

Cleco determines if a contract is a lease at its inception. If a contract is determined to be a lease, Cleco recognizes a ROU asset and lease liability at the commencement date based on the present value of lease payments over the lease term. The present value of the lease payments is determined by using the implicit interest rate if readily determinable. Cleco’s incremental borrowing rate for a term similar to the duration of the lease based on information available at the commencement date is used if the implicit interest rate is not readily determinable.

Cleco recognizes ROU assets and lease liabilities for leasing arrangements with terms greater than one year. Except for the marine transportation asset class, Cleco accounts for lease and non-lease components in a contract as a single lease component for all classes of underlying assets. Cleco’s marine transportation contracts, which include barges and towboats, contain non-lease components, such as maintenance and labor. Cleco allocates the consideration in these contracts between lease and non-lease components based on estimates of fair value from third parties that typically execute leases for this class of assets.

Expense for a lessee operating lease is recognized as a single lease cost on a straight-line basis over the lease term and reflected in the appropriate income statement line item based on the leased asset’s function. Income for

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a lessor operating lease is recognized as a single lease income item on a straight-line basis over the lease term and reflected in the appropriate income statement line item based on the lease asset’s function.

Recent Authoritative Guidance

In February 2016, FASB amended the guidance to account for leases. Effective January 1, 2019, Cleco adopted the amended guidance using the optional transition method that allows an entity to recognize a cumulative-effect adjustment to the opening balance of retained earnings at the date of adoption, apply the new disclosure requirements beginning in the period of adoption, and continue to present comparative period information as required under previous guidance.

In addition, Cleco elected the transition practical expedient that permits an entity to not reassess prior conclusions about lease identification, lease classification, and initial direct costs under the new standard, as well as the practical expedient that permits entities to not assess existing land easements under the new standard.

Adoption of this standard resulted in the recognition of ROU assets and lease liabilities for Cleco and Cleco Power’s operating leases of $16.1 million and $15.9 million, respectively. There was no impact to retained earnings as a result of adopting this standard. Adoption of this standard did not materially impact the Registrants’ results of operations or liquidity, and their accounting for finance leases is substantially unchanged. For more information on Cleco’s lease obligations, see Note 4 — “Leases.”

In June 2016, FASB amended the guidance for the measurement of credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses. The adoption of this guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those years. Management does not expect this guidance to have a significant impact on the results of operations, financial condition, or cash flows of the Registrants.

In August 2018, FASB issued guidance that allows for the deferral of certain implementation costs incurred in a cloud computing arrangement. The adoption of this guidance is effective for annual reporting periods beginning after December 15, 2019, including interim periods within those years. Early adoption is permitted. Management does not expect this guidance to have significant impact on the results of operations, financial condition, or cash flows of the Registrants.

Note 3 — Business Combinations

On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in South Central Generating. This acquisition enabled Cleco to significantly increase the scale of its operations in Louisiana. As a result, Cleco Cajun owns:

• a 176-MW natural-gas-fired generating station located in Sterlington, Louisiana,

• a 220-MW natural-gas-fired facility and a 210-MW natural-gas-fired peaking facility, both located in Jarreau, Louisiana,

• a 580-MW coal-fired generating facility, a 540-MW natural-gas-fired generating station, and 58% of a 588-MW coal-fired generating station all located in New Roads, Louisiana,

• 225 MW of a 300-MW natural-gas-fired peaking facility located in Jennings, Louisiana,

• a 1,263-MW natural-gas-fired generating station located in Deweyville, Texas (the Cottonwood Plant),

• wholesale contracts to provide electricity and capacity to nine Louisiana cooperatives, three municipalities across Arkansas, Louisiana, and Texas, and one investor-owned utility,

• transmission assets, which consist of equipment and land required to connect the generation stations and the wholesale customers to the transmission grid, and

• current assets consisting of cash, inventory, receivables and other miscellaneous assets.

Cleco Cajun, NRG Energy, and South Central Generating each made customary representations, warranties and covenants in the Cleco Cajun Transaction, which include customary indemnification provisions. Cleco Holdings has agreed to guarantee the obligations of Cleco Cajun, subject to certain limitations. In addition, a lease agreement was executed and delivered between Cottonwood Energy and a special-purpose entity that is a

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subsidiary of NRG Energy pursuant to which NRG Energy will lease back the Cottonwood Plant and will operate it no later than May 2025. Upon closing, Cottonwood Energy became a subsidiary of Cleco Cajun.

Regulatory Matters

In January 2019, the LPSC approved the Cleco Cajun Transaction. Approval of the transaction was conditioned upon certain commitments, including holding Cleco Power ratepayers harmless for any adverse impacts, increased costs of debt or equity, and credit rating downgrades attributable to the Cleco Cajun Transaction; the repayment of $400.0 million of Cleco Holdings’ debt by 2024; and a $4.0 million annual reduction to Cleco Power’s retail customer rates. For more information about the debt and rate reduction commitments, see Note 9 — “Debt” and Note 6 — “Regulatory Assets and Liabilities,” respectively.

South Central Generating

In 2017, Louisiana Generating received insurance settlement proceeds for costs incurred to resolve a lawsuit which was brought by the EPA and the LDEQ against Louisiana Generating related to Big Cajun II, Unit 3. Entergy Gulf States, as co-owner of Big Cajun II, Unit 3, is expected to be allocated a portion of the insurance settlement proceeds. Any amount allocated to Entergy Gulf States will be determined by ongoing litigation and negotiations. South Central Generating estimated this amount to be $10.0 million. As part of the Cleco Cajun Transaction, Cleco Cajun assumed the $10.0 million contingent liability and NRG Energy indemnified Cleco for losses associated with this litigation matter. As a result, Cleco also recorded a $10.0 million indemnification asset, which was included in the purchase price allocation.

Prior to the Cleco Cajun Transaction, South Central Generating was involved in various litigation matters, including environmental and contract proceedings, before various courts regarding matters arising out of the ordinary course of business. Management is unable to estimate any potential losses that Cleco Cajun may ultimately be responsible for with respect to any one of these matters. As part of the Cleco Cajun Transaction, NRG Energy indemnified Cleco for losses, as of the closing date, associated with matters that existed as of the closing date, including pending litigation.

Accounting for the Cleco Cajun Transaction

As consideration for all of the outstanding membership interest in South Central Generating, Cleco paid cash of approximately $962.2 million, which represents the $1.0 billion acquisition price net of working capital and other adjustments of $37.8 million.

In connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings borrowed $300.0 million under a bridge loan agreement and $100.0 million under a term loan agreement. Both loan agreements are variable rate debt and have a three-year term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings to maintain (i) a debt to capital ratio (as defined in the applicable agreement) below 65% and (ii) a rating applicable to Cleco’s senior debt rating (as defined in the applicable agreement). On September 11, 2019, Cleco Holdings refinanced the remaining amounts due under the $300.0 million bridge loan agreement and a portion of the $100.0 million term loan agreement with the proceeds from the private placement of $300.0 million aggregate principal amount of senior notes. For more information, see Note 9 — “Debt.” Also, in connection with the Cleco Cajun Transaction, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total capacity of $175.0 million. All other terms remained the same. Also in connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings made a $75.0 million draw on its credit facility, which was repaid on February 5, 2019.

The remaining cash required to finance the transaction consisted of an equity contribution from Cleco Group of $384.9 million and $102.3 million from cash on hand at Cleco Holdings.

F-30

Cleco Cajun accounted for the Cleco Cajun Transaction as a business combination, and accordingly, the assets acquired and liabilities assumed were recorded at their estimated fair values as of the date of the acquisition. Cleco made certain measurement period adjustments at June 30, 2019. The following chart presents Cleco’s current purchase price allocation:

Purchase Price Allocation
(THOUSANDS)	AT FEB. 4, 2019
Current assets
Cash and cash equivalents	$146,494
Customer and other accounts receivable	49,809
Fuel inventory	22,060
Materials and supplies	25,659
Energy risk management assets	4,193
Other current assets	10,056
Non-current assets
Property, plant, and equipment, net	741,203
Prepayments	36,166
Restricted cash and cash equivalents	707
Intangible assets	98,900
Other deferred charges	133
Total assets acquired	1,135,380
Current liabilities
Accounts payable	38,478
Taxes payable	723
Energy risk management liabilities	241
Other current liabilities	14,570
Non-current liabilities
Accumulated deferred federal and state income taxes, net	7,165
Deferred lease revenue	58,300
Intangible liabilities	38,300
Asset retirement obligations	15,323
Operating lease liabilities	110
Total liabilities assumed	173,210
Total purchase price consideration	$962,170

The fair values of Cleco Cajun’s acquired assets and assumed liabilities were determined based on significant estimates and assumptions, including projected future cash flows and discount rates reflecting risk inherent in those future cash flows. There were also estimates made to determine the expected useful lives of each class of assets acquired.

On the date of the acquisition, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the difference between the contract and market price of acquired long-term wholesale power agreements. The fair value of intangible assets of $98.9 million and intangible liabilities of $14.2 million was reflected in the purchase price allocation. The valuation of the acquired intangible assets and liabilities was estimated by applying the income method, which is based upon discounted projected future cash flows associated with the underlying contracts. The power supply agreement intangible assets and liabilities are being amortized to Electric operations on Cleco’s Consolidated Statement of Income over the remaining term of the applicable agreements.

As part of the Cleco Cajun Transaction, Cleco assumed an LTSA for maintenance services related to the Cottonwood Plant. The fair value of the LTSA was estimated by applying the income method. An intangible liability of $24.1 million was reflected in the purchase price allocation and is being amortized using the straight-line method over the estimated remaining life of the LTSA of seven years. The amortization is included as a reduction to the LTSA prepayments on Cleco’s Consolidated Balance Sheet.

F-31

On the date of the acquisition, the fair value of the lease between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy was estimated by applying the income method. Deferred lease revenue of $58.3 million was reflected in the purchase price allocation and is being amortized over the term of the lease agreement. The amortization is included in Other operations revenue on Cleco’s Consolidated Statement of Income.

Valuations were performed to assess the fair value of certain assets acquired and liabilities assumed and were considered preliminary as a result of the short time period between the closing of the acquisition and the end of the first quarter of 2019. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition as more information becomes available. These final valuations and assessments have been completed by the end of 2019.

During the second quarter of 2019, certain modifications were made to the preliminary valuations as of February 4, 2019, due to the refinement of valuation models, assumptions, and inputs. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date.

Measurement Period Adjustments
(THOUSANDS)	AT JUNE 30, 2019
Current assets
Customer and other accounts receivable	$1,408
Other current assets	$56
Non-current assets
Property, plant, and equipment, net	$13,297
Prepayments	$(56)
Intangible assets	$(3,600)
Other deferred charges	$1
Current liabilities
Accounts payable	$3,022
Energy risk management liabilities	$(1)
Other current liabilities	$327
Non-current liabilities
Accumulated deferred federal and state income taxes, net	$421
Deferred lease revenue	$(3,600)
Intangible liabilities	$6,400
Asset retirement obligations	$4,534
Operating lease liabilities	$3

The measurement period adjustments resulted in an increase in electric operations revenue of $0.5 million, a decrease in other operations revenue of $0.1 million, and an increase in depreciation expense of $0.2 million recorded for the three months ended June 30, 2019.

During the fourth quarter of 2019, Cleco completed its evaluation and determination of the fair value of assets and liabilities acquired in the Cleco Cajun Transaction. No modifications were made to the valuation during the third or fourth quarters of 2019. Consequently, no measurement period adjustments were made.

Pro forma Impact of the Cleco Cajun Transaction

The following table includes the unaudited pro forma financial information reflecting the consolidated results of operations of Cleco as if the Cleco Cajun Transaction had taken place on January 1, 2018. The pro forma net income for the year ended December 31, 2019, was adjusted to exclude nonrecurring transaction-related expenses of $4.7 million. The pro forma net income for the year ended December 31, 2018, includes nonrecurring transaction-related expenses.

F-32

The unaudited pro forma financial information presented in the following table is not necessarily indicative of the consolidated results of operations that would have been achieved had the transaction taken place on the dates indicated, or the future consolidated results of operations of the combined companies.

Unaudited Pro Forma Financial Information
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018
Operating revenue, net	$1,660,362	$1,668,022
Net income	$154,898	$170,224

Note 4—Leases

Cleco maintains operating and finance leases in its ordinary course of business activities.

Effective January 1, 2019, Cleco adopted new guidance which requires organizations to recognize lease assets and lease liabilities on the balance sheet and disclose key information about leasing arrangements. A lease is deemed to exist when the right to control the use of identified property, plant, or equipment is conveyed through a contract for a certain period of time and consideration is paid. For more information on how leases are identified and on the new guidance, see Note 2 — “Summary of Significant Accounting Policies — Leases” and “— Recent Authoritative Guidance.”

Operating Leases

Cleco Power leases utility systems from two municipalities and one non-municipal public body. The first municipal lease had a term of 10 years and was set to expire on August 11, 2021. On July 9, 2019, this municipal lease was renewed for an additional term of 10 years and expires on August 11, 2031. The second municipal lease has a term of 10 years and expires on May 13, 2028. The non-municipal lease has a term of 27 years and expires on July 31, 2039. Each utility system lease contains fixed and variable components, as well as provisions for extensions.

Cleco Power has leases for 200 railcars for coal transportation. One lease for 115 railcars expires on March 31, 2021, and the other lease for 85 railcars expires on March 31, 2020. Cleco Cajun has a lease for 135 railcars for coal transportation, which commenced in February 2019 and was a short-term lease with an initial term of 12 months. On January 27, 2020, this lease was renewed and expires on March 31, 2021. This lease renews for additional one-month terms unless Cleco Cajun chooses to terminate. Cleco reassesses its need for the railcars upon the expiration of each term. Cleco pays a monthly rental fee per car. The railcar leases do not contain contingent rent payments.

Cleco Power has leases for three towboats in order to transport petroleum coke to Madison Unit 3. Each of the towboat leases has a term of 10 years and expires on March 31, 2028. Under these agreements, the rates are adjusted annually per the Producer Price Index. Each lease contains provisions for a five-year extension.

Cleco and Cleco Power’s remaining operating leases provide for office and operating facilities, office equipment, and tower rentals.

The following is a schedule by year of future minimum lease payments due under Cleco and Cleco Power’s long-term operating leases together with the present value of the net minimum lease payments as of December 31, 2019:

(THOUSANDS)	CLECO POWER	CLECO
Years ending Dec. 31,
2020	$3,960	$3,994
2021	3,409	3,443
2022	3,256	3,287
2023	3,220	3,249
2024	3,216	3,235
Thereafter	18,618	18,618
Total minimum lease payments	35,679	35,826
Less: amount representing interest	7,086	7,069
Present value of net minimum operating lease payments	$28,593	$28,757
Current liabilities	$2,935	$2,978
Non-current liabilities	$25,658	$25,779

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The following table is a summary of expected operating lease payments for Cleco and Cleco Power at December 31, 2018:

(THOUSANDS)	CLECO POWER	CLECO HOLDINGS	TOTAL
Years ending Dec. 31,
2019	$4,030	$120	$4,150
2020	3,890	—	3,890
2021	2,789	—	2,789
2022	1,239	—	1,239
2023	1,214	—	1,214
Thereafter	7,235	—	7,235
Total operating lease payments	$20,397	$120	$20,517

Finance Lease

Prior to September 2017, Cleco Power had an agreement with Savage Services for barges in order to transport petroleum coke and limestone to Madison Unit 3 that met the accounting definition of a finance lease. In September 2017, Cleco Power entered into a new agreement for use of the barges on a month-to-month basis that met the accounting definition of an operating lease. In April 2018, Cleco Power entered into an agreement with Savage Inland Marine for continued use of the 42 barges used to transport petroleum coke through March 2033. The agreement meets the accounting definition of a finance lease.

The barge lease rate contains both a fixed and variable component, of which the latter is adjusted every third anniversary of the agreement for estimated executory costs. 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. This agreement contains a provision for early termination upon the occurrence of any one of four cancellation events.

For the years ended December 31, 2019, 2018, and 2017, Cleco Power paid $2.2 million, $2.0 million, and $2.5 million, respectively, in lease payments. For the years ended December 31, 2019, 2018, and 2017, Cleco Power received $1.7 million, $0.5 million, and $0.3 million, respectively, of revenue from subleases.

The following is an analysis of the leased property under the finance lease:

(THOUSANDS)	AT DEC. 31, 2019	AT DEC. 31, 2018
Barges	$16,800	$16,800
Accumulated amortization	(1,960)	(840)
Net finance lease	$14,840	$15,960

The following is a schedule by year of future minimum lease payments due under the finance lease together with the present value of the net minimum lease payments as of December 31, 2019:

(THOUSANDS)
Years ending Dec. 31,
2020	$2,203
2021	2,203
2022	2,203
2023	2,203
2024	2,203
Thereafter	17,675
Total minimum lease payments	28,690
Less: amount representing interest	12,829
Present value of net minimum finance lease payments	$15,861
Current liabilities	$617
Non-current liabilities	$15,244

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The following is a schedule by year of future minimum lease payments due under the finance lease together with the present value of the net minimum lease payments as of December 31, 2018:

(THOUSANDS)
Years ending Dec. 31,
2019	$2,611
2020	2,611
2021	2,611
2022	2,611
2023	2,611
Thereafter	23,655
Total minimum lease payments	36,710
Less: executory costs	5,817
Net minimum lease payments	30,893
Less: amount representing interest	14,475
Present value of net minimum lease payments	$16,418
Current liabilities	$557
Non-current liabilities	$15,861

Additional Lessee Disclosures

Cleco and Cleco Power’s total lease cost includes amounts on the income statement, as well as amounts capitalized as part of property, plant, or equipment or inventory. The following tables reflect total lease costs for Cleco and Cleco Power for the year ended December 31, 2019:

Cleco Power
(THOUSANDS)	FOR THE YEAR ENDED DEC. 31, 2019
Finance lease cost
Amortization of ROU assets	$1,120
Interest on lease liabilities	1,646
Operating lease cost	4,303
Variable lease cost	515
Total lease cost	$7,584

Cleco
(THOUSANDS)	FOR THE YEAR ENDED DEC. 31, 2019
Finance lease cost
Amortization of ROU assets	$1,120
Interest on lease liabilities	1,646
Operating lease cost	4,528
Variable lease cost	515
Total lease cost	$7,809

F-35

The following tables present additional information related to Cleco and Cleco Power’s operating and finance leases as of and for the year ended December 31, 2019:

		AT DEC. 31, 2019
(THOUSANDS)	BALANCE SHEET LINE ITEM	CLECO POWER	CLECO
Supplemental balance sheet information
ROU assets
Operating	Operating lease right of use assets	$28,633	$28,791
Finance	Property, plant, and equipment	14,840	14,840
Total ROU assets		$43,473	$43,631
Current lease liabilities
Operating	Other current liabilities	$2,935	$2,978
Finance	Long-term debt and finance leases due within one year	617	617
Non-current lease liabilities
Operating	Operating lease liabilities	25,658	25,779
Finance	Long-term debt and finance leases, net	15,244	15,244
Total lease liabilities		$44,454	$44,618

Cleco Power
(THOUSANDS)	FOR THE YEAR ENDED DEC. 31, 2019
Supplemental cash flow information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$4,203
Operating cash flows from finance leases	$1,646
Financing cash flows from finance leases	$557
ROU assets obtained in exchange for new lease liabilities	$15,749

Cleco
(THOUSANDS)	FOR THE YEAR ENDED DEC. 31, 2019
Supplemental cash flow information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$4,452
Operating cash flows from finance leases	$1,646
Financing cash flows from finance leases	$557
ROU assets obtained in exchange for new lease liabilities	$15,881

	AT DEC. 31, 2019
(THOUSANDS)	CLECO POWER	CLECO
Other supplemental information
Operating leases
Weighted-average remaining lease term	10.8 years	10.8 years
Weighted-average discount rate	4.31%	4.31%
Finance leases
Weighted-average remaining lease term	13.3 years	13.3 years
Weighted-average discount rate	10.18%	10.18%

F-36

Lessor Agreements

Upon the closing of the Cleco Cajun Transaction, Cleco assumed two lessor contracts leasing land to farmers for a term of one year. Both of these lessor contracts are classified as operating leases. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”

Cottonwood Sale Leaseback Agreement

Upon closing the Cleco Cajun Transaction, the Cottonwood Sale Leaseback was executed. Under the terms of the lease, NRG Energy will operate the Cottonwood Plant, incur all costs, and receive all revenues from the operations of the plant. Cottonwood Energy will receive fixed lease payments of $40.0 million per year and variable lease payments for LTSA costs and property taxes paid by NRG Energy on behalf of Cleco. Cleco may terminate the lease contract under specific circumstances stated in the lease contract. The residual value under the Cottonwood Sale Leaseback is expected to be recovered through sales of power generation from the plant. The residual value of the Cottonwood Plant has been determined using the plant’s estimated economic life.

Cleco Cajun is Cleco’s only entity with lessor arrangements. Cleco Cajun’s lease income under the Cottonwood Sale Leaseback for the year ended December 31, 2019, was as follows:

(THOUSANDS)	FOR THE YEAR ENDED DEC. 31, 2019
Fixed payments	$36,667
Variable payments	20,415
Amortization of deferred lease liability(1)	8,438
Total lease income	$65,520

(1)
The deferred lease revenue resulting from the fair value of the lease between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy.

The remaining minimum lease payments to be received under the Cottonwood Sale Leaseback are as follows:

(THOUSANDS)
Years ending Dec. 31,
2020	$40,000
2021	40,000
2022	40,000
2023	40,000
2024	40,000
Thereafter	16,667
Total payments	$216,667

Depreciation expense associated with Cleco’s property under the Cottonwood Sale Leaseback for the year ended December 31, 2019, was $22.7 million. Cleco calculated depreciation on a straight-line basis over the useful life of the asset. Property associated with the Cottonwood Sale Leaseback was as follows:

(THOUSANDS)	AT DEC. 31, 2019
Property, plant, and equipment	$540,409
Accumulated depreciation	(22,741)
Net property, plant, and equipment	$517,668

Note 5 — Revenue Recognition

Revenue from Contracts with Customers

Retail Utility Revenue

Cleco’s retail revenue from contracts with customers is generated primarily from Cleco Power’s regulated revenue from residential, commercial, and industrial customers. Cleco Power recognizes retail revenue from these

F-37

contracts as a series, and progress towards satisfaction of the performance obligation is measured using an output method based on kWh delivered. Accordingly, revenue from electricity sales is recognized as energy is delivered to the customer. Cleco Power bills retail customers, based on rates regulated by the LPSC, on a monthly basis with payments generally due within 20 days of the invoice date.

Included in Cleco Power’s retail revenue is unbilled electric revenue, which represents the amount customers will be billed for services rendered from the last meter reading to the end of the respective accounting period. Cleco Power uses actual customer energy consumption data available from AMI to calculate unbilled revenue. Also included in Cleco Power’s retail revenue is electric customer credits, which primarily represents the accrued estimated refunds to Cleco Power’s retail customers for the tax related benefits of the TCJA.

Wholesale Revenue

Cleco’s wholesale revenue is generated primarily through the sale of energy and capacity to cooperatives, municipalities, and the MISO transmission provider. Cleco also enters into transactions through MISO for spot energy sales which are transacted in the Day-Ahead Energy and Operating Reserves Market and the Real-Time Energy and Operating Reserves Market. The electricity revenue performance obligations, representing both energy and capacity, are satisfied as a series of performance obligations, and progress towards satisfaction of the performance obligations are measured using an output method. The energy performance obligation measure of progress is based on kWh delivered. The capacity performance obligation measure of progress is based on time elapsed and is recognized each month as Cleco’s generating units stand ready to deliver electricity to the customer. Cleco recognizes wholesale revenue, inclusive of both performance obligations, under the invoice practical expedient for the amount Cleco has the right to invoice. Cleco, through Cleco Power and Cleco Cajun, charges its wholesale customers market based rates that are subject to FERC’s triennial market power analysis.

Transmission Revenue

Cleco Power and Cleco Cajun earn transmission revenues pursuant to MISO’s FERC filed tariff. The performance obligation of transmission service is satisfied as service is provided. Revenue is recognized upon delivery of the transmission service. For Cleco Power, revenue from the transmission of electricity is recorded based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of revenue requirements with rates effective June 1 of each year. For Cleco Cajun, revenue from the transmission of electricity is recorded based on a FERC-approved annual filing rate mechanism effective June 1 of each year. Cleco Cajun charges transmission rates based on its cost to provide transmission services.

Other Revenue

Other revenue from contracts with customers, which is not a significant source of Cleco’s revenue, includes Cleco Power’s Teche Unit 3 SSR revenue and miscellaneous fees. The performance obligation under these contracts is satisfied and revenue is recognized as control of the products is delivered or services are rendered.

Revenue Unrelated to Contracts with Customers

Cleco’s energy-related transactions with the following characteristics qualify as derivative contracts and are recorded pursuant to derivatives and hedging accounting guidance: a) their value is based on the notional amount or payment provisions of an underlying asset; b) they require no or a diminutive initial net investment; and c) their terms require or permit net settlement.

Cleco Cajun’s other revenue includes fixed lease payments and certain variable payments for costs paid by NRG Energy on behalf of Cleco. For more information on the Cottonwood lease agreement, see Note 4 — “Leases — Lessor Agreements — Cottonwood Sale Leaseback Agreement.”

F-38

Disaggregated Revenue

Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a new reportable segment. For more information on the transaction, see Note 3 — “Business Combinations.”

Operating revenue, net for the year ended December 31, 2019, and 2018, was as follows:

	FOR THE YEAR ENDED DEC. 31, 2019
(THOUSANDS)	CLECO POWER	CLECO CAJUN	OTHER	ELIMINATIONS	TOTAL
Revenue from contracts with customers
Retail revenue
Residential(1)	$415,242	$—	$—	$—	$415,242
Commercial(1)	289,197	—	—	—	289,197
Industrial(1)	149,711	—	—	—	149,711
Other retail(1)	15,046	—	—	—	15,046
Surcharge	22,132	—	—	—	22,132
Electric customer credits	(35,880)	—	—	—	(35,880)
Total retail revenue	855,448	—	—	—	855,448
Wholesale, net	226,978(1)	374,635(2)	(9,680)(3)	(1)	591,932
Transmission, net	50,874(4)	51,315(5)	—	(7,471)	94,718
Other	19,324(6)	—	2	—	19,326
Affiliate(7)	3,125	108	109,067	(112,300)	—
Total revenue from contracts with customers	1,155,749	426,058	99,389	(119,772)	1,561,424
Revenue unrelated to contracts with customers
Other	12,621(8)	65,560(9)	—	—	78,181
Total revenue unrelated to contracts with customers	12,621	65,560	—	—	78,181
Operating revenue, net	$1,168,370	$491,618	$99,389	$(119,772)	$1,639,605

(1)
Includes fuel recovery revenue.

(2)
Includes $0.8 million of electric customer credits.

(3)
Amortization of intangible assets related to Cleco Power’s wholesale power supply agreements.

(4)
Includes $2.6 million of electric customer credits.

(5)
Includes $0.7 million of electric customer credits.

(6)
Includes $16.1 million of other miscellaneous fee revenue and $3.2 million of Teche Unit 3 SSR revenue.

(7)
Includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.

(8)
Includes realized gains associated with FTRs of $12.4 million and LCFC revenue of $0.2 million.

(9)
Includes $57.1 million in lease revenue related to the Cottonwood Sale Leaseback and $8.4 million of deferred lease revenue amortization.

F-39

	FOR THE YEAR ENDED DEC. 31, 2018
(THOUSANDS)	CLECO POWER	OTHER	ELIMINATIONS	TOTAL
Revenue from contracts with customers
Retail revenue
Residential(1)	$435,610	$—	$—	$435,610
Commercial(1)	288,791	—	—	288,791
Industrial(1)	167,001	—	—	167,001
Other retail(1)	15,582	—	—	15,582
Surcharge	23,138	—	—	23,138
Electric customer credits	(33,195)	—	—	(33,195
Total retail revenue	896,927	—	—	896,927
Wholesale, net(1)	219,598	(9,680)(2)	—	209,918
Transmission	54,531	—	—	54,531
Other(3)	27,800	2	—	27,802
Affiliate(4)	874	74,591	(75,465)	—
Total revenue from contracts with customers	1,199,730	64,913	(75,465)	1,189,178
Revenue unrelated to contracts with customers
Other(5)	41,866	—	—	41,866
Total revenue unrelated to contracts with customers	41,866	—	—	41,866
Operating revenue, net	$1,241,596	$64,913	$(75,465)	$1,231,044

(1)
Includes fuel recovery revenue.

(2)
Amortization of intangible assets related to wholesale power supply agreements.

(3)
Other revenue from contracts with customers includes $18.2 million of other miscellaneous fee revenue and $9.6 million of Teche Unit 3 SSR revenue.

(4)
Affiliate revenue from contracts with customers includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.

(5)
Includes realized gains associated with FTRs of $39.3 million and LCFC revenue of $2.6 million.

Cleco and Cleco Power have unsatisfied performance obligations with durations ranging between 1 and 15 years that primarily relate to stand-ready obligations as part of fixed capacity minimums. Cleco and Cleco Power have elected to not disclose the value of unsatisfied variable performance obligations as part of their application of the right to invoice practical expedient. At December 31, 2019, Cleco and Cleco Power had $30.8 million of unsatisfied performance obligations that will be recognized as revenue over the term of the contracts as the stand-ready obligation to provide energy is provided.

Note 6 — Regulatory Assets and Liabilities

Cleco Power capitalizes or defers certain costs for recovery from customers and recognizes a liability for amounts expected to be returned to customers based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered or refunded 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 the authoritative guidance of regulated operations.

F-40

The following table summarizes Cleco Power’s regulatory assets and liabilities:

Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018	REMAINING RECOVERY PERIOD (YRS.)
Regulatory assets (liabilities)
Deferred taxes, net	(146,948)	(155,537)	*
Mining costs	—	1,274	—
Interest costs	3,958	4,208	*
AROs	3,668	3,099	*
Postretirement costs	151,543	140,245	*
Tree trimming costs	11,341	9,069	*
Training costs	6,241	6,396	40
Surcredits, net(1)	145	289	*
AMI deferred revenue requirement	3,136	3,681	6
Emergency declarations	1,349	2,980	*
Production operations and maintenance expenses	7,985	12,245	*
AFUDC equity gross-up(1)	72,766	71,952	*
Acadia Unit 1 acquisition costs	2,124	2,230	20
Financing costs	7,554	7,923	*
Coughlin transaction costs	906	938	29.5
Corporate franchise tax, net	(1,145)	1,416	*
Non-service cost of postretirement benefits	6,739	4,629	*
Energy efficiency	2,820	2,585	*
Accumulated deferred fuel	22,910	20,112	*
Other, net	(4,543)	(4,979)	*
Total regulatory assets, net	$152,549	$134,755

(1)
Represents regulatory assets for past expenditures that were not earning a return on investment at December 31, 2019, and 2018, respectively. All other assets are earning a return on investment.

*
For information related to the remaining recovery periods, refer to the following disclosures for each specific regulatory asset.

The following table summarizes Cleco’s net regulatory assets and liabilities:

Cleco
	AT DEC. 31,
(THOUSANDS)	2019	2018
Total Cleco Power regulatory assets, net	$152,549	$134,755
2016 Merger adjustments(1)
Fair value of long-term debt	127,977	138,701
Postretirement costs	17,399	19,387
Financing costs	7,935	8,279
Debt issuance costs	5,665	6,252
Total Cleco regulatory assets, net	$311,525	$307,374

(1)
Cleco regulatory assets include acquisition accounting adjustments as a result of the 2016 Merger.

Income Taxes

The regulatory assets and liabilities recorded for deferred income taxes represent the effect of tax benefits or detriments that must be flowed through to customers as they are received or paid. The amounts deferred are attributable to differences between book and tax recovery periods. In 2017, the President signed the TCJA.

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Changes in the IRC, as amended, from the TCJA, had a material impact on the Registrants’ financial statements in 2017. Tax effects of changes in tax laws must be recognized in the period in which the law is enacted. Also, deferred tax assets and liabilities must be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. In 2017, Cleco and Cleco Power made an estimate for the remeasurement of ADIT based upon the new tax rate, which resulted in a provisional regulatory liability of $348.6 million. During the fourth quarter of 2018, Cleco Power recorded the final remeasurements, which resulted in an additional regulatory liability of $26.4 million for a total of $375.0 million at December 31, 2018. No additional regulatory liability was accrued at December 31, 2019. For more information on the status of the TCJA regulatory liability, see Note 13 — “Regulation and Rates — TCJA.”

Mining Costs

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

Cleco Power, along with SWEPCO, maintains a lignite mining agreement with DHLC, the operator of the Dolet Hills Mine. As ordered by the LPSC, Cleco Power’s retail customers received fuel cost savings through the year 2011, while actual mining costs above a certain percentage of the benchmark price were deferred. These deferred costs could be recovered from retail customers through the FAC only when the actual mining costs were below a certain percentage of the benchmark price.

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 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 11.5 years. In connection with its 2009 approval of the Oxbow Lignite Mine acquisition, the LPSC agreed to discontinue benchmarking and the corresponding potential to defer future lignite mining costs while preserving the previously authorized recovery of the legacy deferred fuel balance. At June 30, 2019, Cleco Power had fully recovered the existing deferred mining costs, plus interest.

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.

AROs

Cleco Power recorded an ARO liability for the retirement of certain ash disposal facilities. The ARO regulatory asset represents the accretion of the ARO liability and the depreciation of the related assets. For more information on the accounting treatment of Cleco Power’s AROs, see Note 2 — “Summary of Significant Accounting Policies — AROs.”

Postretirement Costs

Cleco Power recognizes the funded status of its 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. These costs are amortized to pension expense over the average service life of the remaining plan participants (approximately eight years as of December 31, 2019, for Cleco’s plan) when it exceeds certain thresholds. 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 10 — “Pension Plan and Employee Benefits.”

Tree Trimming Costs

In October 2016, the LPSC approved Cleco Power to defer and recover through its base rates tree trimming costs. The LPSC authorized a deferral up to $10.9 million, excluding debt carrying costs. Cleco Power is currently collecting deferred tree trimming costs through its base rates and expects to be fully amortized by 2026.

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Training Costs

In 2008, the LPSC approved Cleco Power’s request to establish a regulatory asset for training costs associated with existing processes and technology for new employees at Madison Unit 3. Recovery of these expenditures was approved by the LPSC in 2009. In 2010, Cleco Power began amortizing the regulatory asset over a 50-year period.

Surcredits, Net

Cleco Power has recorded surcredits as the result of a settlement with the LPSC that addressed, among other things, the recovery of the storm damages related to hurricanes and uncertain tax positions. In the settlement, Cleco Power was required to implement surcredits to provide ratepayers with the economic benefit of the carrying charges of certain ADIT liabilities at a rate of return which was set by the LPSC. The settlement, through a true-up mechanism, allows the surcredits to be adjusted to reflect the actual tax deductions allowed by the IRS.

Cleco Power recorded a true-up to the surcredits to reflect the actual tax deductions allowed by the IRS for storm damages and uncertain tax positions. As a result of the true-ups, Cleco Power recorded a regulatory asset that represents excess surcredits refunded to customers that were collected from ratepayers and amortized over a four-year period, through June 2018. Cleco Power began collecting the balance as part of the July 1, 2019, FRP rate adjustment.

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 the estimated revenue requirements for the AMI project as a regulatory asset. In June 2014, the LPSC approved Cleco Power’s recovery of the AMI regulatory asset over the average life of the AMI meters, or 11 years. In July 2014, Cleco Power began recovering the AMI deferred revenue requirement.

Emergency Declarations

In August 2016, the LPSC issued emergency declaration executive orders following flooding events in south Louisiana which prohibited public utilities from disconnecting or charging late fees to customers for non-payment in affected parishes. In January 2017, the LPSC issued an order that terminated the executive orders effective March 1, 2017, and allowed public utilities to formally petition the LPSC to recover lost revenues as a result of the executive orders. In July 2017, Cleco Power began recovering lost revenues associated with the flooding events and expects the regulatory assets to be fully amortized by June 2021.

Production Operations and Maintenance Expenses

Annually, Cleco Power is allowed to defer, as a regulatory asset, production operations and maintenance expenses, net of fuel and payroll, above the retail jurisdictional portion of $45.0 million, adjusted annually for a growth factor (deferral threshold). The amount of the regulatory asset is capped at $23.0 million. The LPSC allows Cleco Power to recover the amount deferred in any calendar year over the following three-year regulatory period, beginning on July 1, when the annual rates are set. Cleco Power had no deferral in 2019. In December 2018, Cleco Power deferred $8.0 million as a regulatory asset.

AFUDC Equity Gross-Up

Cleco Power capitalizes equity AFUDC as a cost component of construction projects. 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.

Acadia Unit 1 Acquisition Costs

In 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. The Acadia Unit 1 acquisition costs are being recovered over a 30-year period beginning February 2010.

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Financing Costs

In 2011, Cleco Power entered into and settled two treasury rate locks. Of the $26.8 million in settlements, $7.4 million was deferred as a regulatory asset relating to ineffectiveness of the hedge relationships. Also in 2011, Cleco Power entered into a forward starting swap contract. These derivatives were entered into in order to mitigate the interest rate exposure on coupon payments related to forecasted debt issuances. In May 2013, the forward starting interest rate swap was settled at a loss of $3.3 million. Cleco Power deferred $2.9 million of the losses as a regulatory asset, which is being amortized over the terms of the related debt issuances.

Coughlin Transaction Costs

In January 2014, the LPSC authorized Cleco Power to create a regulatory asset for the transaction costs related to the transfer of Coughlin from Evangeline to Cleco Power. The Coughlin transaction costs are being recovered over a 35-year period beginning July 2014.

Corporate Franchise Tax, Net

As part of the FRP extension approved by the LPSC in June 2014, Cleco Power was authorized to recover through a rider the retail portion of state corporate franchise taxes paid. The retail portion of state corporate franchise taxes paid each year will be recovered over 12 months beginning July 1 of the following year.

Non-service Cost of Postretirement Benefits

On January 1, 2018, FASB’s amended guidance related to defined benefit pension and other postretirement plans became effective. The amendment allows only the service cost component of net benefit cost to be eligible for capitalization within property, plant, and equipment. Beginning January 1, 2018, Cleco Power’s non-service cost previously eligible for capitalization into property, plant, and equipment are being deferred to a regulatory asset and will be amortized over the estimated lives of the respective assets.

Energy Efficiency

In December 2018, Cleco Power filed a letter of intent with the LPSC to recover the under recovery of the accumulated decrease in revenues, also known as the LCFC, associated with the energy efficiency program for years 2014 through 2018 to be recovered over a four-year period. Cleco Power began collecting the accumulated LCFC revenues in Cleco Power’s energy efficiency rates effective March 1, 2019. On October 21, 2019, Cleco Power received notice of approval from the LPSC allowing recovery of the accumulated LCFC revenues.

Other Regulatory Assets (Liabilities), Net

At December 31, 2019, Other, net consisted of a $4.7 million regulatory liability for over collections related to the St. Mary Clean Energy project and a $0.8 million regulatory liability for an LPSC Cleco Cajun Transaction commitment. These regulatory liabilities were offset by a $1.0 million regulatory asset for the Coughlin Pipeline revenue requirement.

On July 1, 2018, Cleco Power began collecting the revenue requirement related to the St. Mary Clean Energy Center project based on an expected commercial operation date in the third quarter of 2018. The project was commercially operational in August 2019. Cleco Power recorded a regulatory liability for the over collections due to the delay of the commercial operations. On July 1, 2019, Cleco Power’s rates were adjusted by the amount of the over-collection and Cleco Power began amortizing the regulatory asset over 12 months.

In January 2019, the LPSC approved the Cleco Cajun Transaction. Approval of the Cleco Cajun Transaction was conditioned upon certain commitments, including a $4.0 million annual reduction to Cleco Power’s retail customer rates. For the period from February 4, 2019, to June 30, 2019, Cleco Power recorded a regulatory liability for the annual reduction until the July 1, 2019 FRP rate adjustment reflected the annual savings. Also on July 1, 2019, Cleco Power began amortizing the regulatory liability over 12 months.

In June 2017, the LPSC approved the establishment of a regulatory asset upon the completion of the Coughlin Pipeline project for the revenue requirement associated with the project until Cleco Power seeks recovery in the new FRP, which is anticipated to be effective July 1, 2020. The project was placed in service on September 6, 2019. Cleco Power anticipates collecting this amount over 12 months beginning July 1, 2020, subject to regulatory approval of Cleco Power’s new FRP.

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Accumulated Deferred Fuel

Cleco Power is allowed to recover the cost of fuel used for electric generation and power purchased for utility customers through the LPSC-established FAC or related wholesale contract provisions, which enable Cleco Power to pass on to its customers substantially all such charges. The difference between fuel and purchased power revenues collected from retail and wholesale customers and the current fuel and purchased power costs is generally recorded as Accumulated deferred fuel on Cleco Power’s Consolidated Balance Sheet. For 2019, approximately 76% of Cleco Power’s total fuel cost was regulated by the LPSC.

Cleco Holdings’ 2016 Merger Adjustments

As a result of the 2016 Merger, Cleco implemented acquisition accounting, which eliminated AOCI at the Cleco consolidated level on the date of the 2016 Merger. Cleco will continue to recover expenses related to certain postretirement costs; therefore, Cleco recognized a regulatory asset based on its determination that these costs can continue to be collected from customers. These costs will be amortized to Other operations expense over the average remaining service period of participating employees. Cleco will also continue to recover financing costs associated with the settlement of two treasury rate locks and a forward starting swap contract that were previously recognized in AOCI. Additionally, as a result of the 2016 Merger, a regulatory asset was recorded for debt issuance costs that were eliminated at Cleco and a regulatory asset was recorded for the difference between the carrying value and the fair value of long-term debt. These regulatory assets are being amortized over the terms of the related debt issuances, unless the debt is redeemed prior to maturity, at which time any unamortized related regulatory asset will be derecognized.

Note 7 — Jointly Owned Generation Units

Cleco Power and Cleco Cajun operate electric generation units that 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 and Cleco Cajun are responsible for their own share of the direct expenses of their respective jointly owned generation units. Cleco Power’s share of expenses is included in the operating expenses on Cleco and Cleco Power’s Consolidated Statements of Income. Cleco Cajun’s share of expenses is included in the operating expenses on Cleco’s Consolidated Statement of Income.

At December 31, 2019, the investment in and accumulated depreciation for each generating unit on Cleco and Cleco Power’s Consolidated Balance Sheets were as follows:

Cleco
	AT DEC. 31, 2019
(THOUSANDS, EXCEPT PERCENTAGES AND MW)	RODEMACHER UNIT 2	DOLET HILLS	BAYOU COVE	BIG CAJUN II - UNIT 3	TOTAL
Utility plant in service	$72,840	$179,909	$42,438	$33,291	$328,478
Accumulated depreciation	$7,690	$22,159	$2,090	$2,163	$34,102
Construction work in progress	$539	$5,435	$—	$329	$6,303
Ownership interest percentage	30%	50%	75%	58%
Capacity (MW)	523(1)	650(1)	300(2)	588(2)
Ownership interest (MW)	157	325	225	341

(1)
Nameplate capacity (MW)

(2)
Rated capacity (MW)

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Cleco Power
	AT DEC. 31, 2019
(THOUSANDS, EXCEPT PERCENTAGES AND MW)	RODEMACHER UNIT 2	DOLET HILLS	TOTAL
Utility plant in service	$147,020	$397,406	$544,426
Accumulated depreciation	$81,870	$239,655	$321,525
Construction work in progress	$539	$5,435	$5,974
Ownership interest percentage	30%	50%
Nameplate capacity (MW)	523	650
Ownership interest (MW)	157	325

Note 8 — Fair Value Accounting

The amounts reflected in Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2019, and 2018, for cash equivalents, restricted cash equivalents, accounts receivable, other accounts receivable, short-term debt, and accounts payable approximate fair value because of their short-term nature. Cleco applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including business combinations as well as impairment related to goodwill and other long-lived assets.

The following tables summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments not measured at fair value on Cleco and Cleco Power’s Consolidated Balance Sheets:

Cleco
	AT DEC. 31,
	2019		2018
(THOUSANDS)	CARRYING VALUE*	FAIR VALUE	CARRYING VALUE*	FAIR VALUE
Long-term debt	$3,188,664	$3,371,915	$2,889,631	$2,859,924

*
The carrying value of long-term debt does not include deferred issuance costs of $13.7 million at December 31, 2019, and $10.3 million at December 31, 2018.

Cleco Power
	AT DEC. 31,
	2019		2018
(THOUSANDS)	CARRYING VALUE*	FAIR VALUE	CARRYING VALUE*	FAIR VALUE
Long-term debt	$1,380,688	$1,601,865	$1,400,930	$1,517,152

*
The carrying value of long-term debt does not include deferred issuance costs of $7.4 million at December 31, 2019, and $8.3 million at December 31, 2018.

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

Fair Value Measurements and Disclosures

Cleco classifies assets and liabilities that are measured at their fair value according to three different levels depending on the inputs used in determining fair value.

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The following tables disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured on a recurring basis:

Cleco
	FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)	AT DEC. 31, 2019	QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)	SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)	AT DEC. 31, 2018	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	$129,643	$—	$129,643	$—	$133,722	$—	$133,722	$—
FTRs	6,822	—	—	6,822	23,355	—	—	23,355
Other commodity derivatives	201	—	201	—	—	—	—	—
Total assets	$136,666	$—	$129,844	$6,822	$157,077	$—	$133,722	$23,355
Liability Description
FTRs	$1,044	$—	$—	$1,044	$468	$—	$—	$468
Other commodity derivatives	5,373	—	5,373	—	—	$—	$—	$—
Total liabilities	$6,417	$—	$5,373	$1,044	$468	$—	$—	$468

Cleco Power
	FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)	AT DEC. 31, 2019	QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)	SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)	AT DEC. 31, 2018	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	$74,903	$—	$74,903	$—	$55,900	$—	$55,900	$—
FTRs	6,311	—	—	6,311	23,355	—	—	23,355
Total assets	$81,214	$—	$74,903	$6,311	$79,255	$—	$55,900	$23,355
Liability Description
FTRs	$586	$—	$—	$586	$468	$—	$—	$468
Total liabilities	$586	$—	$—	$586	$468	$—	$—	$468

The following tables summarize the net changes in the net fair value of FTR assets and liabilities classified as Level 3 in the fair value hierarchy for Cleco and Cleco Power:

Cleco
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018
Beginning balance	$22,887	$7,044
Unrealized (losses) gains*	(1,659)	11,865
Purchases	27,881	28,185
Settlements	(43,331)	(24,207)
Ending balance	$5,778	$22,887

*
Cleco Power’s unrealized (losses) gains are reported through Accumulated deferred fuel on Cleco’s Consolidated Balance Sheet. Cleco Cajun’s unrealized (losses) gains are reported through Purchased power on Cleco’s Consolidated Income Statement.

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Cleco Power
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018
Beginning balance	$22,887	$7,044
Unrealized (losses) gains*	(945)	11,865
Purchases	21,609	28,185
Settlements	(37,826)	(24,207)
Ending balance	$5,725	$22,887

*
Unrealized gains (losses) are reported through Accumulated deferred fuel on Cleco Power’s Consolidated Balance Sheets.

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for Cleco and Cleco Power as of December 31, 2019:

Cleco
	FAIR VALUE		VALUATION TECHNIQUE	SIGNIFICANT UNOBSERVABLE INPUTS	FORWARD PRICE RANGE
(THOUSANDS, EXCEPT DOLLAR PER MWh)	Assets	Liabilities			Low	High
FTRs at December 31, 2019	$6,822	$1,044	RTO auction pricing	FTR price - per MWh	$(2.57)	$2.86
FTRs at December 31, 2018	$23,355	$468	RTO auction pricing	FTR price - per MWh	$(4.40)	$15.10

Cleco Power
	FAIR VALUE		VALUATION TECHNIQUE	SIGNIFICANT UNOBSERVABLE INPUTS	FORWARD PRICE RANGE
(THOUSANDS, EXCEPT DOLLAR PER MWh)	Assets	Liabilities			Low	High
FTRs at December 31, 2019	$6,311	$586	RTO auction pricing	FTR price - per MWh	$(2.04)	$2.86
FTRs at December 31, 2018	$23,355	$468	RTO auction pricing	FTR price - per MWh	$(4.40)	$15.10

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 volume of instruments held. Level 2 fair values are determined by obtaining the closing price of similar assets and liabilities from published indices in active markets. Institutional money market funds assets are discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return. Level 3 fair values occur in situations in which there is little, if any, market activity for the asset or liability at the measurement date and prices are not observable. Cleco has consistently applied the Level 2 and Level 3 fair value techniques from fiscal period to fiscal period. Significant increases or decreases in any of those inputs in isolation would result in a significantly different fair value measurement. 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.

At December 31, 2019, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents and restricted cash equivalents. The institutional money market funds were reported on Cleco’s Consolidated Balance Sheets in cash and cash equivalents, current restricted cash and cash equivalents, and non-current restricted cash and cash equivalents of $103.4 million, $11.1 million, and $15.1 million, respectively, at December 31, 2019, and $103.8 million, $11.2 million, and $18.7 million, respectively, at December 31, 2018. At Cleco Power, the institutional money market funds were reported on Cleco Power’s Consolidated Balance Sheets in cash and cash equivalents, current restricted cash and cash equivalents, and non-current restricted cash and cash equivalents of $49.5 million, $11.1 million, and $14.3 million, respectively, at December 31, 2019, and $26.1 million, $11.2 million, and $18.6 million, respectively, at December 31, 2018. If the money market funds failed to perform under the terms of the

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investments, Cleco and Cleco Power would be exposed to a loss of the invested amounts. Collateral on these types of investments is not required by either Cleco or Cleco Power. 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 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.

Other commodity derivatives include fixed price physical forwards and swap transactions. These contracts contain counterparty credit risk because they are transacted directly with a counterparty and are not cleared on an exchange. These other commodity derivatives are recorded at fair value and categorized as Level 2 because pricing is indexed to other contracts.

Cleco Power and Cleco Cajun’s FTRs were priced using MISO’s monthly auction prices. Forward seasonal periods are not included in every monthly auction; therefore, the average of the most recent seasonal auction prices is used for monthly valuation. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from MISO auctions, which occur monthly in the Multi-Period Monthly Auction.

During the years ended December 31, 2019, and 2018, Cleco did not experience any transfers between levels within the fair value hierarchy.

Commodity Contracts

The following tables present the fair values of derivative instruments and their respective line items as recorded on Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2019, and 2018:

Cleco
		DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT DEC. 31, 2019	AT DEC. 31, 2018
Commodity related contracts
FTRs
Current	Energy risk management assets	$6,822	$23,355
Current	Energy risk management liabilities	1,044	468
Other commodity derivatives
Current	Energy risk management assets	201	—
Current	Energy risk management liabilities	3,069	—
Non-current	Other deferred credits	2,304	—
Commodity-related contracts, net		$606	$22,887

Cleco Power
		DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT DEC. 31, 2019	AT DEC. 31, 2018
Commodity related contracts
FTRs
Current	Energy risk management assets	$6,311	$23,355
Current	Energy risk management liabilities	586	468
Commodity-related contracts, net		$5,725	$22,887

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The following tables present the effect of derivatives not designated as hedging instruments on Cleco and Cleco Power’s Consolidated Statements of Income for the years December 31, 2019, 2018, and 2017:

Cleco
		AMOUNT OF GAIN/(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	DERIVATIVES LINE ITEM	2019	2018	2017
Commodity contracts
FTRs(1)	Electric operations	$13,043	$39,659	$23,826
FTRs(1)	Purchased power	(15,685)	(4,566)	(5,509
Other commodity derivatives	Fuel used for electric generation	(5,172)	—	—
Total		$(7,814)	$35,093	$18,317

(1)
For the years ended December 31, 2019, 2018, and 2017, unrealized gains (losses) associated with FTRs for Cleco Power of $(1.7) million, $11.9 million and $(1.4) million, respectively, were reported through Accumulated deferred fuel on the balance sheet.

Cleco Power
		AMOUNT OF GAIN/(LOSS) FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	DERIVATIVES LINE ITEM	2019	2018	2017
Commodity contracts
FTRs(1)	Electric operations	$13,047	$39,659	$23,826
FTRs(1)	Purchased power	(6,066)	(4,566)	(5,509)
Total		$6,981	$35,093	$18,317

(1)
For the years ended December 31, 2019, 2018, and 2017, unrealized gains (losses) associated with FTRs of $(0.9) million, $11.9 million, and $(1.4) million, respectively, were reported through Accumulated deferred fuel on the balance sheet.

The total volume of FTRs that Cleco Power had outstanding at December 31, 2019, and 2018 was 9.2 million MWh and 8.7 million MWh, respectively. The total volume of FTRs that Cleco had outstanding at December 31, 2019, and 2018 was 14.6 million MWh and 8.7 million MWh, respectively. At December 31, 2019, Cleco had 58.5 million MMBtus outstanding in other commodity derivatives.

Note 9 — Debt

Cleco Power’s total indebtedness as of December 31, 2019, and 2018 was as follows:

Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Bonds
Senior notes, 2.94%, due 2022	$25,000	$25,000
Senior notes, 3.08%, due 2023	100,000	100,000
Senior notes, 3.17%, due 2024	50,000	50,000
Senior notes, 3.68%, due 2025	75,000	75,000
Senior notes, 3.47%, due 2026	130,000	130,000
Senior notes, 4.33%, due 2027	50,000	50,000
Senior notes, 3.57%, due 2028	200,000	200,000
Senior notes, 6.50%, due 2035	295,000	295,000
Senior notes, 6.00%, due 2040	250,000	250,000
Senior notes, 5.12%, due 2041	100,000	100,000
Series A GO Zone bonds, 2.00%, due 2038, mandatory tender in 2020	50,000	50,000
Series B GO Zone bonds, 4.25%, due 2038	50,000	50,000
Cleco Katrina/Rita’s storm recovery bonds, 5.61%, due 2023	11,055	31,625
Total bonds	1,386,055	1,406,625

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Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Finance leases
Barge lease obligations	15,861	16,418
Gross amount of long-term debt and finance leases	1,401,916	1,423,043
Less: long-term debt due within one year	60,970	20,571
Less: finance leases classified as long-term debt due within one year	617	557
Unamortized debt discount	(5,368)	(5,695)
Unamortized debt issuance costs	(7,589)	(8,446)
Total long-term debt and finance leases, net	$1,327,372	$1,387,774

Cleco’s total indebtedness as of December 31, 2019, and 2018 was as follows:

Cleco
	AT DEC. 31,
(THOUSANDS)	2019	2018
Total Cleco Power long term debt and finance leases, net	$1,327,372	$1,387,774
Cleco Holdings’ long-term debt, net
Senior notes, 3.250%, due 2023	165,000	165,000
Senior notes, 3.743%, due 2026	535,000	535,000
Senior notes, 3.375%, due 2029	300,000	—
Senior notes, 4.973%, due 2046	350,000	350,000
Bank term loan, variable rate, due 2021	300,000	300,000
Bank term loan, variable rate, due 2021	30,000	—
Long-term debt due within one year	(64,398)	—
Unamortized debt issuance costs(1)	(6,271)	(1,989)
Fair value adjustment	127,976	138,700
Total Cleco long-term debt and finance leases, net	$3,064,679	$2,874,485

(1)
For December 31, 2019, and 2018, this amount includes unamortized debt issuance costs for Cleco Holdings of $11.9 million and $8.2 million, respectively, partially offset by deferred debt issuance costs eliminated as a result of the 2016 Merger of $5.6 million and $6.3 million, respectively. For more information, see Note 6 — “Regulatory Assets and Liabilities — Cleco Holdings’ 2016 Merger Adjustments.”

The principal amounts payable under long-term debt agreements for each year through 2024 and thereafter are as follows:

(THOUSANDS)	CLECO	CLECO POWER
For the year ending Dec. 31
2020(1)	$11,055	$11,055
2021	$330,000	$—
2022	$25,000	$25,000
2023	$265,000	$100,000
2024	$50,000	$50,000
Thereafter	$2,385,000	$1,200,000

(1)
Does not include Series A GO Zone bonds that have a maturity date of December 2038 but a mandatory tender in May 2020.

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The principal amounts payable under the finance lease agreement for each year through 2024 and thereafter are as follows:

(THOUSANDS)	CLECO	CLECO POWER
For the year ending Dec. 31
2020	$617	$617
2021	$682	$682
2022	$755	$755
2023	$836	$836
2024	$925	$925
Thereafter	$12,046	$12,046

Cleco Power Debt

Cleco Power had no short-term debt outstanding at December 31, 2019, and 2018.

At December 31, 2019, Cleco Power’s long-term debt and finance leases outstanding was $1.39 billion, of which $61.6 million was due within one year. The long-term debt due within one year at December 31, 2019, primarily represents $50.0 million of GO Zone bonds with a mandatory tender in May 2020 and $11.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds.

On March 2, 2020, Cleco Power completed the repayment of its Cleco Katrina/Rita storm recovery bonds issued in March 2008.

Cleco Debt

Cleco had no short-term debt outstanding at December 31, 2019, and 2018.

At December 31, 2019, Cleco’s long-term debt and finance leases outstanding was $3.19 billion, of which $126.0 million was due within one year. The long-term debt due within one year at December 31, 2019, primarily represents $63.3 million of principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC, $50.0 million of GO Zone bonds with a mandatory tender in May 2020, and $11.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds.

In connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings borrowed $300.0 million under a new bridge loan agreement and $100.0 million under a new term loan agreement. Both loan agreements are variable rate debt and have a three-year term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings to maintain (i) a debt to capital ratio (as defined in the applicable agreement) below 65% and (ii) a rating applicable to Cleco’s senior debt rating (as defined in the applicable agreement). On September 11, 2019, Cleco Holdings completed the private placement of $300.0 million aggregate principal amount of its 3.375% senior notes due September 15, 2029. The proceeds from the issuance were used to repay the remaining amounts due under the $300.0 million bridge loan agreement and to repay a portion of the $100.0 million term loan agreement. The senior notes are governed by an indenture entered into between Cleco Holdings and a trustee. The indenture contains certain covenants that restrict Cleco Holdings’ ability to merge, consolidate, transfer, or lease all or substantially all of its assets or create or incur certain liens.

Upon approval of the Cleco Cajun Transaction, commitments were made to the LPSC by Cleco, including repayment of $400.0 million of Cleco Holdings’ debt by December 31, 2024. As of December 31, 2019, Cleco Holdings was in compliance with these commitments. The cumulative minimum principal amounts committed to be repaid for each year through 2024 are as follows:

(THOUSANDS)
For the year ending Dec. 31
2019	$66,700
2020	$133,300
2021	$200,000
2022	$267,700
2023	$333,300
2024	$400,000

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Credit Facilities

At December 31, 2019, Cleco had two separate revolving credit facilities, one for Cleco Holdings in the amount of $175.0 million and one for Cleco Power in the amount of $300.0 million, with a maximum aggregate capacity of $475.0 million.

In connection with the Cleco Cajun Transaction, on February 4, 2019, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total credit facility of $175.0 million. The credit facility includes restrictive financial covenants and expires in 2021. Under covenants contained in Cleco Holdings’ credit facility, Cleco is required to maintain total indebtedness less than or equal to 65% of total capitalization. At December 31, 2019, $1.01 billion of Cleco’s member’s equity was unrestricted. At December 31, 2019, Cleco Holdings was in compliance with the covenants of its credit facility. The borrowing costs under Cleco Holdings’ credit facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%. If Cleco Holding’s credit ratings were to be downgraded one level, Cleco Holdings could be required to pay higher fees and additional interest of 0.075% and 0.50%, respectively, under the pricing levels of its credit facility.

At December 31, 2019, Cleco Power had a $300.0 million credit facility. The credit facility includes restrictive financial covenants and expires in 2021. Under covenants contained in Cleco Power’s credit facility, Cleco Power is required to maintain total indebtedness less than or equal to 65% of total capitalization. At December 31, 2019, $989.0 million of Cleco Power’s member’s equity was unrestricted. At December 31, 2019, Cleco Power was in compliance with the covenants in its credit facility. The borrowing costs under Cleco Power’s credit facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%. If Cleco Power’s credit ratings were to be downgraded one level, Cleco Power could be required to pay higher fees and additional interest of 0.05% and 0.125%, respectively, under the pricing levels of its credit facility.

If Cleco Holdings or Cleco Power were to default under the covenants in their respective credit facilities or other debt agreements, they would be unable to borrow additional funds under the facilities 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 Holdings would be considered in default under its credit facility.

Note 10 — Pension Plan and Employee Benefits

Pension Plan and Other Benefits Plan

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 ten 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. On September 12, 2019, Cleco made a $12.3 million discretionary contribution to the pension plan. Cleco did not make any required or discretionary contributions to the pension plan in 2018 or 2017. Cleco expects to make $83.0 million discretionary contributions in 2020, which would reduce the future required contributions. 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. Based on funding assumptions at December 31, 2019, management estimates that $61.8 million in pension contributions will be required through 2024. 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. Adverse changes in assumptions or adverse actual events could cause additional minimum contributions. 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 the plan sponsor and Support Group is the plan administrator.

The pension plan was amended on February 4, 2019, to include certain former NRG Energy employees who are now Cleco Cajun employees. The Cleco Cajun employees are eligible to participate as a cash balance participant and are credited with all service that was credited to them under the NRG Pension Plan as of February 4, 2019. Benefits under the plan amendment reflect the employee’s years of service, age at retirement, and accrued benefit at retirement.

Cleco’s retirees may be eligible to receive Other Benefits. Dependents of Cleco’s retirees may also be eligible to receive Other Benefits with the exception of life insurance benefits. Cleco recognizes the expected cost of Other Benefits during the periods in which the benefits are earned.

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The employee pension plan and Other Benefits plan obligation, plan assets, and funded status at December 31, 2019, and 2018 are presented in the following table:

	PENSION BENEFITS		OTHER BENEFITS
	FOR THE YEAR ENDED DEC. 31,		FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2019	2018
Change in benefit obligation
Benefit obligation at beginning of period	$530,936	$567,215	$40,455	$43,203
Service cost	8,414	9,507	1,191	1,320
Interest cost	22,485	20,860	1,646	1,465
Plan participants’ contributions	—	—	1,229	1,224
Actuarial loss (gain)	73,655	(42,935)	13,897	(1,106)
Expenses paid	(2,933)	(2,786)	—	—
Benefits paid	(22,234)	(20,925)	(5,696)	(5,651)
Benefit obligation at end of period	610,323	530,936	52,722	40,455
Change in plan assets
Fair value of plan assets at beginning of period	391,933	444,089	—	—
Actual return on plan assets	81,081	(28,884)	—	—
Employer contributions	12,250	—	—	—
Expenses paid	(2,933)	(2,786)	—	—
Adjustment	—	439	—	—
Benefits paid	(22,234)	(20,925)	—	—
Fair value of plan assets at end of period	460,097	391,933	—	—
Unfunded status	$(150,226)	$(139,003)	$(52,722)	$(40,455)

The employee pension plan accumulated benefit obligation at December 31, 2019, and 2018 is presented in the following table:

	PENSION BENEFITS
	AT DEC. 31,
(THOUSANDS)	2019	2018
Accumulated benefit obligation	$568,354	$491,522

The following table presents the net actuarial gains/losses and prior service costs/credits included in other comprehensive income for Other Benefits and in regulatory assets for pension related to current year gains and losses as a result of being included in net periodic benefit costs for the employee pension plan and Other Benefits plan for December 31, 2019, and 2018:

	PENSION BENEFITS		OTHER BENEFITS
	AT DEC. 31,		AT DEC. 31,
(THOUSANDS)	2019	2018	2019	2018
Net actuarial loss (gain) occurring during period	$19,075	$9,722	$13,897	$(1,106)
Net actuarial loss amortized during period	$7,849	$12,313	$21	$135
Prior service credit amortized during period	$(71)	$(71)	$—	$—

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The following table presents net actuarial gains/losses and prior service costs/credits in accumulated other comprehensive income for Other Benefits and in regulatory assets for pension that have not been recognized as components of net periodic benefit costs and the amounts expected to be recognized in 2020 for the employee pension plan and Other Benefits plans at December 31, 2020, 2019, and 2018:

	PENSION BENEFITS			OTHER BENEFITS
	AT DEC. 31,			AT DEC. 31,
(THOUSANDS)	2020	2019	2018	2020	2019	2018
Net actuarial loss	$14,824	$151,603	$140,377	$1,355	$15,732	$1,814
Prior service credit	$(60)	$(60)	$(131)	$—	$—	$—

The non-service components of net periodic pension and Other Benefits cost are included in Other income (expense), net within Cleco and Cleco Power’s Consolidated Statements of Income. The components of net periodic pension and Other Benefits costs for 2019, 2018, and 2017 are as follows:

	PENSION BENEFITS			OTHER BENEFITS
	FOR THE YEAR ENDED DEC. 31,			FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017	2019	2018	2017
Components of periodic benefit costs
Service cost	$8,414	$9,507	$9,039	$1,191	$1,320	1,446
Interest cost	22,485	20,860	21,648	1,646	1,465	1,569
Expected return on plan assets	(26,502)	(23,773)	(24,064)	—	—	—
Amortizations
Prior service credit	(71)	(71)	(71)	—	—	—
Net loss (gain)	7,849	12,312	10,008	21	135	(50)
Net periodic benefit cost	$12,175	$18,835	$16,560	2,858	$2,920	$2,965

Because 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, 2019, 2018, and 2017 was $2.2 million, $2.0 million, and $1.8 million, respectively.

Cleco Holdings 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. The expense related to Other Benefits reflected in Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2019, 2018, and 2017 was $3.1 million, $3.3 million, and $3.3 million, respectively. The current and non-current portions of the Other Benefits liability for Cleco and Cleco Power at December 31, 2019, and 2018 are as follows:

Cleco
	AT DEC. 31,
(THOUSANDS)	2019	2018
Current	$4,401	$4,130
Non-current	$48,321	$36,325

Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Current	$3,815	$3,584
Non-current	$42,080	$31,694

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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
	AT DEC. 31,		AT DEC. 31,
	2019	2018	2019	2018
Weighted-average assumptions used to determine the benefit obligation
Discount rate	3.43%	4.35%	3.25%	4.16%
Rate of compensation increase	2.81%	2.93%	N/A	N/A

	PENSION BENEFITS			OTHER BENEFITS
	FOR THE YEAR ENDED DEC. 31,			FOR THE YEAR ENDED DEC. 31,
	2019	2018	2017	2019	2018	2017
Weighted-average assumptions used to determine the net benefit cost
Discount rate	4.35%	3.73%	4.27%	4.16%	3.47%	3.81%
Expected return on plan assets	6.55%	5.86%	6.08%	N/A	N/A	N/A
Rate of compensation increase	2.81%	2.93%	2.98%	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 were 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 2020 periodic expense, Cleco decreased the expected long-term return on plan assets to 5.91%. Cleco expects pension expense to increase in 2020 by approximately $6.0 million due to a decrease in the discount rate and a decrease in expected return on plan assets.

Employee pension plan assets are invested in accordance with the Pension Plan’s Investment Policy Statement. At December 31, 2019, allowable investments included U.S. Equity Portfolios, International Equity - Developed Markets Portfolios, Emerging Markets Equity Portfolios, Multi-Asset Credits, Treasury Separate Trading of Registered Interest and Principal of Securities (STRIPS), Fixed Income Portfolios - Long Credit, and Real Estate Portfolios.

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.

Fair Value Disclosures

Cleco classifies 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,

• 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.

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There have been no changes in the methodologies for determining fair value at December 31, 2019, and 2018. The following tables disclose the pension plan’s fair value of financial assets measured on a recurring basis:

(THOUSANDS)	AT DEC. 31, 2019	QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)	SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Cash equivalents	$4,810	$—	$4,810	$—
Government securities	19,517	—	19,517	—
Mutual funds
Domestic	102,184	102,184	—	—
International	53,041	53,041	—	—
Real estate funds	18,017	—	—	18,017
Corporate debt	157,109	—	157,109	—
Total	$354,678	$155,225	$181,436	$18,017
Investments measured at net asset value*	103,326
Interest accrual	2,093
Total net assets	$460,097

*
Investments measured at net asset value consist of Common/collective trust.

(THOUSANDS)	AT DEC. 31, 2018	QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)	SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)
Asset Description
Cash equivalents	$2,471	$—	$2,471	$—
Common stock	13,111	13,111	—	—
Government securities	19,831	—	19,831	—
Mutual funds
Domestic	79,210	79,210	—	—
International	43,418	43,418	—	—
Real estate funds	20,298	—	—	20,298
Corporate debt	138,391	—	138,391	—
Total	$316,730	$135,739	$160,693	$20,298
Investments measured at net asset value*	73,100
Interest accrual	2,103
Total net assets	$391,933

*
Investments measured at net asset value consist of Common/collective trust.

Level 3 valuations are derived from other valuation methodologies including pricing models, discounted cash flow models, and similar techniques. Level 3 valuations incorporate subjective judgments and consider assumptions including capitalization rates, discount rates, cash flows, and other factors that are not observable in the market. Significant increases or decreases in any of those inputs in isolation would result in a significantly different fair value measurement.

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The following is a reconciliation of the beginning and ending balances of the pension plan’s real estate funds measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2019, and 2018:

(THOUSANDS)
Balance, Dec. 31, 2017	$19,195
Realized losses	29
Unrealized gains	391
Purchases	710
Sales	(27)
Balance, Dec. 31, 2018	$20,298
Realized gains	370
Unrealized losses	(1,727)
Purchases	759
Sales	(1,683)
Balance, Dec. 31, 2019	$18,017

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 2019, the return on plan assets was 22.17% compared to an expected long-term return of 6.55%. The 2018 return on pension plan assets was (7.31)% compared to an expected long-term return of 5.86%. As of December 31, 2019, none of the pension plan participants’ future annual benefits are covered by insurance contracts.

Pension Plan Investment Objectives

Cleco’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 (FAS) actuarial assumed rate of return on plan assets, and

• Exceed the annualized total return of the following customized index (based on the target allocation in the glide path) consisting of a mixture of S&P 500 Index, Russell 2500 Index, Morgan Stanley Capital International All Country World ex U.S. Index, Morgan Stanley Capital International Emerging Markets Index, Customer Index related to Multi-Asset Credit asset class, Bloomberg Barclays Capital Long Credit Index, Bloomberg Barclays 15+ Year Treasury STRIPS, and National Council of Real Estate Investment Fiduciaries Index.

Risk characteristics of the portfolio (annualized standard deviation of returns) should be similar to or less than the custom index.

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

U.S. Equity Portfolios

• Equity holdings of a single company (including common stock and convertible securities) must not exceed 10% of the manager’s portfolio measured at market value.

• A minimum of 25 stocks should be owned in the portfolio.

• Equity holdings in any one economic sector should not exceed the lesser of three times the sector’s weighting in the S&P 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.

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International Equity - Developed Markets Portfolios

• Equity holdings of a single company (including common stock and convertible securities) should not exceed 5% of the manager’s portfolio measured at market value.

• A minimum of 30 stocks should be owned.

• Equity holdings in any industry sector should not exceed 35%.

• A minimum of 50% of the countries within the Morgan Stanley Capital International All Country World ex U.S. 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 Morgan Stanley Capital International All Country World ex U.S. Index.

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

Emerging Markets Portfolios

• 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.

Multi-Asset Credits

• Assets can include, but would not be limited to, high yield debt, emerging market debt, global investment grade credit and bank loans, as well as fixed income strategies.

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

Treasury STRIPS

• The STRIPS are synthetic zero-coupon bonds that are created by separating each coupon and principal payment of a treasury bond into a separate security. STRIPS take the form of a zero-coupon bond which is sold at a discount to face value and mature at par. They are backed by U.S. Treasury securities.

• Implementation of the portfolio is either through Treasury Futures or purchase of Treasury STRIPS through an investment manager.

• The benchmark would be Bloomberg Barclays 15+ Year Treasury STRIPS.

Fixed Income Portfolios - 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.

• Securities must have a maximum position size of 5% for A rated securities and 3% for BBB rated securities.

• The duration of the portfolio must be within +/- 1 year of benchmark.

• Treasury STRIPS managers will have the discretion to utilize U.S. treasury futures and STRIPS as needed to adjust the portfolio duration.

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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.

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. The Long Duration fixed income managers and Treasury STRIPS manger(s) are exempt from the prohibition on derivatives use, due to the nature of long duration fixed income management. Currency hedging is permitted for international investing.

The investment manager of affiliated securities shall not purchase any securities of its organization or affiliated entities.

The following chart shows the dynamic asset allocation based on the funded ratio at December 31, 2019:

	PERCENT OF TOTAL PLAN ASSETS
	AT DEC. 31, 2019
	MINIMUM	TARGET	MAXIMUM
Return-seeking
Domestic equity		19%
International equity		20%
Multi-asset credit		6%
Real estate		5%
Total return-seeking	45%	50%	55%
Liability hedging*	45%	50%	55%

*
Liability hedging has no target subcategories

The assumed health care cost trend rates used to measure the expected cost of Other Benefits is 5.0% for 2020 and remains at 5.0% thereafter. The rate used for 2019 was also 5.0%. Assumed health care cost trend rates have a limited effect on the amount reported for Cleco’s 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	$(16)
Effect on postretirement benefit obligation	$205	$(229)

The projected benefit payments for the employee pension plan and Other Benefits obligation plan for each year through 2024 and the next five years thereafter are listed in the following table:

(THOUSANDS)	PENSION BENEFITS	OTHER BENEFITS, GROSS
For the year ending Dec. 31,
2020	$24,065	$4,472
2021	$25,293	$4,498
2022	$26,541	$4,554
2023	$27,709	$4,536
2024	$28,741	$4,531
Next five years	$158,810	$21,706

SERP

Certain Cleco officers are covered by SERP. In 2014, SERP was closed to new participants; however, with regard to current SERP participants, including former employees or their beneficiaries, all terms of SERP will

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continue, other than as described below. SERP is a non-qualified, non-contributory, defined benefit pension plan. Generally, benefits under the plan reflect an employee’s years of service, age at retirement, and the sum of (a) the highest base salary paid out over the last five calendar years and (b) the average of the five highest cash bonuses paid during the 60 months prior to retirement. SERP benefits are reduced by retirement benefits received from any other defined benefit pension plan, supplemental executive retirement plan, or Cleco contributions under the enhanced 401(k) Plan to the extent such contributions exceed the amount the employee would have received under the terms of the original 401(k) Plan. Two executive officers’ SERP benefits were capped as of December 31, 2017, with regard to final compensation; however, adjustments will continue with regard to age and tenure with Cleco. Additionally, these executive officers had their annual bonuses set at target rather than actual awards for 2017 for the average incentive award portion of their SERP benefit calculation. A third executive officer’s SERP benefit amount will be set at a specified amount based upon the year of separation. Management reviews current market trends as it evaluates Cleco’s future compensation strategy.

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. The life insurance policies issued on SERP participants designate the rabbi trust as the beneficiary. Market conditions could have a significant impact on the cash surrender value of the life insurance policies. Proceeds from the life insurance policies are expected to be used to pay the SERP participants’ death benefits, as well as future SERP payments. However, because 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 that employed the officer. Cleco Power is the plan sponsor and Support Group is the plan administrator.

SERP’s funded status at December 31, 2019, and 2018 is presented in the following table:

	SERP BENEFITS
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018
Change in benefit obligation
Benefit obligation at beginning of period	$78,414	$84,339
Service cost	330	542
Interest cost	3,326	3,077
Actuarial loss (gain)	11,608	(5,163)
Benefits paid	(4,550)	(4,381)
Benefit obligation at end of period	$89,128	$78,414

SERP’s accumulated benefit obligation at December 31, 2019, and 2018 is presented in the following table:

	SERP BENEFITS
	AT DEC. 31,
(THOUSANDS)	2019	2018
Accumulated benefit obligation	$89,128	$78,414

The following table presents net actuarial gains/losses and prior service costs/credits included in other comprehensive income or regulatory assets related to current year gains and losses as a result of being amortized as a component of net periodic benefit costs for SERP for December 31, 2019, and 2018:

	SERP BENEFITS
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018
Net actuarial loss (gain) occurring during year	$11,608	$(5,163)
Net actuarial loss amortized during year	$1,544	$2,913
Prior service credit amortized during year	$(160)	$(160)

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The following table presents net actuarial losses and prior service credit in accumulated other comprehensive income and regulatory assets that have not been recognized as components of net periodic benefit costs and the amounts expected to be recognized in 2020 for SERP at December 31, 2020, 2019, and 2018:

	SERP BENEFITS
	AT DEC. 31,
(THOUSANDS)	2020	2019	2018
Net actuarial loss	$3,171	$28,731	$17,261
Prior service credit	$(160)	$(1,678)	$(1,837)

The non-service components of net periodic benefit cost related to SERP are included in Other income (expense), net within Cleco and Cleco Power’s Consolidated Statements of Income. The components of the net SERP costs for 2019, 2018, and 2017 are as follows:

	SERP BENEFITS
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Components of periodic benefit costs
Service cost	$330	$542	$494
Interest cost	3,326	3,077	3,239
Amortizations
Prior service credit	(160)	(160)	(190)
Net loss	1,544	2,913	2,105
Net periodic benefit cost	5,040	6,372	5,648
Special/contractual termination benefits	—	—	315
Total benefit cost	$5,040	$6,372	$5,963

There was a remeasurement of SERP at March 30, 2017, to reflect a special termination benefit resulting from an executive officer’s separation agreement. On the date of the remeasurement, the discount rate decreased from 4.22% to 4.08%. This remeasurement resulted in a special termination benefit for the executive officer of $0.3 million.

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 BENEFITS
	AT DEC. 31,
	2019	2018
Weighted-average assumptions used to determine the benefit obligation
Discount rate	3.37%	4.34%
Rate of compensation increase	5.00%	5.00%

	SERP BENEFITS
	JAN. 1, 2019 - DEC. 31, 2019	JAN. 1, 2018 - DEC. 31, 2018	MAR. 31, 2017 - DEC. 31, 2017	JAN. 1, 2017 - MAR. 30, 2017
Weighted-average assumptions used to determine the net benefit cost
Discount rate	4.34%	3.70%	4.08%	4.22%
Rate of compensation increase	5.00%	5.00%	5.00%	5.00%

The expense related to SERP reflected on Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2019, 2018, and 2017 was $0.8 million, $1.4 million, and $1.3 million, respectively.

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Liabilities relating to SERP are reported on the individual subsidiaries’ financial statements. The current and non-current portions of the SERP liability for Cleco and Cleco Power at December 31, 2019, and 2018 are as follows:

Cleco
	AT DEC. 31,
(THOUSANDS)	2019	2018
Current	$4,599	$4,478
Non-current	$84,529	$73,936

Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Current	$760	$930
Non-current	$13,964	$12,025

The projected benefit payments for SERP for each year through 2024 and the next five years thereafter are shown in the following table:

(THOUSANDS)	2020	2021	2022	2023	2024	NEXT FIVE YEARS
SERP	$4,662	$4,689	$4,698	$4,710	$4,753	$24,861

401(k) Plan

Cleco’s 401(k) Plan is intended to provide active, eligible employees with voluntary, long-term savings and investment opportunities. The 401(k) Plan is a defined contribution plan and is subject to the applicable provisions of the Employee Retirement Income Security Act of 1974. In accordance with the 401(k) Plan, employer contributions are made in the form of cash. Cash contributions are invested in proportion to the participant’s voluntary contribution investment choices. Participation in the Plan is voluntary and active Cleco employees are eligible to participate. Cleco’s 401(k) was amended upon the close of the Cleco Cajun Transaction to include Cleco Cajun employees. Cleco’s 401(k) Plan expense for the years ended December 31, 2019, 2018, and 2017 was as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
401(k) Plan expense	$7,861	$5,884	$5,386

Cleco Power is the plan sponsor for the 401(k) Plan. The expense of the 401(k) Plan related to Cleco’s other subsidiaries for the years ended December 31, 2019, 2018, and 2017 was as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
401(k) Plan expense	$3,408	$1,066	$888

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Note 11 — Income Taxes

Cleco

For the years ended December 31, 2019, and 2018, income tax expense was higher than the amount computed by applying the statutory federal rate. For the year ended December 31, 2017, income tax expense was lower than the amount computed by applying the statutory federal rate. The differences are as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT PERCENTAGES)	2019	2018	2017
Income before tax	$195,830	$123,819	$145,159
Statutory rate	21.0%	21.0%	35.0%
Tax expense at federal statutory rate	$41,124	$26,002	$50,806
Increase (decrease)
Plant differences, including AFUDC flowthrough	(4,687)	(401)	743
State income taxes, net of federal benefit	9,565	6,288	5,047
Return to accrual adjustment	(3,963)	(193)	(608)
TCJA	—	(19)	(46,291)
NMTC	—	(1,578)	313
Other, net	1,126	(717)	(2,931)
Total tax expense	$43,165	$29,382	$7,079
Effective rate	22.0%	23.7%	4.9%

Information about current and deferred income tax expense is as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Current federal income tax expense	$1,600	$15,304	$46,520
Deferred federal income tax expense (benefit)	37,963	5,863	(47,329)
Amortization of accumulated deferred investment tax credits	(191)	(236)	(662)
Total federal income tax expense (benefit)	$39,372	$20,931	$(1,471)
Current state income tax expense	1,675	7,771	3,187
Deferred state income tax expense	2,118	680	5,363
Total state income tax expense	$3,793	$8,451	$8,550
Total federal and state income tax expense	$43,165	$29,382	$7,079
Items charged or credited directly to member’s equity
Federal deferred	(5,130)	1,408	(2,380)
State deferred	(1,678)	460	(384)
Total tax (benefit) expense from items charged directly to member’s equity	$(6,808)	$1,868	$(2,764)
Total federal and state income tax expense	$36,357	$31,250	$4,315

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The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2019, and 2018 was comprised of the following:

	AT DEC. 31,
(THOUSANDS)	2019	2018
Depreciation and property basis differences	$(862,263)	$(664,996)
Net operating loss carryforward	120,955	—
NMTC	92,364	86,673
Fuel costs	(3,984)	(8,339)
Other comprehensive income	10,612	640
Regulated operations regulatory liability, net	34,836	39,808
Postretirement benefits	22,691	19,580
Merger fair value adjustments	(52,957)	(56,725)
Other	(19,312)	(24,671)
Accumulated deferred federal and state income taxes, net	$(657,058)	$(608,030)

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, 2019, and 2018, Cleco had a deferred tax asset resulting from NMTC carryforwards of $92.4 million and $86.9 million, respectively. If the NMTC 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 NMTC carryforwards will be realized; therefore, no valuation allowance has been recorded.

Net Operating Losses

For the 2019 tax year, Cleco created approximately $536.5 million and $68.7 million of federal and state net operating losses, respectively, primarily due to the Cleco Cajun Transaction.

The federal net operating loss may be carried forward indefinitely, and state net operating loss carryforwards will begin to expire in 2039.

Cleco considers it more likely than not that these income tax losses will be utilized to reduce future income tax payments and utilize the entire net operating loss carryforward within the statutory deadlines.

Cleco Power

For the years ended December 31, 2019, and 2018, income tax expense was higher than the amount computed by applying the statutory rate. For the year ended December 31, 2017, income tax expense was lower 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 PERCENTAGES)	2019	2018	2017
Income before tax	$193,714	$218,181	$218,069
Statutory rate	21.0%	21.0%	35.0%
Tax expense at federal statutory rate	$40,680	$45,818	$76,324
Increase (decrease)
Plant differences, including AFUDC flowthrough	(4,687)	(401)	743
State income taxes, net of federal benefit	11,683	11,080	7,583
Return to accrual adjustment	(2,008)	483	(284)
TCJA	—	(19)	(14,292)
Other, net	(216)	(1,037)	(2,743)
Total taxes	$45,452	$55,924	$67,331
Effective rate	23.5%	25.6%	30.9%

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Information about current and deferred income tax expense is as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Current federal income tax expense	$14,781	$44,411	$87,433
Deferred federal income tax expense (benefit)	22,443	(9,033)	(29,190)
Amortization of accumulated deferred investment tax credits	(191)	(236)	(662)
Total federal income tax expense	$37,033	$35,142	$57,581
Current state income tax expense	9,063	23,293	14,751
Deferred state income tax benefit	(644)	(2,511)	(5,001)
Total state income tax expense	$8,419	$20,782	$9,750
Total federal and state income taxes	$45,452	$55,924	$67,331
Items charged or credited directly to members’ equity
Federal deferred	(2,500)	797	(141)
State deferred	(818)	261	(23)
Total tax (benefit) expense from items charged directly to member’s equity	$(3,318)	$1,058	$(164)
Total federal and state income tax expense	$42,134	$56,982	$67,167

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2019, and 2018 was comprised of the following:

	AT DEC. 31,
(THOUSANDS)	2019	2018
Depreciation and property basis differences	$(705,423)	$(666,224)
Net operating loss carryforward	2,714	—
Fuel costs	(5,608)	(8,339)
Other comprehensive income	7,510	4,192
Regulated operations regulatory liability, net	34,836	39,808
Postretirement benefits	10,044	11,081
Other	(1,907)	(11,283)
Accumulated deferred federal and state income taxes, net	$(657,834)	$(630,765)

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. Management considers it more likely than not that all deferred tax assets will be realized; therefore, no valuation allowance has been recorded.

Uncertain Tax Positions

Cleco classifies all interest related to uncertain tax positions as a component of interest payable and interest expense. At December 31, 2019, and 2018, Cleco and Cleco Power had no interest payable related to uncertain tax positions. For the years ended December 31, 2019, 2018, and 2017, Cleco and Cleco Power had no interest expense related to uncertain tax positions.

At December 31, 2019, and 2018, Cleco and Cleco Power had no liability for unrecognized tax positions. Cleco estimates that it is reasonably possible that the balance of unrecognized tax benefits as of December 31, 2019, for Cleco and Cleco Power would be unchanged in the next 12 months. The settlement of open tax years could involve the payment of additional taxes, and/or the recognition of tax benefits, which may affect Cleco’s effective income tax rate.

Income Tax Audits

Cleco participates in the IRS’s Compliance Assurance Process in which financial results are examined and agreed upon prior to filing federal consolidated tax returns. The 2018 federal income tax year remains subject to examination by the IRS. While the statute of limitations remains open for tax years 2016 and 2017 until 2020 and 2021, respectively, management believes the likelihood of further examination by the IRS is remote.

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The state income tax years 2016, 2017, and 2018 remain subject to examination by the Louisiana Department of Revenue.

Cleco classifies income tax penalties as a component of other expenses. For the years ended December 31, 2019, and 2018, no penalties were recognized.

TCJA

On December 22, 2017, the President signed into law the TCJA. The TCJA includes significant changes to the IRC, as amended, including amendments which significantly change the taxation of business entities and includes specific provisions related to rate regulated activities, including Cleco Power. The most significant change that impacts Cleco is the reduction of the corporate federal income tax rate from 35% to 21%.

The SEC Staff recognized the complexity of reflecting the impacts of the TCJA and issued guidance which clarified accounting for income taxes and allowed for up to one year to complete the required analysis and accounting (the measurement period). During the fourth quarter of 2018, Cleco finalized the remeasurement of and accounting for the effects of the TCJA, which resulted in a total net reduction in the ADIT liability for Cleco and Cleco Power of $421.2 million and $389.3 million, respectively. For more information on the regulatory treatment of the TCJA regulatory liability, see Note 6 — “Regulatory Assets and Liabilities — Income Taxes” and Note 13 — “Regulation and Rates — TCJA.”

Additionally, as a result of the TCJA, effective for tax years beginning after December 31, 2017, corporations are no longer subject to the alternative minimum tax (AMT). For companies with unused AMT credits, the credits may be carried forward and used as refundable credits for tax years beginning after 2017, but before 2022. Cleco expects its unused AMT credits will be fully utilized by December 31, 2021. During 2018, Cleco’s $7.6 million of unused tax credits were reclassed from Accumulated deferred federal and state income taxes, net to Taxes payable, net and Other deferred charges on Cleco’s Consolidated Balance Sheets. At December 31, 2019, and 2018, Cleco had $1.4 million and $3.8 million in AMT credits recorded in Taxes payable, net on Cleco’s Consolidated Balance Sheets for the current amount of credits expected to be utilized. At December 31, 2019, and 2018, Cleco had $1.4 million and $3.8 million in non-current AMT credits recorded in Other deferred charges on Cleco’s Consolidated Balance Sheets.

Note 12 — Disclosures about Segment

Cleco

Cleco’s reportable segments are based on its method of internal reporting, which disaggregates business units by its first-tier subsidiary. Cleco’s reportable segments are Cleco Power and Cleco Cajun.

Each reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco’s CEO with discrete financial information and, at least quarterly, present discrete financial information to Cleco and Cleco Power’s Boards of Managers. The reportable segment prepares budgets that are presented to and approved by Cleco and Cleco Power’s Boards of Managers. The column shown as Other in the following tables includes the holding company, a shared services subsidiary, an investment subsidiary, and a subsidiary formed to facilitate the Cleco Cajun Transaction. Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a new reportable segment. For more information on the transaction, see Note 3 — “Business Combinations.”

The financial results in the following tables are presented on an accrual basis. The historical segment information was not recast because the Cleco Cajun segment only consists of the newly acquired business. There were no other changes to Cleco’s existing reportable segments. Management evaluates the performance of its segments and allocates resources to them based on segment profit and the requirements to implement 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 as well as transmission services provided by Cleco Power to Cleco Cajun.

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SEGMENT INFORMATION
	FOR THE YEAR ENDED DEC. 31, 2019
(THOUSANDS)	CLECO POWER	CLECO CAJUN	OTHER	ELIMINATIONS	CONSOLIDATED
Revenue
Electric operations	$1,130,928	$375,489	$(9,680)	$(1)	$1,496,736
Other operations	72,833	117,468	2	(7,471)	182,832
Affiliate revenue	3,125	108	109,067	(112,300)	—
Electric customer credits	(38,516)	(1,447)	—	—	(39,963)
Operating revenue, net	$1,168,370	$491,618	$99,389	$(119,772)	$1,639,605
Depreciation and amortization	$172,471	$35,544	$8,305	$—	$216,320
Merger transaction and commitment costs	$—	$—	$7,668	$—	$7,668
Interest income	$4,744	$987	$974	$(615)	$6,090
Interest charges	$71,279	$35	$70,611	$(616)	$141,309
Net income (loss)	$148,262	$69,411	$(65,009)	$1	$152,665
Additions to property, plant, and equipment	$313,962	$9,174	$655	$—	$323,791
Equity investment in investee	$17,072	$—	$—	$—	$17,072
Goodwill	$1,490,797	$—	$—	$—	$1,490,797
Total segment assets	$5,967,327	$1,011,591	$546,096	$(48,716)	$7,476,298

	FOR THE YEAR ENDED DEC. 31, 2018
(THOUSANDS)	CLECO POWER	OTHER	ELIMINATIONS	CONSOLIDATED
Revenue
Electric operations	$1,191,587	$(9,680)	$—	$1,181,907
Other operations	82,330	2	—	82,332
Affiliate revenue	874	74,591	(75,465)	—
Electric customer credits	(33,195)	—	—	(33,195)
Operating revenue, net	$1,241,596	$64,913	$(75,465)	$1,231,044
Depreciation and amortization	$162,069	$8,344	$1	$170,414
Merger transaction and commitment costs	$—	$19,514	$—	$19,514
Interest income	$5,052	$1,338	$(317)	$6,073
Interest charges	$71,303	$55,659	$(320)	$126,642
Federal and state income tax expense (benefit)	$55,924	$(26,541)	$(1)	$29,382
Net income (loss)	$162,257	$(67,819)	$(1)	$94,437
Additions to property, plant, and equipment	$289,153	$1,908	$—	$291,061
Equity investment in investee	$18,172	$—	$—	$18,172
Goodwill	$1,490,797	$—	$—	$1,490,797
Total segment assets	$5,839,853	$633,756	$(36,795)	$6,436,814

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	FOR THE YEAR ENDED DEC. 31, 2017
(THOUSANDS)	CLECO POWER	OTHER	ELIMINATIONS	CONSOLIDATED
Revenue
Electric operations	$1,108,389	$(10,757)	$—	$1,097,632
Other operations	77,522	2,058	—	79,580
Affiliate revenue	851	57,168	(58,019)	—
Electric customer credits	(1,566)	—	—	(1,566)
Operating revenue, net	$1,185,196	$48,469	$(58,019)	$1,175,646
Depreciation and amortization	$158,415	$8,439	$—	$166,854
Merger transaction and commitment costs	$—	$5,445	$(293)	$5,152
Interest income	$1,283	$316	$(175)	$1,424
Interest charges	$69,362	$53,725	$(174)	$122,913
Federal and state income tax expense (benefit)	$67,331	$(60,252)	$—	$7,079
Net income (loss)	$150,738	$(12,659)	$1	$138,080
Additions to property, plant, and equipment	$235,252	$1,680	$—	$236,932
Equity investment in investee	$18,172	$—	$—	$18,172
Goodwill	$1,490,797	$—	$—	$1,490,797
Total segment assets	$5,679,538	$619,943	$(21,099)	$6,278,382

Cleco Power

Cleco Power is a vertically integrated, regulated electric utility operating within Louisiana and Mississippi and is viewed as one unit by management. Discrete financial reports are prepared only at the company level.

Note 13 — Regulation and Rates

At December 31, 2019, Provision for rate refund on Cleco and Cleco Power’s Consolidated Balance Sheets consisted primarily of $28.7 million for the estimated refund for the tax-related benefits from the TCJA, $3.5 million for the estimated refund related to the FERC audit, $2.3 million for the estimated FRP refunds, $1.9 million for the cost of service savings refunds, and $1.0 million for potential reductions to the transmission ROE. For more information about the FERC audit, see Note 15 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — FERC Audit.”

Transmission ROE

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco Power, may collect under the MISO tariff. As of December 31, 2019, Cleco Power had $1.0 million accrued for the change in ROE. For more information on the ROE complaint, see Note 15 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE.”

FRP

Cleco Power’s annual retail earnings are subject to an FRP that was approved by the LPSC in June 2014. Under the terms of Cleco Power’s current FRP, Cleco Power is allowed to earn a target ROE of 10.0%, while providing the opportunity to earn up to 10.9%. Additionally, 60% of retail earnings between 10.9% and 11.75%, and all retail earnings over 11.75% are required to be refunded to customers. The amount of credits due to customers, if any, is determined by Cleco Power and the LPSC annually. Credits are typically included on customers’ bills the following summer, but the amount and timing of the refunds are ultimately subject to LPSC approval. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP, with anticipated new rates being effective July 1, 2020. Cleco Power has responded to several sets of data requests relating to the new FRP.

Cleco Power must file annual monitoring reports no later than October 31 for the 12-month period ending June 30. In January 2020, Cleco Power reached an agreement with the LPSC Staff regarding the treatment and realignment of SSR revenue between base and fuel revenue that resulted in $2.3 million of refunds for the 2018

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monitoring report and confirmed no refunds for the 2017 monitoring report. The settlement also applies to treatment of SSR revenues for the 2019 monitoring report. The 2017 monitoring report was approved by the LPSC Staff on February 19, 2020. Cleco Power expects to refund the $2.3 million for the 2018 monitoring report in March 2020. Cleco Power has responded to data requests relating to the 2019 FRP monitoring report.

Cleco Power’s monitoring reports also include a $1.2 million annual cost of service savings as a result of the 2016 Merger Commitments. The cost of service savings are not subject to the target ROE or any sharing mechanism. The cost of service savings are refunded annually in September and will continue until Cleco Power’s next FRP is in effect, which is expected in July 2020. At December 31, 2019, Cleco Power had $1.9 million accrued for the estimated cost of service savings refunds.

TCJA

The provisions of the TCJA reduced the top federal statutory corporate income tax rate from 35% to 21%. As a result of the tax rate reduction, on January 1, 2018, Cleco Power began accruing an estimated reserve for the reduction in the federal statutory corporate income tax rate. In February 2018, the LPSC directed utilities, including Cleco Power, to provide considerations of the appropriate manner to flow through to ratepayers the benefits of the reduction in corporate income taxes as a result of the TCJA. On July 10, 2019, the LPSC approved Cleco Power’s rate refund of $79.2 million, plus interest, for the reduction in the statutory federal tax rate for the period from January 2018 to June 2020. The refund is being credited to customers over 12 months beginning August 1, 2019. At December 31, 2019, Cleco Power had $28.7 million accrued for the estimated federal tax-related benefits from the TCJA and $2.4 million accrued in related interest.

Also on July 10, 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT, resulting from the enactment of the TCJA, in Cleco Power’s application for its next FRP, which was filed on June 28, 2019.

2016 Merger Commitments

On March 28, 2016, the LPSC approved the 2016 Merger. The LPSC’s written order approving the 2016 Merger was issued on April 7, 2016. Approval of the 2016 Merger was conditioned upon certain commitments, including $136.0 million of customer rate credits. As of December 31, 2019, Cleco Power had issued $135.9 million of customer rate credits. Also included in the 2016 Merger Commitments were $2.5 million of contributions for economic development for Louisiana state and local organizations to be disbursed over five years, an additional $7.0 million one-time contribution in 2016 for economic development in Cleco Power’s service territory to be administered by Louisiana Economic Development, and $6.0 million of charitable contributions to be disbursed over five years. At December 31, 2019, Cleco Power had $3.9 million remaining accrued for the 2016 Merger Commitments discussed above.

SSR

In September 2016, Cleco Power filed an Attachment Y with MISO requesting retirement of Teche Unit 3 effective April 1, 2017. MISO conducted a study which determined the proposed retirement of Teche Unit 3 would result in violations of specific applicable reliability standards for which no mitigation is available. As a result, MISO designated Teche Unit 3 as an SSR unit until such time that an appropriate alternative solution can be implemented to mitigate reliability issues. One mitigating factor identified was Cleco Power’s Terrebonne to Bayou Vista Transmission project. The Terrebonne to Bayou Vista project was completed in April 2019. Cleco Power received a termination notice, effective April 30, 2019, and filed paperwork to withdraw the filed Attachment Y. While operating as an SSR unit, Cleco Power received monthly payments that included recovery of expenses, including capital expenditures, related to the operations of Teche Unit 3. Additionally, MISO allocated SSR costs to the load serving entities that required the operation of the SSR unit, including Cleco Power. These payments and cost allocations were finalized as part of a MISO SSR settlement approved in December 2018. Cleco Power operated Teche Unit 3 as an SSR unit from April 2017 through April 2019.

Cleco Power expects Teche Unit 3 to be available to run until the estimated 2021 in-service date of Bayou Vista to Segura Transmission project, at which time, Cleco Power does not expect to offer the unit into MISO, barring any grid or customer reliability issues or other similar reasons. At December 31, 2019, Cleco Power had $6.1 million accrued for the net capital refund for capital expenditures paid for by third parties while operating under the SSR agreement. As part of the settlement, one of the load serving entities agreed to reimburse Cleco Power for their portion of the capital refund. Management is unable to determine the timing of the capital refund.

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Note 14 — Variable Interest Entities

Cleco and Cleco Power apply the equity method of accounting to report the investment in Oxbow in the consolidated financial statements. Under the equity method, the assets and liabilities of this entity are reported as Equity investment in investee on Cleco 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 and Cleco Power’s Consolidated Statements of Income.

Oxbow is owned 50% by Cleco Power and 50% by SWEPCO. Cleco Power is not the primary beneficiary because it shares the power to control Oxbow’s significant activities with SWEPCO. Cleco Power’s current assessment of its maximum exposure to loss related to Oxbow at December 31, 2019, consisted of its equity investment of $17.1 million. During 2019, Cleco Power received $1.1 million from Oxbow as a return of investment.

The following table presents the components of Cleco Power’s equity investment in Oxbow:

	AT DEC. 31,
INCEPTION TO DATE (THOUSANDS)	2019	2018
Purchase price	$12,873	$12,873
Cash contributions	6,399	6,399
Dividend received	(2,200)	(1,100)
Total equity investment in investee	$17,072	$18,172

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

	AT DEC. 31,
(THOUSANDS)	2019	2018
Oxbow’s net assets/liabilities	$34,145	$36,345
Cleco Power’s 50% equity	$17,072	$18,172
Cleco Power’s maximum exposure to loss	$17,072	$18,172

The following tables contain summarized financial information for Oxbow:

	AT DEC. 31,
(THOUSANDS)	2019	2018
Current assets	$2,239	$4,128
Property, plant, and equipment, net	23,738	25,186
Other assets	9,364	9,405
Total assets	$35,341	$38,719
Current liabilities	$1,196	$2,374
Partners’ capital	34,145	36,345
Total liabilities and partners’ capital	$35,341	$38,719

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating revenue	$8,886	$6,992	$4,189
Operating expenses	8,886	6,992	4,189
Income before taxes	$—	$—	$—

DHLC mines lignite reserves at Oxbow through the Amended Lignite Mining Agreement. The lignite reserves are intended to be used to provide fuel to the Dolet Hills Power Station. For more information on DHLC, see Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Risks and Uncertainties.”

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

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Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Litigation

2016 Merger

In connection with the 2016 Merger, four actions were filed in the 9th Judicial District Court for Rapides Parish, Louisiana and three actions were filed in the Civil District Court for Orleans Parish, Louisiana. The petitions in each action generally alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process, agreeing to the 2016 Merger at a price that allegedly undervalued Cleco, and failing to disclose material information about the 2016 Merger. The petitions also alleged that Cleco Partners, Cleco Corporation, Merger Sub, and in some cases, certain of the investors in Cleco Partners either aided and abetted or entered into a civil conspiracy to advance those supposed breaches of duty. The petitions seek various remedies, including monetary damages, which includes attorneys’ fees and expenses.

The four actions filed in the 9th Judicial District Court for Rapides Parish are captioned as follows:

• Braunstein v. Cleco Corporation, No. 251,383B (filed October 27, 2014),

• Moore v. Macquarie Infrastructure and Real Assets, No. 251,417C (filed October 30, 2014),

• Trahan v. Williamson, No. 251,456C (filed November 5, 2014), and

• L’Herisson v. Macquarie Infrastructure and Real Assets, No. 251,515F (filed November 14, 2014).

In November 2014, the plaintiff in the Braunstein action moved for a dismissal of the action without prejudice, and that motion was granted in November 2014. In December 2014, the Court consolidated the remaining three actions and appointed interim co-lead counsel. Also, in December 2014, the plaintiffs in the consolidated action filed a Consolidated Amended Verified Derivative and Class Action Petition for Damages and Preliminary and Permanent Injunction (the Consolidated Amended Petition). The consolidated action named Cleco Corporation, its directors, Cleco Partners, and Merger Sub as defendants. The Consolidated Amended Petition alleged, among other things, that Cleco Corporation’s directors breached their fiduciary duties to Cleco’s shareholders and grossly mismanaged Cleco by approving the Merger Agreement because it allegedly did not value Cleco adequately, failing to structure a process through which shareholder value would be maximized, engaging in self-dealing by ignoring conflicts of interest, and failing to disclose material information about the 2016 Merger. The Consolidated Amended Petition further alleged that all defendants conspired to commit the breaches of fiduciary duty. Cleco believes that the allegations of the Consolidated Amended Petition are without merit and that it has substantial meritorious defenses to the claims set forth in the Consolidated Amended Petition.

The three actions filed in the Civil District Court for Orleans Parish are captioned as follows:

• Butler v. Cleco Corporation, No. 2014-10776 (filed November 7, 2014),

• Creative Life Services, Inc. v. Cleco Corporation, No. 2014-11098 (filed November 19, 2014), and

• Cashen v. Cleco Corporation, No. 2014-11236 (filed November 21, 2014).

Both the Butler and Cashen actions name Cleco Corporation, its directors, Cleco Partners, Merger Sub, MIRA, BCI, and John Hancock Financial as defendants. The Creative Life Services action names Cleco Corporation, its directors, Cleco Partners, Merger Sub, MIRA, and Macquarie Infrastructure Partners III, L.P., as defendants. In December 2014, the plaintiff in the Butler action filed an Amended Class Action Petition for Damages. Each petition alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties to Cleco’s shareholders by approving the Merger Agreement because it allegedly did not value Cleco adequately, failing to structure a process through which shareholder value would be maximized and engaging in self-dealing by ignoring conflicts of interest. The Butler and Creative Life Services petitions also allege that the directors breached their fiduciary duties by failing to disclose material information about the 2016 Merger. Each petition further alleged that Cleco, Cleco Partners, Merger Sub, and certain of the investors in Cleco Partners aided and abetted the directors’ breaches of fiduciary duty. In December 2014, the directors and Cleco filed declinatory exceptions in each action on the basis that each action was improperly brought in Orleans Parish and should either be transferred to the 9th Judicial District Court for Rapides Parish or dismissed. Also, in December 2014, the plaintiffs in each action jointly filed a motion to consolidate the three actions pending in Orleans Parish and to appoint interim co-lead plaintiffs and co-lead counsel. In January 2015, the Court in the

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Creative Life Services case sustained the defendants’ declinatory exceptions and dismissed the case so that it could be transferred to the 9th Judicial District Court for Rapides Parish. In February 2015, the plaintiffs in Butler and Cashen also consented to the dismissal of their cases from Orleans Parish so they could be transferred to the 9th Judicial District Court for Rapides Parish.

In February 2015, the 9th Judicial District Court for Rapides Parish held a hearing on a motion for preliminary injunction filed by plaintiffs Moore, L’Herisson, and Trahan seeking to enjoin the shareholder vote for approval of the Merger Agreement. Following the hearing, the Court denied the plaintiffs’ motion. In June 2015, three of the plaintiffs filed their Second Consolidated Amended Verified Derivative and Class Action Petition. This will be considered according to a schedule established by the 9th Judicial District Court for Rapides Parish. Cleco filed exceptions seeking dismissal of the amended petition in July 2015.

In March 2016 and May 2016, the plaintiffs filed their Third Consolidated Amended Verified Derivative Petition for Damages and Preliminary and Permanent Injunction and their Fourth Verified Consolidated Amended Class Action Petition, respectively. The fourth petition eliminated the request for preliminary and permanent injunction and also named an additional executive officer as a defendant. Cleco filed exceptions seeking dismissal of the amended Petition. A hearing was held in September 2016 and the District Court granted the exceptions filed by Cleco and dismissed all claims asserted by the former shareholders. The plaintiffs appealed the District Court’s ruling to the Louisiana Third Circuit Court of Appeal. The Third Circuit Court of Appeal heard oral arguments in the case in September 2017. In December 2017, the Third Circuit Court of Appeal issued an order reversing and remanding the case to the District Court for further proceedings. In January 2018, Cleco filed a writ with the Louisiana Supreme Court seeking review of the Third Circuit Court of Appeal’s decision. The writ was denied in March 2018 and the parties are engaged in discovery in the District Court. In November 2018, Cleco filed exceptions of no cause of action and res judicata, seeking to dismiss all claims. The District Court denied the exceptions on January 14, 2019. A hearing on the plaintiff’s request for certification of a class was scheduled for August 26, 2019; however, prior to the hearing, the parties reached an agreement to certify a limited class. Cleco believes that the allegations of the petitions in each action are without merit and that it has substantial meritorious defenses to the claims set forth in each of the petitions.

Gulf Coast Spinning

In September 2015, a potential customer sued Cleco for failure to fully perform an alleged verbal agreement to lend or otherwise fund its startup costs to the extent of $6.5 million. Gulf Coast Spinning Company, LLC (Gulf Coast), the primary plaintiff, alleges that Cleco promised to assist it in raising approximately $60.0 million, which Gulf Coast needed to construct a cotton spinning facility near Bunkie, Louisiana. According to the petition filed by Gulf Coast in the 12^th Judicial District Court for Avoyelles Parish, Louisiana (the “District Court”), Cleco made such promises of funding assistance in order to cultivate a new industrial electric customer which would increase its revenues under a power supply agreement that it executed with Gulf Coast. Gulf Coast seeks unspecified damages arising from its inability to raise sufficient funds to complete the project, including lost profits.

Cleco filed an Exception of No Cause of Action arguing that the case should be dismissed. The District Court denied Cleco’s exception in December 2015, after considering briefs and arguments. In January 2016, Cleco appealed the District Court’s denial of its exception by filing with the Third Circuit Court of Appeal. In June 2016, the Third Circuit Court of Appeal denied the request to have the case dismissed. In July 2016, Cleco filed a writ to the Louisiana Supreme Court seeking a review of the District Court’s denial of Cleco’s exception. In November 2016, the Louisiana Supreme Court denied Cleco’s writ application.

In February 2016, the parties agreed to a stay of all proceedings pending discussions concerning settlement. In May 2016, the District Court lifted the stay at the request of Gulf Coast. The parties are currently participating in discovery. Cleco believes the allegations of the petition are contradicted by the written documents executed by Gulf Coast, are otherwise without merit, and that it has substantial meritorious defenses to the claims alleged by Gulf Coast.

Sabine River Flood

In March 2017, Cleco was served with a summons in Perry Bonin, Ace Chandler, and Michael Manuel, et al v. Sabine River Authority of Texas and Sabine River Authority of Louisiana, No. B-160173-C. The action was filed in the 163rd Judicial District Court for Orange County, Texas, and relates to flooding that occurred in

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Texas and Louisiana in March 2016. The plaintiffs have alleged that the flooding was the result of the release of water from the Toledo Bend spillway gates into the Sabine River. While the plaintiffs have made numerous allegations, they have specifically alleged that Cleco Power, included as one of several companies and governmental bodies, failed to repair one of the two hydroelectric generators at the Toledo Bend Dam, which in turn contributed to the flooding. Cleco Power does not operate the hydroelectric generator.

The suit was removed to federal court in Texas. The new federal case is Perry Bonin, et al. v. Sabine River Authority of Texas et al., No. 17-cv-134, U.S. District Court for the Eastern District of Texas (Bonin Case). The plaintiffs moved to remand the case to state court, but the district court found that the case raises a substantial federal question and denied the motion to remand. Cleco Power, along with its co-defendants, filed a motion to dismiss on various grounds, primarily arguing that the plaintiffs’ claims are preempted because they infringe on FERC’s exclusive control of dam operations. The district court granted the motion to dismiss in part, declining to rule on some of the arguments raised by the defendants, and granted the plaintiffs leave to amend their complaint. The plaintiffs filed a Fifth Amended Complaint in March 2018. Cleco Power filed a new motion to dismiss the plaintiffs’ claims.

In March 2018, approximately 26 other individual plaintiffs filed a petition against Cleco Power and other defendants in Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. D180096-C. The action was filed in the 260th Judicial District Court for Orange County, Texas. The defendants removed the case to federal court in April 2018. The new federal case is Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. 18-cv-153, U.S. District Court for the Eastern District of Texas. The allegations are essentially identical to those in the Bonin Case. Also, in April 2018, Cleco Power filed a motion to dismiss on the same grounds that previously were successful in the Bonin Case. In July 2018, the district court entered an order consolidating the Addison Case with the Bonin Case. Management believes that both cases, as they relate to Cleco Power, have no merit. In August 2018, the Judge entered an order requiring the plaintiffs to file a more definitive statement to clarify the plaintiffs’ claims. In response thereto, the plaintiffs filed a Sixth Amended Petition in September 2018. Cleco Power filed a response in October 2018. All claims were dismissed against Cleco Power by ruling of the judge on March 18, 2019. The plaintiffs filed an appeal of the dismissal with the United States Court of Appeals for the Fifth Circuit. This case has been fully briefed, and an oral argument is set for the week of March 30, 2020.

Dispute with Saulsbury Industries

In October 2018, Cleco Power sued Saulsbury Industries, Inc., the former general contractor for the St. Mary Clean Energy Center project, seeking damages for Saulsbury Industries, Inc.’s failure to complete the St. Mary Clean Energy Center project on time and for costs incurred by Cleco Power in hiring a replacement general contractor. The action was filed in the 9th Judicial District Court for Rapides Parish, No. 263339. Saulsbury Industries, Inc. removed the case to the U.S. District Court for the Western District of Louisiana, on March 1, 2019.

In January 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC, in the U.S. District Court for the Western District of Louisiana. Saulsbury Industries, Inc. alleges that Cleco Power and Cabot Corporation caused the delays in the St. Mary Clean Energy Center project, resulting in significant impact to Saulsbury Industries, Inc.’s direct and indirect costs. On June 5, 2019, Cleco Power and Cabot Corporation each filed separate motions to dismiss. On October 24, 2019, the District Court denied Cleco’s motion as premature and ruled that Saulsbury Industries, Inc. had six weeks to conduct discovery on specified jurisdictional issues. The current procedural posture of the Western District of Louisiana case reflects a recognition by Cleco Power and Saulsbury Industries, Inc. that subject matter jurisdiction is lacking and that this action, in so far as it relates to Cleco Power and Saulsbury Industries, Inc., will not proceed in federal court.

On October 10, 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC in the 16th Judicial District Court for St. Mary Parish, No. 133910-A. Saulsbury Industries, Inc. alleged that Cleco Power and Cabot Corporation caused the delays in the St. Mary Clean Energy Center project, resulting in significant impact to Saulsbury Industries, Inc.’s direct and indirect costs. Saulsbury Industries, Inc. also seeks to enforce an alleged lien on the St. Mary Energy Center project. On December 9, 2019, Cleco moved to stay the case, arguing that the Rapides Parish suit should proceed. On February 14, 2020, the court granted Cleco’s motion.

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LPSC Audits

Fuel Audit

Generally, Cleco Power’s cost of fuel used for electric generation and the cost of purchased power are recovered through the LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. Recovery of FAC costs is subject to periodic fuel audits by the LPSC. The LPSC FAC General Order issued in November 1997, in Docket No. U-21497 provides that an audit of FAC filings will be performed at least every other year. In March 2018, Cleco Power received notice of an FAC audit from the LPSC for the period of January 2016, to December 2017. The total amount of fuel expense included in the audit was $536.2 million. In August 2018, the LPSC Staff issued its audit report which recommended no disallowance of fuel costs. On April 26, 2019, the report was approved by the LPSC. Cleco Power has FAC filings for January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. Historically, the disallowances have not been material. If a disallowance of fuel cost is ordered resulting in a refund, any such refund could have a material adverse effect on the results of operations, financial condition or cash flows of the Registrants.

Environmental Audit

In 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides Cleco Power an EAC to recover from its customers certain costs of environmental compliance. 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. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. In May 2018, Cleco Power received notice of an EAC audit from the LPSC for the period of January 2016 to December 2017. The total amount of environmental expense included in this audit was $30.7 million. On July 16, 2019, the LPSC Staff issued its audit report, which recommended no disallowance of environmental costs. On September 11, 2019, the report was approved by the LPSC. Cleco Power has EAC filings for January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. Historically, the disallowances have not been material. If a disallowance of environmental cost is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.

Cleco Power incurs environmental compliance expenses for reagents associated with the compliance standards of MATS. In June 2015, the U.S. Supreme Court remanded the MATS rule to the D.C. Circuit Court of Appeals. In December 2015, the D.C. Circuit Court of Appeals remanded the rule to the EPA; however, the D.C. Circuit Court of Appeals did not vacate this rule. In April 2016, the EPA released a final supplemental finding that, even considering costs, it is appropriate and necessary to regulate hazardous air pollutants. By the June 2016 deadline, six petitions were filed with the U.S. Court of Appeals for the D.C. Circuit Court of Appeals for review of the EPA’s findings. At the request of the EPA, in April 2017, the court issued an order holding the cases in abeyance pending the EPA’s review of its supplemental finding. These expenses are also eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC.

FERC Audit

Generally, Cleco Power records wholesale transmission revenue through approved formula rates. Attachment O of the MISO tariff and certain grandfathered agreements. The calculation of the rate formulas, as well as FERC accounting and reporting requirements, are subject to periodic audits by FERC. In March 2018, the Division of Audits and Accounting, within the Office of Enforcement of FERC, initiated an audit of Cleco Power for the period of January 1, 2014, through June 30, 2019. On September 27, 2019, Cleco Power received the final audit report, which indicated 12 findings of noncompliance with a combination of FERC accounting and reporting requirements and computation of revenue requirements along with 59 recommendations associated with the audit period. Cleco Power submitted a plan for implementing the audit recommendations on October 28, 2019. Cleco Power also submitted the refund analysis on November 7, 2019, which resulted in an estimated refund of $3.5 million related to the FERC audit findings, pending final assessment by the FERC Division of Audits and

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Accounting. This amount was recorded in Provision for rate refund on Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2019. Cleco Power anticipates this amount to be refunded to its wholesale transmission customers as a reduction in Attachment O and grandfathered agreement rates over 12 months beginning June 1, 2020.

Transmission ROE

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. The complaints sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 6.68%.

The complaints covered the period December 2013 through May 2016. In June 2016, an administrative law judge issued an initial decision in the second rate case docket recommending a 9.70% base ROE. In September 2016, FERC issued a Final Order in response to the first complaint establishing a 10.32% ROE. However, on November 21, 2019, FERC voted to adopt a new methodology for evaluating base ROE for public utilities under the Federal Power Act. In addition, FERC set the MISO transmission owners’ region-wide base ROE at 9.88% for the refund period covered in the first complaint and going forward. The draft FERC order further found that complainants in the second complaint proceeding failed to show that the 9.88% base ROE was unjust and unreasonable and thus dismissed the second complaint. Cleco Power is unable to determine when a final FERC Order will be issued. As of December 31, 2019, Cleco Power had $1.0 million accrued for the change in the ROE.

In November 2014, the MISO transmission owners committee, of which Cleco is a member, filed a request with FERC for an incentive to increase the new ROE by 50 basis points for RTO participation as allowed by the MISO tariff. In January 2015, FERC granted the request. Beginning January 1, 2020, the collection of the adder is being included in MISO’s transmission rates for a total ROE of 10.38%.

South Central Generating

In 2017, Louisiana Generating received insurance settlement proceeds for costs incurred to resolve a lawsuit which was brought by the EPA and the LDEQ against Louisiana Generating related to Big Cajun II, Unit 3. Entergy Gulf States, as co-owner of Big Cajun II, Unit 3, is expected to be allocated a portion of the insurance settlement proceeds. Any amount allocated to Entergy Gulf States will be determined by ongoing litigation and negotiations. South Central Generating estimated this amount to be $10.0 million. As part of the Cleco Cajun Transaction, Cleco Cajun assumed the $10.0 million contingent liability and NRG Energy indemnified Cleco for losses associated with this litigation matter. As a result, Cleco also recorded a $10.0 million indemnification asset, which was included in the purchase price allocation.

Prior to the Cleco Cajun Transaction, South Central Generating was involved in various litigation matters, including environmental and contract proceedings, before various courts regarding matters arising out of the ordinary course of business. Management is unable to estimate any potential losses that Cleco Cajun may ultimately be responsible for with respect to any one of these matters. As part of the Cleco Cajun Transaction, NRG Energy indemnified Cleco for losses as of the closing date associated with matters that existed as of the closing date, including pending litigation.

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 may be in excess of amounts currently accrued. Management regularly analyzes current information and, as of December 31, 2019, believes the probable and reasonably estimable liabilities based on the eventual disposition of these matters is $5.0 million and has accrued this amount.

Off-Balance Sheet Commitments and Guarantees

Cleco Holdings 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 Holdings’ subsidiaries and equity investees (affiliates). Cleco Holdings and Cleco Power have also agreed to contractual terms that require the Registrants to pay third parties if certain triggering events occur. These contractual terms generally are defined as guarantees.

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Cleco Holdings 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 Holdings had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco and Cleco Power’s Consolidated Balance Sheets because management has determined that Cleco and Cleco Power’s affiliates are able to perform the obligations under their contracts and that it is not probable that payments by Cleco or Cleco Power will be required.

Cleco Holdings provided guarantees and indemnities to Entergy Louisiana and Entergy Gulf States as a result of the sale of the Perryville generation facility in 2005. The remaining indemnifications relate to environmental matters that may have been present prior to closing. These remaining indemnifications have no time limitations. The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million. Management does not expect to be required to pay Entergy Louisiana and Entergy Gulf States under these guarantees.

On behalf of Acadia, Cleco Holdings provided guarantees and indemnifications as a result of the sales of Acadia Unit 1 to Cleco Power and Acadia Unit 2 to Entergy Louisiana in 2010 and 2011, respectively. The remaining indemnifications relate to the fundamental organizational structure of Acadia. These remaining indemnifications have no time limitations or maximum potential future payments. Management does not expect to be required to pay Cleco Power or Entergy Louisiana under these guarantees.

Cleco Holdings provided indemnifications to Cleco Power as a result of the transfer of Coughlin to Cleco Power in March 2014. Cleco Power also provided indemnifications to Cleco Holdings and Evangeline as a result of the transfer of Coughlin to Cleco Power. The maximum amount of the potential payment to Cleco Power, Cleco Holdings, and Evangeline for their respective indemnifications is $40.0 million, except for indemnifications relating to the fundamental organizational structure of each respective entity, of which the maximum amount is $400.0 million. Management does not expect to be required to make any payments under these indemnifications.

As part of the Amended Lignite Mining Agreement, Cleco Power and SWEPCO, joint owners of Dolet Hills Power Station, have agreed to pay the loan and lease principal obligations of the lignite miner, DHLC, when due if DHLC 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 future invoices for lignite delivered. The maximum projected payment by Cleco Power under this guarantee is estimated to be $86.4 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 is not expected to terminate pursuant to its terms until 2036 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 this guarantee.

At December 31, 2019, Cleco Holdings had a $34.5 million letter of credit to MISO pursuant to energy market requirements related to Cleco Cajun’s participation in MISO. The letter of credit automatically renews each year and has no impact on the Cleco Holdings’ credit facility.

Generally, neither Cleco Holdings nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations. There are no assets held as collateral for third parties that either Cleco Holdings or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees or indemnification obligations.

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Long-Term Purchase Obligations

Cleco Holdings had no unconditional long-term purchase obligations at December 31, 2019. Cleco Power and Cleco Cajun have several unconditional long-term purchase obligations primarily related to the purchase of petroleum coke, limestone, energy delivery facilities, information technology outsourcing, natural gas storage, network monitoring, and software maintenance. The aggregate amount of payments required under such obligations at December 31, 2019, is as follows:

(THOUSANDS)	CLECO POWER	CLECO
For the year ending Dec. 31,
2020	$28,741	$89,490
2021	29,832	35,986
2022	18,025	19,311
2023	7,751	8,782
2024	7,740	9,829
Thereafter	13,242	14,474
Total long-term purchase obligations	$105,331	$177,872

Cleco’s payments under these agreements for the years ended December 31, 2019, 2018, and 2017 were $94.8 million, $70.5 million, and $47.0 million, respectively. Cleco Power’s payments under these agreements for the years ended December 31, 2019, 2018, and 2017 were $35.3 million, $60.7 million, and $44.2 million, respectively.

Other

Cleco has accrued for liabilities related to third parties, employee medical benefits, and AROs. For more information on AROs, see Note 2 — “Summary of Significant Accounting Policies — AROs” and Note 6 — “Regulatory Assets and Liabilities — AROs.”

Risks and Uncertainties

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

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.

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 and Cleco’s financial condition could be materially adversely affected.

Cleco Power and Cleco Cajun are participants in the MISO market. Energy prices in the MISO market are based on LMP, which includes a component directly related to congestion on the transmission system. Pricing zones with greater transmission congestion may have higher LMPs. Physical transmission constraints present in the MISO market could increase energy costs within pricing zones. Cleco Power and Cleco Cajun use FTRs to mitigate transmission congestion price risks. Changes to anticipated transmission paths may result in an unexpected increase in energy costs.

On March 1, 2019, Cleco Power began to operate Dolet Hills Power Station from June through September of each year; however, Dolet Hills Power Station will continue to be available to operate in other months, as needed. Cleco Power will continue to evaluate the cost of operating the Dolet Hills Power Station compared with other alternatives and decide the best course of action for the Dolet Hills Power Station within the LPSC regulatory requirements and recovery mechanism. In January 2020, Cleco Power’s joint owner in Dolet Hills Power Station unilaterally entered into a settlement with the Arkansas Public Service Commission to seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. While this settlement does not bind Cleco Power to agree to retire the Dolet Hills Power Station by 2026, management is unable to predict the effects an early closure agreement would have on the recovery value of the plant. In addition, Cleco Power and its joint owner are in discussions around their joint venture in the Oxbow mine and their obligations under the associated mining agreement with Dolet Hills Lignite Company. Any early closure of the mine could result in increased costs billed through fuel, which management currently believes are recoverable.

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Note 16 — 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, tax, and auditing; human resources; public 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.

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.

All charges and revenues from consolidated affiliates were eliminated in Cleco’s Consolidated Statements of Income for the years ending December 31, 2019, 2018, and 2017.

At December 31, 2019, Cleco Holdings had accounts payable of $33.8 million due from Cleco Group primarily for affiliate settlement of taxes payable. At December 31, 2018, Cleco Holdings had no accounts payable due to Cleco Group.

For the year ended December 31, 2019, Cleco Holdings made no distribution payments to Cleco Group. For the year ended December 31, 2018, Cleco Holdings made $71.4 million of distribution payments to Cleco Group.

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. Support Group provides joint and common administrative support services in the areas of information technology; finance, cash management, accounting, tax, and auditing; human resources; public 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.

With the exception of Support Group, affiliates 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)	2019	2018	2017
Support Group
Other operations and maintenance	$73,090	$56,669	$50,572
Taxes other than income taxes	$(73)	$6	$(13)
Other expense	$64	$290	$255
Cleco Holdings
Other expense	$—	$1,007	$361

The majority of the services provided by Cleco Power relates to the lease of office space to Support Group and transmission services to Cleco Cajun. 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.

F-79

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)	2019	2018	2017
Other operations revenue
Cleco Cajun	$7,471	$—	$—
Affiliate revenue
Support Group	3,088	874	851
Cleco Cajun	37	—	—
Other income
Cleco Holdings	149	1,092	494
Total	$10,745	$1,966	$1,345

Cleco Power had the following affiliate receivable and payable balances associated with the service agreements:

	AT DEC. 31,
	2019		2018
(THOUSANDS)	ACCOUNTS RECEIVABLE	ACCOUNTS PAYABLE	ACCOUNTS RECEIVABLE	ACCOUNTS PAYABLE
Cleco Holdings	$10,351	$194	$699	$88
Support Group	3,172	13,890	2,619	7,755
Cleco Cajun	958	39	—	—
Total	$14,481	$14,123	$3,318	$7,843

During 2019, 2018, and 2017, Cleco Power made $20.0 million, $121.4 million, and $135.0 million, respectively, of distribution payments to Cleco Holdings. Cleco Power received no equity contributions from Cleco Holdings in 2019, 2018, and 2017.

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 Power’s affiliates is transferred with a like amount of assets to Cleco Power monthly. The following table shows the expense of the pension plan related to Cleco Power’s affiliates for the years ended 2019 and 2018:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018
Support Group	$1,316	$1,963
Cleco Cajun	$239	$—

Note 17 — Intangible Assets, Intangible Liabilities, and Goodwill

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 be fully amortized in 2020. The intangible asset’s expected amortization expense is based on the estimated collections from Cleco Power’s customers. At the end of its life, the asset will have no residual value. Cleco Katrina/Rita records amortization expense based on actual collections. At the date of the 2016 Merger, the gross balance of the Cleco Katrina/Rita intangible asset for Cleco was adjusted to be net of accumulated amortization, as no accumulated amortization existed at such date.

As a result of the 2016 Merger, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the valuation of the Cleco trade name and long-term wholesale power supply agreements. At the end of their life, these intangible assets will have no residual value. The trade name intangible asset is being amortized over its estimated economic useful life of 20 years. The intangible assets related to the power supply agreements are amortized over the remaining life of each applicable contract ranging between 3 years and 15 years and the amortization is included in Electric operations on Cleco’s Consolidated Statements of Income.

As a result of the Cleco Cajun Transaction, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the difference between the contract and market price of acquired long-term wholesale power

F-80

agreements. The fair value of intangible assets of $98.9 million and intangible liabilities of $14.2 million was reflected in the purchase price allocation. At the end of their life, these intangible assets and liabilities will have no residual value. These intangibles are amortized over the remaining life of each applicable contract ranging between two years and eight years. The amortization is included in Electric operations on Cleco’s Consolidated Statement of Income.

As part of the Cleco Cajun Transaction, Cleco assumed an LTSA for maintenance services related to the Cottonwood Plant. An intangible liability of $24.1 million was reflected in the purchase price allocation and is being amortized using the straight-line method over the estimated remaining life of the LTSA of seven years. The amortization is included as a reduction to the LTSA prepayments on Cleco’s Consolidated Balance Sheet. For more information on the fair value adjustments of intangible assets and liabilities related to the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”

The following tables present Cleco and Cleco Power’s amortization of intangible assets and liabilities:

Cleco
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Intangible assets
Cleco Katrina/Rita right to bill and collect storm recover charges	$20,576	$20,608	$16,772
Trade name	$255	$255	$255
Power supply agreements	$24,273	$9,680	$10,757
Intangible liabilities
LTSA	$3,194	$—	$—
Power supply agreements	$3,234	$—	$—

No impairments for intangibles in the table above for 2019, 2018, and 2017.

Cleco Power
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Cleco Katrina/Rita right to bill and collect storm recovery charges	$20,576	$20,608	$16,772

The following tables summarize the balances for intangible assets and liabilities subject to amortization for Cleco and Cleco Power:

Cleco
	AT DEC. 31,
(THOUSANDS)	2019	2018
Intangible assets
Cleco Katrina/Rita right to bill and collect storm recovery charges	$70,594	$70,594
Trade name	5,100	5,100
Power supply agreements	184,004	85,104
Total intangible assets carrying amount	259,698	160,798
Intangible liabilities
LTSA	24,100	—
Power supply agreements	14,200	—
Total intangible liabilities carrying amount	38,300	—
Net intangible assets carrying amount	221,398	160,798
Accumulated amortization	(115,167)	(76,491)
Net intangible assets subject to amortization	$106,231	$84,307

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Cleco Power
	AT DEC. 31,
(THOUSANDS)	2019	2018
Cleco Katrina/Rita right to bill and collect storm recovery charges	$177,537	$177,537
Accumulated amortization	(177,020)	(156,444)
Net intangible assets subject to amortization	$517	$21,093

The following table summarizes the amortization expense related to intangible assets and liabilities expected to be recognized in Cleco’s Consolidated Statements of Income:

Cleco
(THOUSANDS)	INTANGIBLE ASSETS	INTANGIBLE LIABILITIES
For the year ending Dec. 31,
2020	$26,372	$(7,012)
2021	$25,855	$(5,862)
2022	$25,855	$(5,041)
2023	$25,855	$(5,041)
2024	$29,459	$(5,041)
Thereafter	$4,707	$(3,875)

Cleco Power expects to recognize $0.5 million of amortization expense related to intangible assets on its Consolidated Statement of Income in 2020.

Goodwill

In connection with the completion of the 2016 Merger, Cleco recognized goodwill of $1.49 billion. Management assigned the recognized goodwill to the Cleco Power reporting segment. Goodwill is required to be tested for impairment at the reporting segment level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting segment below its carrying value. Application of the goodwill impairment test requires significant judgments, including the identification of reporting segments, assignments of assets and liabilities to reporting segments, assignment of goodwill to reporting segments, and the determination of the fair value of the reporting segments.

Cleco conducted its 2019 annual impairment test using an August 1, 2019, measurement date. The fair value of the Cleco Power reporting segment was estimated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables within the utility and energy industries. Significant assumptions used in these fair value estimates include estimation of future cash flows related to capital expenditures, long-term rate of growth, and weighted-average cost of capital or discount rate. Changes in these assumptions could materially affect the determination of fair value and goodwill impairment at Cleco Power. Based on the tests performed, management has determined that there was no impairment of Cleco Power’s goodwill for 2019.

Management estimated the fair value of Cleco Power’s equity to be $3.97 billion at the August 1, 2019, measurement date. The carrying value of Cleco Power’s equity was approximately $3.40 billion with the excess of the fair value over the carrying value representing 16.8% or $570.4 million. There were no accumulated impairment charges.

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Note 18 — Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss are summarized in the following tables for Cleco and Cleco Power. All amounts are reported net of income taxes. Amounts in parentheses indicate debits.

Cleco
(THOUSANDS)	POSTRETIREMENT BENEFIT NET GAIN (LOSS)
Balances, Dec. 31, 2016	$1,500
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year	(3,898)
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net gain	(523)
Balances, Dec. 31, 2017	$(2,921)
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year	3,681
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net loss	1,615
Reclassification of effect of tax rate change	(589)
Balances, Dec. 31, 2018	$1,786
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year	(18,877)
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net loss	(422)
Balances, Dec. 31, 2019	$(17,513)

Cleco Power
(THOUSANDS)	POSTRETIREMENT BENEFIT NET (LOSS) GAIN	NET (LOSS) GAIN ON CASH FLOW HEDGES	TOTAL AOCI
Balances, Dec. 31, 2016	$(7,905)	$(5,517)	$(13,422)
Other comprehensive loss before reclassifications
Postretirement benefit adjustments incurred during the year	(948)	—	(948)
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss	476	—	476
Reclassification of net loss to interest charges	—	211	211
Balances, Dec. 31, 2017	$(8,377)	$(5,306)	$(13,683)
Other comprehensive loss before reclassifications
Postretirement benefit adjustments incurred during the year	954	—	954
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss	1,789	—	1,789
Reclassification of net loss to interest charges	—	254	254
Reclassification of effect of tax rate change	(1,426)	(1,070)	(2,496)
Balances, Dec. 31, 2018	$(7,060)	$(6,122)	$(13,182)
Other comprehensive loss before reclassifications
Postretirement benefit adjustments incurred during the year	(10,344)	—	(10,344)
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss	687	—	687
Reclassification of net gain to interest charges	—	254	254
Balances, Dec. 31, 2019	$(16,717)	$(5,868)	$(22,585)

F-83

Note 19 — Miscellaneous Financial Information (Unaudited)

Cleco

Quarterly information for Cleco for 2019 and 2018 is shown in the following tables:

				2019
(THOUSANDS)	1ST QUARTER	2ND QUARTER	3RD QUARTER	4TH QUARTER
Operating revenue, net	$344,186	$397,873	$487,971	$409,575
Operating income	$50,586	$87,196	$101,539	$75,573
Net income	$20,557	$44,746	$55,565	$31,797

				2018
(THOUSANDS)	1ST QUARTER	2ND QUARTER	3RD QUARTER	4TH QUARTER
Operating revenue, net	$276,760	$299,261	$358,256	$296,767
Operating income	$44,734	$63,709	$86,110	$50,004
Net income	$10,861	$25,839	$47,360	$10,377
Distributions to member	$19,500	$20,400	$20,600	$10,850

Cleco Power

Quarterly information for Cleco Power for 2019 and 2018 is shown in the following tables:

				2019
(THOUSANDS)	1ST QUARTER	2ND QUARTER	3RD QUARTER	4TH QUARTER
Operating revenue, net	$268,745	$272,972	$344,977	$281,676
Operating income	$44,905	$75,446	$78,132	$49,985
Net income	$26,712	$49,356	$51,527	$20,667
Distributions to member	$—	$—	$—	$20,000

				2018
(THOUSANDS)	1ST QUARTER	2ND QUARTER	3RD QUARTER	4TH QUARTER
Operating revenue, net	$279,387	$301,901	$360,899	$299,409
Operating income	$50,521	$72,602	$96,063	$59,786
Net income	$26,004	$43,020	$63,336	$29,897
Distributions to member	$28,000	$43,000	$50,400	$—

F-84

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)

Condensed Statements of Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating expenses
Administrative and general	$3,263	$1,269	$602
Merger transaction costs	7,803	19,514	5,152
Other operating expense	130	318	260
Total operating expenses	11,196	21,101	6,014
Operating loss	(11,196)	(21,101)	(6,014)
Equity income from subsidiaries, net of tax	205,187)	149,543	170,706
Interest, net	(70,252)	(54,635)	(53,684)
Other income (expense), net	8,568	(1,687)	3,978
Income before income taxes	132,307	72,120	114,986
Federal and state income tax benefit	(20,358)	(22,317)	(23,094)
Net income	$152,665	$94,437	$138,080

The accompanying notes are an integral part of the condensed financial statements.

F-85

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)

Condensed Statements of Comprehensive Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Net Income	$152,665	$94,437	$138,080
Other comprehensive (loss) income, net of tax Postretirement benefits (loss) gain (net of tax benefit of $6,808, tax expense of $1,868, and tax benefit of $2,764, respectively)	(19,299)	(5,296)	(4,421)
Total other comprehensive (loss) income, net of tax	(19,299)	(5,296)	(4,421)
Comprehensive income, net of tax	$133,366	$99,733	$133,659

The accompanying notes are an integral part of the condensed financial statements.

F-86

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)

Condensed Balance Sheets

	AT DEC. 31,
(THOUSANDS)	2019	2018
Assets
Current assets
Cash and cash equivalents	$15,008	$76,938
Accounts receivable - affiliate	14,231	8,374
Other accounts receivable	2,650	2,755
Taxes receivable, net	6,726	7,046
Cash surrender value of trust-owned life insurance policies	68,523	59,894
Total current assets	107,138	155,007
Equity investment in subsidiaries	4,150,953	3,247,809
Accumulated deferred federal and state income taxes, net	127,655	101,015
Other deferred charges	1,831	4,532
Total assets	4,387,577	3,508,363
Liabilities and member’s equity
Liabilities
Current liabilities
Long-term debt due within one year	$63,300	$—
Accounts payable	1,448	1,322
Accounts payable - affiliate	47,184	18,047
Interest accrued	11,005	7,576
Deferred compensation	12,115	10,753
Other current liabilities	274	273
Total current liabilities	135,326	37,971
Postretirement benefit obligations	4,481	3,894
Long-term debt, net	1,604,764	1,341,758
Total liabilities	1,744,571	1,383,623
Commitments and contingencies (Note 6)
Member’s equity	2,643,006	2,124,740
Total liabilities and member’s equity	$4,387,577	$3,508,363

The accompanying notes are an integral part of the condensed financial statements.

F-87

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)

Condensed Statements of Cash Flows

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Operating activities
Net cash provided by operating activities	$189,644	$97,614	$124,817
Investing activities
Return of equity investment in tax credit fund	1,625	2,775	7,502
Contribution to subsidiary	(962,170)	(1,250)	—
Other investing	—	442	(630)
Net cash (used in) provided by investing activities	(960,545)	1,967	6,872
Financing activities
Draws on credit facility	75,000	—	73,000
Payments on credit facility	(75,000)	—	(73,000)
Issuance of long-term debt	700,000	—	—
Repayment of long-term debt	(370,000)	—	—
Payment of financing costs	(5,929)	(25)	(269)
Contribution from member	384,900	—	—
Distributions to member	—	(71,350)	(84,065)
Net cash provided by (used in) financing activities	708,971	(71,375)	(84,334)
Net (decrease) increase in cash and cash equivalents	(61,930)	28,206	47,355
Cash and cash equivalents at beginning of period	76,938	48,732	1,377
Cash and cash equivalents at end of period	$15,008	$76,938	$48,732
Supplementary cash flow information
Interest paid, net of amount capitalized	$56,768	$53,798	$52,026
Income taxes (refunded) paid, net	$(19)	$2	$(6)
Supplementary non-cash investing and financing activity
Non-cash contribution to subsidiary, net of tax	$—	$3,865	$—

The accompanying notes are an integral part of the condensed financial statements.

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CLECO HOLDINGS (Parent Company Only) Notes to 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 Holdings, 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, 2019, Cleco Holdings’ restricted net assets of consolidated subsidiaries were $1.26 billion and exceeded 25% of its total consolidated net assets.

Cleco Holdings’ major, first-tier subsidiaries are Cleco Power and Cleco Cajun. Cleco Power contains the LPSC-jurisdictional generation, transmission, and distribution electric utility operations serving its retail and wholesale customers. Upon completion of the Cleco Cajun Transaction, Cleco Cajun became a major, first tier subsidiary. Cleco Cajun is an unregulated electric utility company that owns generation and transmission assets and supplies wholesale power and capacity to its customers. For more information about the Cleco Cajun Transaction, see “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 2 — Business Combinations.”

The accompanying financial statements have been prepared to present the results of operations, financial condition, and cash flows of Cleco Holdings on a stand-alone basis as a holding company. Investments in subsidiaries and other investees are presented using the equity method. These financial statements should be read in conjunction with Cleco’s consolidated financial statements.

Note 2 — Debt

At December 31, 2019, and 2018, Cleco Holdings had no short-term debt outstanding.

At December 31, 2019, Cleco Holding’s long-term debt outstanding was $1.67 billion, of which $63.3 million was due within one year. The amount due within one year represents principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC.

In connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings borrowed $300.0 million under a new bridge loan agreement and $100.0 million under a new term loan agreement. Both loan agreements are variable rate debt and have a three-year term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings to maintain (i) a debt to capital ratio (as defined in the applicable agreement) below 65% and (ii) a rating applicable to Cleco Holdings’ senior debt rating (as defined in the applicable agreement). On September 11, 2019, Cleco Holdings completed the private placement of $300.0 million aggregate principal amount of its 3.375% senior notes due September 15, 2029. The proceeds from the issuance were used to repay the remaining amounts due under the $300.0 million bridge loan agreement and to repay a portion of the $100.0 million term loan agreement. The senior notes are governed by an indenture entered into between Cleco Holdings and a trustee. The indenture contains certain covenants that restrict Cleco Holdings’ ability to merge, consolidate, transfer, or lease all or substantially all of its assets or create or incur certain liens.

Upon approval of the Cleco Cajun Transaction, commitments were made to the LPSC by Cleco Holdings, including repayment of $400.0 million of Cleco Holdings’ debt by December 31, 2024. As of December 31, 2019, Cleco Holdings was in compliance with these commitments. The cumulative minimum principal amounts committed to be repaid for each year through 2024 are as follows:

(THOUSANDS)
For the year ending Dec. 31,
2019	$66,700
2020	$133,300
2021	$200,000
2022	$267,700
2023	$333,300
2024	$400,000

In connection with the Cleco Cajun Transaction, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total credit facility of $175.0 million. All other terms remained the same.

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The principal amounts payable under long-term debt agreements for each year through 2024 and thereafter are as follows:

AMOUNTS PAYABLE UNDER LONG-TERM DEBT ARRANGEMENTS	(THOUSANDS)
For the year ending Dec. 31,
2020	$—
2021	$330,000
2022	$—
2023	$165,000
2024	$—
Thereafter	$1,185,000

Note 3 — Cash Distributions and Equity Contributions

Some provisions in Cleco Power’s debt instruments restrict the amount of equity available for distribution to Cleco Holdings by Cleco Power by requiring Cleco Power’s total indebtedness to be less than or equal to 65% of total capitalization. In addition, the 2016 Merger Commitments provide for limitations on the amount of distributions that may be paid from Cleco Power to Cleco Holdings, depending on Cleco Power’s common equity ratio and its corporate credit ratings.

The following table summarizes the cash distributions Cleco Holdings received from affiliates during 2019, 2018, and 2017:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Cleco Power	$20,000	$121,400	$135,000
Cleco Cajun	205,000	—	—
Perryville	—	225	6,850
Attala	—	217	7,160
Total	$225,000	$121,842	$149,010

During both years ended December 31, 2019, and 2017, Cleco Holdings made no non-cash equity contributions to affiliates. During the year ended December 31, 2018, Cleco Holdings made $1.8 million and $2.1 million in non-cash equity contributions to Perryville and Attala, respectively.

During the year ended December 31, 2019, Cleco Holdings made $962.2 million of contributions to Cleco Cajun to finance the Cleco Cajun Transaction. During the year ended December 31, 2018, Cleco Holdings made $1.3 million of contributions to Cleco Cajun. During the year ended December 31, 2017, Cleco Holdings made no cash contributions to affiliates.

During the year ended December 31, 2019, Cleco Holdings received $384.9 million equity contributions from Cleco Group. During both years ended December 31, 2018, and 2017, Cleco Holdings received no equity contributions from Cleco Group.

During the year ended December 31, 2019, Cleco Holdings made no distribution payments to Cleco Group. During the years ended December 31, 2018, and 2017, Cleco Holdings made $71.4 million and $84.1 million, respectively, of distribution payments to Cleco Group.

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Note 4 — Income Taxes

Cleco Holdings’ (Parent Company Only) Condensed Statements of Income reflect income tax expense (benefit) for the following line items:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2019	2018	2017
Federal and state income tax benefit	$(20,358)	$(22,317)	$(23,094)
Equity income from subsidiaries - federal and state income tax expense	$63,523	$51,699	$30,173

For information regarding the TCJA, see “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 11 — Income Taxes — TCJA.”

Note 5 — Commitments and Contingencies

For information regarding commitments and contingencies related to Cleco Holdings, see “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees.”

F-91

CLECO	SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD	ADDITIONS	DEDUCTIONS	BALANCE AT END OF PERIOD(1)
Allowance for Uncollectible Accounts
Year Ended Dec. 31, 2019	$814	$2,323	$132	$3,005
Year Ended Dec. 31, 2018	$1,457	$977	$1,620	$814
Year Ended Dec. 31, 2017	$7,199	$4,179	$9,921	$1,457

(1)
Deducted in the consolidated balance sheet

(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD	ADDITIONS	DEDUCTIONS	BALANCE AT END OF PERIOD(1)
Unrestricted Storm Reserve
Year Ended Dec. 31, 2019	$3,672	$4,000	$6,572	$1,100
Year Ended Dec. 31, 2018	$4,186	$—	$514	$3,672
Year Ended Dec. 31, 2017	$2,607	$4,000	$2,421	$4,186
Restricted Storm Reserve
Year Ended Dec. 31, 2019	$15,485	$800	$4,000	$12,285
Year Ended Dec. 31, 2018	$14,469	$1,016	$—	$15,485
Year Ended Dec. 31, 2017	$17,385	$1,084	$4,000	$14,469

(1)
Included in the consolidated balance sheet

CLECO POWER	SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD	ADDITIONS	DEDUCTIONS	BALANCE AT END OF PERIOD(1)
Allowance for Uncollectible Accounts
Year Ended Dec. 31, 2019	$814	$2,323	$132	$3,005
Year Ended Dec. 31, 2018	$1,457	$977	$1,620	$814
Year Ended Dec. 31, 2017	$7,199	$4,179	$9,921	$1,457

(1)
Deducted in the consolidated balance sheet

(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD	ADDITIONS	DEDUCTIONS	BALANCE AT END OF PERIOD(1)
Unrestricted Storm Reserve
Year Ended Dec. 31, 2019	$3,672	$4,000	$6,572	$1,100
Year Ended Dec. 31, 2018	$4,186	$—	$514	$3,672
Year Ended Dec. 31, 2017	$2,607	$4,000	$2,421	$4,186
Restricted Storm Reserve
Year Ended Dec. 31, 2019	$15,485	$800	$4,000	$12,285
Year Ended Dec. 31, 2018	$14,469	$1,016	$—	$15,485
Year Ended Dec. 31, 2017	$17,385	$1,084	$4,000	$14,469

(1)
Included in the consolidated balance sheet

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Index to Unaudited Interim Financial Statements

Condensed Consolidated Financial Statements (Unaudited)
Financial Statements of Cleco
Condensed Consolidated Statements of Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-94
Condensed Consolidated Statements of Comprehensive Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-95
Condensed Consolidated Balance Sheets (Unaudited) at March 31, 2020, and at December 31, 2019	F-96
Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2020, and 2019	F-98
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited) for the three months ended March 31, 2020, and 2019	F-99
Financial Statements of Cleco Power
Condensed Consolidated Statements of Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-100
Condensed Consolidated Statements of Comprehensive Income (Unaudited) for the three months ended March 31, 2020, and 2019	F-101
Condensed Consolidated Balance Sheets (Unaudited) at March 31, 2020, and at December 31, 2019	F-102
Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended March 31, 2020, and 2019	F-104
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited) for the three months ended March 31, 2020, and 2019	F-106
Notes to the Unaudited Interim Financial Statements	F-108

F-93

Cleco

These unaudited condensed consolidated financial statements should be read in conjunction with Cleco’s Consolidated Financial Statements and Notes included in “Financial Statements and Supplementary Data — Consolidated Financial Statements (Audited) of Cleco.” For more information on the basis of presentation, see “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies — Basis of Presentation.”

CLECO
Condensed Consolidated Statements of Income (Unaudited)

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Operating revenue
Electric operations	$311,157	$312,949
Other operations	44,908	39,397
Gross operating revenue	356,065	352,346
Electric customer credits	(8,493)	(8,160)
Operating revenue, net	347,572	344,186
Operating expenses
Fuel used for electric generation	76,637	104,054
Purchased power	66,320	60,099
Other operations and maintenance	74,766	60,731
Depreciation and amortization	55,873	49,856
Taxes other than income taxes	16,536	13,870
Merger transaction and commitment costs	2,775	4,990
Total operating expenses	292,907	293,600
Operating income	54,665	50,586
Interest income	1,157	1,491
Allowance for equity funds used during construction	(74)	5,688
Other (expense) income, net	(12,709)	2,777
Interest charges
Interest charges, net	35,328	36,115
Allowance for borrowed funds used during construction	(179)	(2,116)
Total interest charges	35,149	33,999
Income before income taxes	7,890	26,543
Federal and state income tax expense	1,562	5,986
Net income	$6,328	$20,557

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-94

CLECO
Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Net income	$6,328	$20,557
Other comprehensive income (loss), net of tax
Postretirement benefits gain (loss) (net of tax expense of $146 in 2020 and tax benefit of $47 in 2019)	414	(135)
Total other comprehensive income (loss), net of tax	414	(135)
Comprehensive income, net of tax	$6,742	$20,422

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-95

CLECO
Condensed Consolidated Balance Sheets (Unaudited)

(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Assets
Current assets
Cash and cash equivalents	$350,231	$116,292
Restricted cash and cash equivalents	4,054	11,100
Customer accounts receivable (less allowance for credit losses of $2,123 in 2020 and $3,005 in 2019)	71,796	83,591
Other accounts receivable	29,485	35,731
Unbilled revenue	30,434	33,207
Fuel inventory, at average cost	109,232	83,061
Materials and supplies, at average cost	120,646	118,858
Energy risk management assets	1,992	7,023
Accumulated deferred fuel	16,353	22,910
Cash surrender value of company-/trust-owned life insurance policies	75,411	86,096
Prepayments	6,518	7,711
Regulatory assets	18,643	19,807
Other current assets	12,356	12,688
Total current assets	847,151	638,075
Property, plant, and equipment
Property, plant, and equipment	5,038,241	4,982,255
Accumulated depreciation	(503,554)	(454,874)
Net property, plant, and equipment	4,534,687	4,527,381
Construction work in progress	121,575	117,630
Total property, plant, and equipment, net	4,656,262	4,645,011
Equity investment in investee	17,072	17,072
Goodwill	1,490,797	1,490,797
Prepayments	27,794	25,949
Operating lease right of use assets	28,447	28,791
Restricted cash and cash equivalents	9,899	15,203
Note receivable	15,031	15,198
Regulatory assets	415,226	422,431
Intangible assets	131,122	138,103
Other deferred charges	37,394	39,668
Total assets	$7,676,195	$7,476,298

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-96

(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Liabilities and member’s equity
Liabilities
Current liabilities
Short-term debt	$238,000	$—
Long-term debt and finance leases due within one year	63,932	125,986
Accounts payable	104,091	158,863
Accounts payable - affiliate	33,780	33,780
Customer deposits	59,192	58,289
Provision for rate refund	29,735	38,903
Taxes payable, net	23,902	8,931
Interest accrued	41,731	19,001
Energy risk management liabilities	9,697	4,113
Regulatory liabilities - other	3,910	6,675
Deferred compensation	9,371	12,115
Other current liabilities	45,699	44,683
Total current liabilities	663,040	511,339
Long-term liabilities and deferred credits
Accumulated deferred federal and state income taxes, net	655,027	657,058
Postretirement benefit obligations	283,830	283,075
Regulatory liabilities - deferred taxes, net	146,225	146,948
Restricted storm reserve	8,324	12,285
Deferred lease revenue	47,561	49,862
Intangible liabilities	30,119	31,872
Asset retirement obligations	23,489	23,173
Operating lease liabilities	25,119	25,779
Other deferred credits	30,474	27,222
Total long-term liabilities and deferred credits	1,250,168	1,257,274
Long-term debt and finance leases, net	3,113,239	3,064,679
Total liabilities	5,026,447	4,833,292
Commitments and contingencies (Note 14)
Member’s equity	2,649,748	2,643,006
Total liabilities and member’s equity	$7,676,195	$7,476,298

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-97

CLECO
Condensed Consolidated Statements of Cash Flows (Unaudited)

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Operating activities
Net income	$6,328	$20,557
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	63,307	56,776
Provision for credit losses	2,957	316
Unearned compensation expense	1,788	948
Allowance for equity funds used during construction	74	(5,688)
Loss on risk management assets and liabilities, net	6,509	954
Deferred lease revenue	(2,301)	(1,440)
Deferred income taxes	(2,900)	5,425
Deferred fuel costs	7,626	13,869
Cash surrender value of company-/trust-owned life insurance	10,686	(1,806)
Changes in assets and liabilities
Accounts receivable	13,310	(6,929)
Unbilled revenue	2,773	5,109
Fuel inventory and materials and supplies	(27,928)	(1,939)
Prepayments	(1,638)	14
Accounts payable	(55,131)	(19,999)
Accounts payable - affiliate	—	3,102
Customer deposits	2,731	2,598
Provision for merger commitments	1,018	(732)
Postretirement benefit obligations	1,315	192
Regulatory assets and liabilities, net	(721)	5,173
Other deferred accounts	(4,571)	(540)
Taxes accrued	14,563	5,403
Interest accrued	22,730	28,662
Deferred compensation	(2,743)	152
Other operating	424	(2,048)
Net cash provided by operating activities	60,206	108,129
Investing activities
Additions to property, plant, and equipment	(65,624)	(83,679)
Allowance for equity funds used during construction	(74)	5,688
Payment to acquire business, net of cash acquired	—	(814,969)
Other investing	285	299
Net cash used in investing activities	(65,413)	(892,661)
Financing activities
Draws on credit facilities	238,000	108,000
Payments on credit facilities	—	(108,000)
Issuances of long-term debt	—	400,000
Repayment of long-term debt	(11,055)	(10,382)
Payment of financing costs	—	(3,785)
Contributions from member	—	384,900
Other financing	(149)	(134)
Net cash provided by financing activities	226,796	770,599
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents	221,589	(13,933)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period	142,595(1)	140,086
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period	$364,184(2)	$126,153
Supplementary cash flow information
Interest paid, net of amount capitalized	$9,077	$5,752
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$11,854	$56,670

(1)
Includes cash and cash equivalents of $116,292, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $15,203.

(2)
Includes cash and cash equivalents of $350,231, current restricted cash and cash equivalents of $4,054, and non-current restricted cash and cash equivalents of $9,899.

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-98

CLECO
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited)

(THOUSANDS)	MEMBERSHIP INTEREST	RETAINED EARNINGS	AOCI	TOTAL MEMBER’S EQUITY
Balances, Dec. 31, 2018	$2,069,376	$53,578	$1,786	$2,124,740
Contribution from member	—	384,900	—	384,900
Net income	—	20,557	—	20,557
Other comprehensive loss, net of tax	—	—	(135)	(135)
Balances, Mar. 31, 2019	$2,069,376	$459,035	$1,651	$2,530,062
Balances, Dec. 31, 2019	$2,069,376	$591,143	$(17,513)	$2,643,006
Net income	—	6,328	—	6,328
Other comprehensive income, net of tax	—	—	414	414
Balances, Mar. 31, 2020	$2,069,376	$597,471	$(17,099)	$2,649,748

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-99

Cleco Power

These unaudited condensed consolidated financial statements should be read in conjunction with Cleco Power’s Consolidated Financial Statements and Notes included in “Financial Statements and Supplementary Data — Consolidated Financial Statements (Audited) of Cleco.” For more information on the basis of presentation, see “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies — Basis of Presentation.”

CLECO POWER
Condensed Consolidated Statements of Income (Unaudited)

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Operating revenue
Electric operations	$224,430	$257,175
Other operations	15,764	19,430
Affiliate revenue	1,106	300
Gross operating revenue	241,300	276,905
Electric customer credits	(8,340)	(8,160)
Operating revenue, net	232,960	268,745
Operating expenses
Fuel used for electric generation	61,064	94,131
Purchased power	23,462	29,654
Other operations and maintenance	56,944	47,700
Depreciation and amortization	43,677	42,377
Taxes other than income taxes	12,276	9,978
Total operating expenses	197,423	223,840
Operating income	35,537	44,905
Interest income	954	994
Allowance for equity funds used during construction	(74)	5,688
Other (expense) income, net	(2,667)	268
Interest charges
Interest charges, net	18,760	19,261
Allowance for borrowed funds used during construction	(179)	(2,116)
Total interest charges	18,581	17,145
Income before income taxes	15,169	34,710
Federal and state income tax expense	3,338	7,998
Net income	$11,831	$26,712

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-100

CLECO POWER
Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Net income	$11,831	$26,712
Other comprehensive income, net of tax
Postretirement benefits gain (net of tax expense of $152 in 2020 and $55 in 2019)	426	156
Amortization of interest rate derivatives to earnings (net of tax expense of $22 in 2020 and $22 in 2019)	64	64
Total other comprehensive income, net of tax	490	220
Comprehensive income, net of tax	$12,321	$26,932

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-101

CLECO POWER
Condensed Consolidated Balance Sheets (Unaudited)

(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Assets
Utility plant and equipment
Property, plant, and equipment	$5,542,292	$5,489,457
Accumulated depreciation	(1,941,674)	(1,905,031
Net property, plant, and equipment	3,600,618	3,584,426
Construction work in progress	114,710	111,687
Total utility plant and equipment, net	3,715,328	3,696,113
Current assets
Cash and cash equivalents	189,423	55,489
Restricted cash and cash equivalents	4,054	11,100
Customer accounts receivable (less allowance for credit losses of $2,123 in 2020 and $3,005 in 2019)	30,735	39,165
Accounts receivable - affiliate	12,037	14,481
Other accounts receivable	24,852	24,604
Unbilled revenue	30,434	33,207
Fuel inventory, at average cost	80,459	59,602
Materials and supplies, at average cost	93,544	91,941
Energy risk management assets	1,673	6,311
Accumulated deferred fuel	16,353	22,910
Cash surrender value of company-owned life insurance policies	17,614	17,574
Prepayments	4,469	4,786
Regulatory assets	10,907	10,973
Other current assets	646	655
Total current assets	517,200	392,798
Equity investment in investee	17,072	17,072
Prepayments	1,686	2,693
Operating lease right of use assets	27,883	28,633
Restricted cash and cash equivalents	9,056	14,363
Note receivable	15,031	15,198
Regulatory assets	267,602	272,289
Other deferred charges	36,791	37,371
Total assets	$4,607,649	$4,476,530

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-102

(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Liabilities and member’s equity
Member’s equity	$1,725,713	$1,713,392
Long-term debt and finance leases, net	1,377,432	1,327,372
Total capitalization	3,103,145	3,040,764
Current liabilities
Short-term debt	150,000	—
Long-term debt and finance leases due within one year	632	61,587
Accounts payable	77,892	110,096
Accounts payable - affiliate	10,486	14,123
Customer deposits	59,192	58,289
Provision for rate refund	28,921	38,241
Taxes payable, net	46,988	38,888
Interest accrued	23,232	7,972
Energy risk management liabilities	524	586
Regulatory liabilities - other	3,910	6,675
Other current liabilities	22,497	22,802
Total current liabilities	424,274	359,259
Commitments and contingencies (Note 14)
Long-term liabilities and deferred credits
Accumulated deferred federal and state income taxes, net	664,071	657,834
Postretirement benefit obligations	207,293	206,270
Regulatory liabilities - deferred taxes, net	146,225	146,948
Restricted storm reserve	8,324	12,285
Asset retirement obligations	7,441	7,325
Operating lease liabilities	25,001	25,658
Other deferred credits	21,875	20,187
Total long-term liabilities and deferred credits	1,080,230	1,076,507
Total liabilities and member’s equity	$4,607,649	$4,476,530

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-103

CLECO POWER
Condensed Consolidated Statements of Cash Flows (Unaudited)

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Operating activities
Net income	$11,831	$26,712
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	45,079	43,739
Provision for credit losses	2,569	316
Allowance for equity funds used during construction	74	(5,688)
Deferred income taxes	5,341	(2,386)
Deferred fuel costs	7,626	13,869
Cash surrender value of company-owned life insurance	(40)	3,044
Changes in assets and liabilities
Accounts receivable	3,452	(8,045)
Accounts receivable - affiliate	2,863	1,687
Unbilled revenue	2,773	5,109
Fuel inventory and materials and supplies	(22,429)	(6,147)
Prepayments	1,209	965
Accounts payable	(33,749)	(10,704)
Accounts payable - affiliate	(3,817)	8,422
Customer deposits	2,731	2,598
Provision for merger commitments	(1,295)	(732)
Postretirement benefit obligations	1,181	394
Regulatory assets and liabilities, net	(1,218)	4,676
Other deferred accounts	(3,452)	(840)
Taxes accrued	7,691	(22,895)
Interest accrued	15,260	16,868
Other operating	370	(993)
Net cash provided by operating activities	44,050	69,969
Investing activities
Additions to property, plant, and equipment	(61,477)	(81,040)
Allowance for equity funds used during construction	(74)	5,688
Other investing	285	299
Net cash used in investing activities	(61,266)	(75,053)
Financing activities
Draws on credit facility	150,000	33,000
Payments on credit facility	—	(33,000)
Repayment of long-term debt	(11,055)	(10,382)
Other financing	(148)	(142)
Net cash provided by (used in) financing activities	138,797	(10,524)
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents	121,581	(15,608)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period	80,952(1)	61,877
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period	$202,533(2)	$46,269

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-104

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Supplementary cash flow information
Interest paid, net of amount capitalized	$605	$1,348
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$11,015	$49,477

(1)
Includes cash and cash equivalents of $55,489, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $14,363.

(2)
Includes cash and cash equivalents of $189,423, current restricted cash and cash equivalents of $4,054, and non-current restricted cash and cash equivalents of $9,056.

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-105

CLECO POWER
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited)

(THOUSANDS)	MEMBER’S EQUITY	AOCI	TOTAL MEMBER’S EQUITY
Balances, Dec. 31, 2018	$1,607,715	$(13,182)	$1,594,533
Net income	26,712	—	26,712
Other comprehensive income, net of tax	—	220	220
Balances, Mar. 31, 2019	$1,634,427	$(12,962)	$1,621,465
Balances, Dec. 31, 2019	$1,735,977	$(22,585)	$1,713,392
Net income	11,831	—	11,831
Other comprehensive income, net of tax	—	490	490
Balances, Mar. 31, 2020	$1,747,808	$(22,095)	$1,725,713

The accompanying notes are an integral part of the condensed consolidated financial statements.

F-106

Index to Applicable Notes to the Unaudited Interim Financial Statements of Registrants

Note 1	Summary of Significant Accounting Policies	Cleco and Cleco Power
Note 2	Business Combinations	Cleco
Note 3	Recent Authoritative Guidance	Cleco and Cleco Power
Note 4	Leases	Cleco and Cleco Power
Note 5	Revenue Recognition	Cleco and Cleco Power
Note 6	Regulatory Assets and Liabilities	Cleco and Cleco Power
Note 7	Fair Value Accounting	Cleco and Cleco Power
Note 8	Debt	Cleco and Cleco Power
Note 9	Pension Plan and Employee Benefits	Cleco and Cleco Power
Note 10	Income Taxes	Cleco and Cleco Power
Note 11	Disclosures about Segments	Cleco
Note 12	Regulation and Rates	Cleco and Cleco Power
Note 13	Variable Interest Entities	Cleco and Cleco Power
Note 14	Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees	Cleco and Cleco Power
Note 15	Affiliate Transactions	Cleco and Cleco Power
Note 16	Intangible Assets and Liabilities	Cleco and Cleco Power
Note 17	Accumulated Other Comprehensive Loss	Cleco and Cleco Power

F-107

Note 1 — Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying condensed consolidated financial statements of Cleco include the accounts of Cleco and its majority-owned subsidiaries after elimination of intercompany accounts and transactions. Cleco’s condensed consolidated financial statements include the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, through March 31, 2020. For more information about the Cleco Cajun Transaction, see Note 2 — “Business Combinations.”

Basis of Presentation

The condensed consolidated financial statements of Cleco and Cleco Power have been prepared in accordance with GAAP for interim financial information and with the instructions to the Form 10-Q and Regulation S-X. Accordingly, these condensed consolidated financial statements do not include all of the information and notes required by GAAP for annual financial statements. The year-end condensed consolidated balance sheet data was derived from audited financial statements. Because the interim condensed consolidated financial statements and the accompanying notes do not include all of the information and notes required by GAAP for annual financial statements, the condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

These condensed consolidated financial statements, in the opinion of management, reflect all normal recurring adjustments that are necessary to fairly state the financial position and results of operations of Cleco and Cleco Power. Amounts reported in Cleco and Cleco Power’s interim financial statements are not necessarily indicative of amounts expected for the annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices, discrete income tax items, and other factors.

On March 11, 2020, the World Health Organization declared the current outbreak of COVID-19 to be a global pandemic, and on March 13, 2020, the U.S. declared a national emergency. In response to these declarations and the rapid spread of COVID-19, federal, state and local governments have imposed varying degrees of restrictions on business and social activities to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory. Cleco has modified some of its business operations, as these restrictions have significantly impacted many sectors of the economy, including record levels of unemployment, with businesses, nonprofit organizations, and governmental entities modifying, curtailing, or ceasing normal operations. Cleco has also modified certain business practices to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities.

Cleco cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the markets will have on its business, cash flows, liquidity, financial condition, and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities, customers, suppliers and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume.

In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses, and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. For information on recent authoritative guidance and its effect on financial results, see Note 3 — “Recent Authoritative Guidance.”

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.

F-108

Cleco and Cleco Power’s restricted cash and cash equivalents consisted of the following:

Cleco
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Current
Cleco Katrina/Rita’s storm recovery bonds	$2,623	$9,632
Cleco Power’s charitable contributions	1,200	1,200
Cleco Power’s rate credit escrow	231	268
Total current	4,054	11,100
Non-current
Diversified Lands’ mitigation escrow	23	21
Cleco Cajun’s defense fund	720	719
Cleco Cajun’s margin deposits	100	100
Cleco Power’s future storm restoration costs	8,315	12,269
Cleco Power’s charitable contributions	741	2,094
Total non-current	9,899	15,203
Total restricted cash and cash equivalents	$13,953	$26,303

Cleco Power
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Current
Cleco Katrina/Rita’s storm recovery bonds	$2,623	$9,632
Charitable contributions	1,200	1,200
Rate credit escrow	231	268
Total current	4,054	11,100
Non-current
Future storm restoration costs	8,315	12,269
Charitable contributions	741	2,094
Total non-current	9,056	14,363
Total restricted cash and cash equivalents	$13,110	$25,463

Cleco Katrina/Rita had the right to bill and collect storm restoration costs from Cleco Power’s customers. As cash was collected, it was restricted for payment of administration fees, interest, and principal on storm recovery bonds. The change from December 31, 2019, to March 31, 2020, was due to Cleco Katrina/Rita using $11.1 million for the final storm recovery bond principal payment and $0.3 million for the related final interest payment, partially offset by collections of $4.4 million net of administration fees. The remaining $2.6 million of restricted cash is expected to be used for final administrative and winding up activities of Cleco Katrina/Rita.

Reserves for Credit Losses

Customer accounts receivable are recorded at the invoiced amount and do not bear interest. Customer accounts receivables are generally considered to become past due 20 days after the billing date. Cleco recognizes write-offs within the allowance for credit losses once all recovery methods have been exhausted. It is the policy of management to review accounts receivable and unbilled revenue monthly using a reserve matrix based on historical bad debt write-offs as well as current and forecasted economic conditions to establish a credit loss estimate. Management’s historical credit loss analysis included periods of economic recessions, natural disasters, and temporary changes to collection policies. Due to the critical necessity of electricity, none of these past events have significantly impacted Cleco’s credit loss rates. While the LPSC has issued a moratorium on disconnects of customers for nonpayment on March 13, 2020, and Cleco’s service territory experienced a recent decline in the economy related to the COVID-19 outbreak, the economic outlook at March 31, 2020, was still within range of Cleco’s historical credit loss analysis.

F-109

The table below presents the changes in the allowance for credit losses by receivable for Cleco and Cleco Power:

Cleco
(THOUSANDS)	ACCOUNTS RECEIVABLE	OTHERS*	TOTAL
Balances, Dec. 31, 2019	$3,005	$1,250	$4,255
CECL adoption	71	—	71
Current period provision	2,498	388	2,886
Charge-offs	(4,092)	—	(4,092)
Recovery	641	—	641
Balances, Mar. 31, 2020	$2,123	$1,638	$3,761

*
Loan held at Diversified Lands that is fully reserved for at March 31, 2020.

Cleco Power
(THOUSANDS)	ACCOUNTS RECEIVABLE
Balances, Dec. 31, 2019	$3,005
CECL adoption	71
Current period provision	2,498
Charge-offs	(4,092)
Recovery	641
Balances, Mar. 31, 2020	$2,123

Fair Value Measurements and Disclosures

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values. Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance. Cleco and Cleco Power disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes. For more information about fair value levels, see Note 7 — “Fair Value Accounting.”

Derivatives and Other Risk Management Activity

Cleco’s Energy Market Risk Management Policy authorizes hedging of commodity price risk with physical or financially settled derivative instruments. Some of these contracts may qualify for the normal purchase, normal sale (NPNS) exception under derivative accounting guidance. Contracts that do not qualify for NPNS accounting treatment or are not elected for NPNS accounting treatment are marked-to-market and recorded on the balance sheet at their fair value.

Additionally, Cleco Power and Cleco Cajun are awarded and/or purchase FTRs in auctions facilitated by MISO. FTRs represent economic hedges of future congestion charges that will be incurred in serving customer load. FTRs are derivatives not designated as hedging instruments for accounting purposes.

Cleco Power’s FTRs are marked-to-market with the resulting unrealized gains or losses deferred as a component of deferred fuel assets or liabilities in accordance with regulatory policy. At settlement, realized gains or losses are included in the FAC and reflected on customers’ bills as a component of the fuel charge.

Cleco Cajun’s FTRs are marked-to-market with the resulting unrealized gains and losses recorded on the income statement as a component of purchased power expense. At settlement, realized gains or losses are also recorded on the income statement as a component of purchased power expense.

Cleco Cajun entered into other commodity derivative contracts during the three months ended March 31, 2020. Management did not elect to apply hedge accounting to these contracts as allowed under applicable accounting standards. When these contracts are marked-to-market, the resulting unrealized gain or loss is recorded on the income statement as a component of fuel expense for gas related derivative contracts or purchased power for

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power related derivative contracts. At settlement, realized gains or losses are also recorded on the income statement as a component of fuel expense for gas related derivative contracts or purchased power for power related derivative contracts.

For more information on FTRs and other commodity derivatives, see Note 7 — “Fair Value Accounting — Commodity Contracts.”

Cleco may also enter into 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 each reporting period presented, the Registrants did not enter into any contracts to mitigate the volatility in interest rate risk.

Note 2 — Business Combinations

On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in South Central Generating. This acquisition enabled Cleco to significantly increase the scale of its operations in Louisiana.

Accounting for the Cleco Cajun Transaction

As consideration for all of the outstanding membership interest in South Central Generating, Cleco paid cash of approximately $962.2 million, which represents the $1.0 billion acquisition price net of working capital and other adjustments of $37.8 million.

Cleco Cajun accounted for the Cleco Cajun Transaction as a business combination, and accordingly, the assets acquired and liabilities assumed were recorded at their estimated fair values as of the date of the acquisition. Cleco made certain measurement period adjustments at June 30, 2019. The following chart presents Cleco’s purchase price allocation:

Purchase Price Allocation
(THOUSANDS)	AT FEB. 4, 2019
Current assets
Cash and cash equivalents	$146,494
Customer and other accounts receivable	49,809
Fuel inventory	22,060
Materials and supplies	25,659
Energy risk management assets	4,193
Other current assets	10,056
Non-current assets
Property, plant, and equipment, net	741,203
Prepayments	36,166
Restricted cash and cash equivalents	707
Intangible assets	98,900
Other deferred charges	133
Total assets acquired	1,135,380
Current liabilities
Accounts payable	38,478
Taxes payable	723
Energy risk management liabilities	241
Other current liabilities	14,570
Non-current liabilities
Accumulated deferred federal and state income taxes, net	7,165
Deferred lease revenue	58,300
Intangible liabilities	38,300
Asset retirement obligations	15,323
Operating lease liabilities	110
Total liabilities assumed	173,210
Total purchase price consideration	$962,170

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During the second quarter of 2019, certain modifications were made to the preliminary valuations as of February 4, 2019, due to the refinement of valuation models, assumptions, and inputs. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date.

Measurement Period Adjustments
(THOUSANDS)	AT JUNE 30, 2019
Current assets
Customer and other accounts receivable	$1,408
Other current assets	$56
Non-current assets
Property, plant, and equipment, net	$13,297
Prepayments	$(56)
Intangible assets	$(3,600)
Other deferred charges	$1
Current liabilities
Accounts payable	$3,022
Energy risk management liabilities	$(1)
Other current liabilities	$327
Non-current liabilities
Accumulated deferred federal and state income taxes, net	$421
Deferred lease revenue	$(3,600)
Intangible liabilities	$6,400
Asset retirement obligations	$4,534
Operating lease liabilities	$3

The measurement period adjustments resulted in an increase in electric operations revenue of $0.5 million, a decrease in other operations revenue of $0.1 million, and an increase in depreciation expense of $0.2 million recorded for the three months ended June 30, 2019.

As of December 31, 2019, Cleco completed its evaluation and determination of the fair value of assets acquired and liabilities assumed in the Cleco Cajun Transaction. There were no adjustments to those amounts during the three months ended March 31, 2020.

Pro forma Impact of the Cleco Cajun Transaction

The following table includes the unaudited pro forma financial information reflecting the consolidated results of operations of Cleco as if the Cleco Cajun Transaction had taken place on January 1, 2018. The pro forma net income for the three months ended March 31, 2019, was adjusted to exclude nonrecurring transaction-related expenses of $3.9 million.

The unaudited pro forma financial information presented in the following table is not necessarily indicative of the consolidated results of operations that would have been achieved had the transaction taken place on the date indicated, or the future consolidated results of operations of the combined companies.

Unaudited Pro Forma Financial Information
(THOUSANDS)	FOR THE THREE MONTHS ENDED MAR. 31, 2019
Operating revenue, net	$381,796
Net income	$32,986

Note 3 — Recent Authoritative Guidance

In June 2016, FASB amended the guidance for the measurement of credit losses on receivables and certain other assets. In-scope items for Cleco include unbilled revenue, trade receivables, notes receivables, other accounts receivables, and guarantees. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses. Effective January 1, 2020, Cleco adopted the amended guidance using the

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prospective transition method. Adoption of this standard resulted in a $0.1 million increase in credit loss reserves related to unbilled revenue and trade receivables. The current expected credit loss model did not impact reserves related to any other in-scope items. For more information on Cleco’s accounting for credit losses, see Note 1 — “Summary of Significant Accounting Policies — Reserves for Credit Losses.”

In August 2018, FASB issued guidance that allows for the deferral of certain implementation costs incurred in a cloud computing arrangement. Effective January 1, 2020, Cleco adopted the guidance using the prospective transition method. Adoption of this guidance did not materially impact the Registrants’ results of operations, financial condition, or cash flows.

In March 2020, FASB issued amendments that are elective and apply to all entities, subject to meeting certain criteria, for the contract modifications or hedging relationships that are referencing LIBOR or another reference rate expected to be discontinued due to reference rate reform. The amendments include a general principal that permits an entity to consider contract modifications due to reference rate reform to be an event that does not require contract remeasurement at the modification date or reassessment of a previous accounting determination. The amendment became effective March 12, 2020. Management is evaluating this guidance and the impact it may have on the Registrants’ results of operations, financial condition, or cash flows.

Note 4 — Leases

Cleco maintains operating and finance leases in its ordinary course of business activities.

Cottonwood Sale Leaseback Agreement

Upon closing the Cleco Cajun Transaction, the Cottonwood Sale Leaseback was executed. Under the terms of the lease, NRG Energy will operate the Cottonwood Plant, incur all costs, and receive all revenues from the operations of the plant. Cottonwood Energy will receive fixed lease payments of $40.0 million per year and variable lease payments for LTSA costs and property taxes paid by NRG Energy on behalf of Cleco. Cleco may terminate the lease contract under specific circumstances stated in the lease contract. The residual value under the Cottonwood Sale Leaseback is expected to be recovered through sales of power generation from the plant. The residual value of the Cottonwood Plant has been determined using the plant’s estimated economic life.

Cleco Cajun is Cleco’s only entity with lessor arrangements. Cleco Cajun’s lease income under the Cottonwood Sale Leaseback for the three months ended March 31, 2020, and 2019, was as follows:

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Fixed payments	$10,000	$6,667
Variable payments	5,566	3,151
Amortization of deferred lease liability(1)	2,302	1,440
Total lease income	$17,868	$11,258

(1)
Consists of the deferred lease revenue resulting from the fair value of the lease between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy. For more information, see Note 2 — “Business Combinations.”

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Note 5 — Revenue Recognition

Disaggregated Revenue

Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a reportable segment. For more information on the transaction, see Note 2 — “Business Combinations.”

Operating revenue, net for the three months ended March 31, 2020, and 2019, was as follows:

	FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)	CLECO POWER	CLECO CAJUN	OTHER	ELIMINATIONS	TOTAL
Revenue from contracts with customers
Retail revenue
Residential(1)	$81,571	$—	$—	$—	$81,571
Commercial(1)	61,110	—	—	—	61,110
Industrial(1)	32,210	—	—	—	32,210
Other retail(1)	3,461	—	—	—	3,461
Surcharge	2,443	—	—	—	2,443
Electric customer credits	(8,340)	—	—	—	(8,340)
Total retail revenue	172,455	—	—	—	172,455
Wholesale, net	42,229(1)	89,147	(2,420)(2)	—	128,956
Transmission, net	12,069	12,931(3)	—	(1,818)	23,182
Other	3,695(4)	—	1	—	3,696
Affiliate(5)	1,106	161	29,278	(30,545)	—
Total revenue from contracts with customers	231,554	102,239	26,859	(32,363)	328,289
Revenue unrelated to contracts with customers
Other	1,406(6)	17,877(7)	—	—	19,283
Total revenue unrelated to contracts with customers	1,406	17,877	—	—	19,283
Operating revenue, net	$232,960	$120,116	$26,859	$(32,363)	$347,572

(1)
Includes fuel recovery revenue.

(2)
Amortization of intangible assets related to Cleco Power’s wholesale power supply agreements.

(3)
Includes $0.2 million of electric customer credits.

(4)
Includes $3.7 million of other miscellaneous fee revenue.

(5)
Includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.

(6)
Includes realized gains associated with FTRs of $1.4 million.

(7)
Includes $15.6 million in lease revenue related to the Cottonwood Sale Leaseback and $2.3 million of deferred lease revenue amortization.

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	FOR THE THREE MONTHS ENDED MAR. 31, 2019
(THOUSANDS)	CLECO POWER	CLECO CAJUN	OTHER	ELIMINATIONS	TOTAL
Revenue from contracts with customers
Retail revenue
Residential(1)	$87,148	$—	$—	$—	$87,148
Commercial(1)	65,380	—	—	—	65,380
Industrial(1)	37,870	—	—	—	37,870
Other retail(1)	3,681	—	—	—	3,681
Surcharge	5,321	—	—	—	5,321
Electric customer credits	(8,160)	—	—	—	(8,160)
Total retail revenue	191,240	—	—	—	191,240
Wholesale, net	55,546(1)	58,191	(2,420)(2)	—	111,317
Transmission	12,579	8,727	—	—	21,306
Other	6,851(3)	(26)	2	—	6,827
Affiliate(4)	300	—	26,535	(26,835)	—
Total revenue from contracts with customers	266,516	66,892	24,117	(26,835)	330,690
Revenue unrelated to contracts with customers
Other	2,229(5)	11,267(6)	—	—	13,496
Total revenue unrelated to contracts with customers	2,229	11,267	—	—	13,496
Operating revenue, net	$268,745	$78,159	$24,117	$(26,835)	$344,186

(1)
Includes fuel recovery revenue.

(2)
Amortization of intangible assets related to Cleco Power’s wholesale power supply agreements.

(3)
Includes $4.4 million of other miscellaneous fee revenue and $2.4 million of Teche Unit 3 SSR revenue at Cleco Power.

(4)
Includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.

(5)
Includes realized gains associated with FTRs of $4.8 million and the reversal of the LCFC revenue of $(2.6) million.

(6)
Includes $9.8 million in lease revenue related to the Cottonwood Sale Leaseback and $1.4 million of deferred lease revenue amortization.

Cleco and Cleco Power have unsatisfied performance obligations with durations ranging between 1 and 15 years that primarily relate to stand-ready obligations as part of fixed capacity minimums. At March 31, 2020, Cleco and Cleco Power had $80.7 million of unsatisfied performance obligations that will be recognized as revenue over the term of such contracts as the stand-ready obligation to provide energy is provided.

Note 6 — Regulatory Assets and Liabilities

Cleco Power capitalizes or defers certain costs for recovery from customers and recognizes a liability for amounts expected to be returned to customers based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered or refunded 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 the authoritative guidance on regulated operations.

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The following table summarizes Cleco Power’s regulatory assets and liabilities:

Cleco Power
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Regulatory assets (liabilities)
Deferred taxes, net	$(146,225)	$(146,948)
Interest costs	3,896	3,958
AROs	3,815	3,668
Postretirement costs	147,889	151,543
Tree trimming costs	11,384	11,341
Training costs	6,202	6,241
Surcredits, net(1)	72	145
AMI deferred revenue requirement	3,000	3,136
Emergency declarations	948	1,349
Production operations and maintenance expenses	6,756	7,985
AFUDC equity gross-up(1)	71,992	72,766
Acadia Unit 1 acquisition costs	2,098	2,124
Financing costs	7,461	7,554
Coughlin transaction costs	899	906
Corporate franchise tax, net	(1,145)	(1,145)
Non-service cost of postretirement benefits	7,551	6,739
Energy efficiency	2,820	2,820
Accumulated deferred fuel	16,353	22,910
Other, net	(1,039)	(4,543)
Total regulatory assets, net	$144,727	$152,549

(1)
Represents regulatory assets for past expenditures that were not earning a return on investment at March 31, 2020, and December 31, 2019, respectively. All other assets are earning a return on investment.

The following table summarizes Cleco’s net regulatory assets and liabilities:

Cleco
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Total Cleco Power regulatory assets, net	$144,727	$152,549
2016 Merger adjustments(1)
Fair value of long-term debt	125,105	127,977
Postretirement costs	16,902	17,399
Financing costs	7,849	7,935
Debt issuance costs	5,504	5,665
Total Cleco regulatory assets, net	$300,087	$311,525

(1)
Cleco regulatory assets include acquisition accounting adjustments as a result of the 2016 Merger.

Note 7 — Fair Value Accounting

The amounts reflected on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020, and December 31, 2019, for cash equivalents, restricted cash equivalents, accounts receivable, other accounts receivable, short-term debt, and accounts payable approximate fair value because of their short-term nature. Cleco applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including business combinations, as well as impairment related to goodwill and other long-lived assets.

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The following tables summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments not measured at fair value on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets:

Cleco
	AT MAR. 31, 2020		AT DEC. 31, 2019
(THOUSANDS)	CARRYING VALUE*	FAIR VALUE	CARRYING VALUE*	FAIR VALUE
Long-term debt	$3,174,821	$3,295,214	$3,188,664	$3,371,915

*
The carrying value of long-term debt does not include deferred issuance costs of $13.2 million at March 31, 2020, and $13.7 million at December 31, 2019.

Cleco Power
	AT MAR. 31, 2020		AT DEC. 31, 2019
(THOUSANDS)	CARRYING VALUE*	FAIR VALUE	CARRYING VALUE*	FAIR VALUE
Long-term debt	$1,369,716	$1,696,053	$1,380,688	$1,601,865

*
The carrying value of long-term debt does not include deferred issuance costs of $7.2 million at March 31, 2020, and $7.4 million at December 31, 2019.

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

Fair Value Measurements and Disclosures

Cleco classifies assets and liabilities that are measured 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 on a recurring basis:

Cleco
	FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)	AT MAR. 31, 2020	QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)	SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)	AT DEC. 31, 2019	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	$352,549	$—	$352,549	$—	$129,643	$—	$129,643	$—
FTRs	1,779	—	—	1,779	6,822	—	—	6,822
Other commodity derivatives	213	—	213	—	201	—	201	—
Total assets	$354,541	$—	$352,762	$1,779	$136,666	$—	$129,844	$6,822
Liability description
FTRs	$683	$—	$—	$683	$1,044	$—	$—	$1,044
Other commodity derivatives	12,494	—	12,494	—	5,373	—	5,373	—
Total liabilities	$13,177	$—	$12,494	$683	$6,417	$—	$5,373	$1,044

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Cleco Power
	FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)	AT MAR. 31, 2020	QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)	SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)	SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)	AT DEC. 31, 2019	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	$198,006	$—	$198,006	$—	$74,903	$—	$74,903	$—
FTRs	1,673	—	—	1,673	6,311	—	—	6,311
Total assets	$199,679	$—	$198,006	$1,673	$81,214	$—	$74,903	$6,311
Liability description
FTRs	$524	$—	$—	$524	$586	$—	$—	$586
Total liabilities	$524	$—	$—	$524	$586	$—	$—	$586

The following tables summarize the net changes in the net fair value of FTR assets and liabilities classified as Level 3 in the fair value hierarchy for Cleco and Cleco Power:

Cleco
	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Beginning balance	$5,778	$22,887
Unrealized losses*	(1,398)	(1,917)
Purchases	466	5,237
Settlements	(3,750)	(18,397)
Ending balance	$1,096	$7,810

*
Cleco Power’s unrealized losses are reported through Accumulated deferred fuel on Cleco’s Condensed Consolidated Balance Sheet. Cleco Cajun’s unrealized (losses) gains are reported through Purchased power on Cleco’s Condensed Consolidated Income Statement.

Cleco Power
	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Beginning balance	$5,725	$22,887
Unrealized losses*	(1,311)	(2,939)
Purchases	466	1,286
Settlements	(3,731)	(16,422)
Ending balance	$1,149	$4,812

*
Unrealized losses are reported through Accumulated deferred fuel on Cleco Power’s Condensed Consolidated Balance Sheet.

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The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for Cleco and Cleco Power as of March 31, 2020, and December 31, 2019:

Cleco
	FAIR VALUE		VALUATION TECHNIQUE	SIGNIFICANT UNOBSERVABLE INPUTS	FORWARD PRICE RANGE
(THOUSANDS, EXCEPT FORWARD PRICE RANGE)	ASSETS	LIABILITIES			LOW	HIGH
FTRs at Mar. 31, 2020	$1,779	$683	RTO auction pricing	FTR price - per MWh	$(1.40)	$2.93
FTRs at Dec. 31, 2019	$6,822	$1,044	RTO auction pricing	FTR price - per MWh	$(2.57)	$2.86

Cleco Power
	FAIR VALUE		VALUATION TECHNIQUE	SIGNIFICANT UNOBSERVABLE INPUTS	FORWARD PRICE RANGE
(THOUSANDS, EXCEPT FORWARD PRICE RANGE)	ASSETS	LIABILITIES			LOW	HIGH
FTRs at Mar. 31, 2020	$1,673	$524	RTO auction pricing	FTR price - per MWh	$(1.40)	$2.93
FTRs at Dec. 31, 2019	$6,311	$586	RTO auction pricing	FTR price - per MWh	$(2.04)	$2.86

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 are determined by obtaining the closing price of similar assets and liabilities from published indices in active markets. Institutional money market funds assets are discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return. Level 3 fair values occur in situations in which there is little, if any, market activity for the asset or liability at the measurement date and prices are not observable. Cleco has consistently applied the Level 2 and Level 3 fair value techniques from fiscal period to fiscal period. Significant increases or decreases in any of those inputs in isolation would result in a significantly different fair value measurement. 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.

At March 31, 2020, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents and restricted cash equivalents. The following tables present the institutional money market funds in cash and cash equivalents and restricted cash and cash equivalents as recorded on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020, and December 31, 2019:

Cleco
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Cash and cash equivalents	$338,611	$103,409
Current restricted cash and cash equivalents	$4,054	$11,100
Non-current restricted cash and cash equivalents	$9,883	$15,134

Cleco Power
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Cash and cash equivalents	$184,911	$49,509
Current restricted cash and cash equivalents	$4,054	$11,100
Non-current restricted cash and cash equivalents	$9,041	$14,294

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If the money market funds failed to perform under the terms of the investments, Cleco and Cleco Power would be exposed to a loss of the invested amounts. Collateral on these types of investments is not required by either Cleco or Cleco Power. 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 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.

Other commodity derivatives include fixed price physical forwards and swap transactions. These contracts contain counterparty credit risk because they are transacted directly with a counterparty and are not cleared on an exchange. With respect to any open trading contracts that Cleco has entered into or may enter into in the future, Cleco may be required to provide credit support or pay liquidated damages under such contracts. 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 contract, changes in the market price, changes in open contracts, and changes in the amounts counterparties owe to Cleco. Changes in any of these factors could cause the amount of requested credit support to increase or decrease. These other commodity derivatives are recorded at fair value and categorized as Level 2 because pricing is indexed to other contracts.

Cleco Power and Cleco Cajun’s FTRs were priced using MISO’s monthly auction prices. Forward seasonal periods are not included in every monthly auction; therefore, the average of the most recent seasonal auction prices is used for monthly valuation. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from MISO auctions, which occur monthly in the Multi-Period Monthly Auction.

During the three months ended March 31, 2020, and the year ended December 31, 2019, Cleco did not experience any transfers between levels within the fair value hierarchy.

Commodity Contracts

The following tables present the fair values of derivative instruments and their respective line items as recorded on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020, and December 31, 2019:

Cleco
	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT MAR. 31, 2020	AT DEC. 31, 2019
Commodity-related contracts
FTRs
Current	Energy risk management assets	$1,779	$6,822
Current	Energy risk management liabilities	(683)	(1,044)
Other commodity derivatives
Current	Energy risk management assets	213	201
Current	Energy risk management liabilities	(9,014)	(3,069)
Non-current	Other deferred credits	(3,480)	(2,304)
Commodity-related contracts, net		$(11,185)	$606

Cleco Power
	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT MAR. 31, 2020	AT DEC. 31, 2019
Commodity-related contracts
FTRs
Current	Energy risk management assets	$1,673	$6,311
Current	Energy risk management liabilities	(524)	(586)
Commodity-related contracts, net		$1,149	$5,725

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The following tables present the effect of derivatives not designated as hedging instruments on Cleco and Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2020, and 2019:

Cleco
	AMOUNT OF GAIN(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES
		FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	INCOME STATEMENT LINE ITEM	2020	2019
Commodity-related contracts
FTRs(1)	Electric operations	$1,396	$5,209
FTRs(1)	Purchased power	(381)	(3,324)
Other commodity derivatives	Fuel used for electric generation	(7,108)	—
Total		$(6,093)	$1,885

(1)
For the three months ended March 31, 2020, unrealized losses associated with FTRs for Cleco Power of $1.3 million were reported through Accumulated deferred fuel on the balance sheet. For the three months ended March 31, 2019, unrealized losses associated with FTRs for Cleco Power of $2.9 million were reported through Accumulated deferred fuel on the balance sheet.

Cleco Power
	AMOUNT OF GAIN(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES
		FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	INCOME STATEMENT LINE ITEM	2020	2019
Commodity-related contracts
FTRs(1)	Electric operations	$1,396	$5,206
FTRs(1)	Purchased power	(751)	(1,983)
Total		$645	$3,223

(1)
For the three months ended March 31, 2020, unrealized losses associated with FTRs of $1.3 million were reported through Accumulated deferred fuel on the balance sheet. For the three months ended March 31, 2019, unrealized losses associated with FTRs of $2.9 million were reported through Accumulated deferred fuel on the balance sheet.

The total volume of FTRs that Cleco Power had outstanding at March 31, 2020, and December 31, 2019, was 3.4 million MWh and 9.2 million MWh, respectively. The total volume of FTRs that Cleco had outstanding at March 31, 2020, and December 31, 2019, was 5.4 million MWh and 14.6 million MWh, respectively. The total volume of other commodity derivatives Cleco had outstanding at March 31, 2020, and December 31, 2019, was 54.8 million MMBtus and 58.5 million MMBtus, respectively.

Note 8 — Debt

On March 2, 2020, Cleco Power made the final $11.1 million principal payment and completed the repayment in full of its Cleco Katrina/Rita storm recovery bonds issued in March 2008.

On May 1, 2020, Cleco Power repriced at a mandatory tender date its $50.0 million 2008 series A GO Zone bonds and entered into a new interest rate period with a mandatory tender date of May 1, 2025. The interest rate for the new interest rate period is fixed at 2.50% per annum.

At March 31, 2020, Cleco Holdings had $88.0 million of borrowings outstanding under its $175.0 million credit facility at an all-in interest rate of 2.50%. The borrowing costs under the facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%.

At March 31, 2020, Cleco Power had $150.0 million of borrowings outstanding under its $300.0 million credit facility at an all-in interest rate of 1.875%. The borrowing costs under the facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%.

Note 9 — Pension Plan and Employee Benefits

Pension Plan and Other Benefits Plan

Employees hired before August 1, 2007, are covered by a non-contributory, defined benefit pension plan. In September 2019, Cleco made a $12.3 million discretionary contribution to the pension plan. Based on updated

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funding assumptions at December 31, 2019, management estimates that $66.5 million in pension contributions will be required through 2024. Cleco expects to make a $15.5 million minimum required contribution to the pension plan in 2020.

Cleco Power is the plan sponsor and Support Group is the plan administrator. The plan was amended on February 4, 2019, to include certain former NRG Energy employees who are now Cleco Cajun employees. The Cleco Cajun employees are eligible to participate as a cash balance participant and are credited with all service that was credited to them under the NRG Pension Plan as of February 4, 2019. Benefits under the plan amendment reflect an employee’s years of service, age at retirement, and accrued benefit at retirement.

Cleco’s retirees may be eligible to receive Other Benefits. Dependents of Cleco’s retirees may also be eligible to receive Other Benefits with the exception of life insurance benefits.

The non-service components of net periodic pension and Other Benefits cost are included in Other income (expense), net within Cleco and Cleco Power’s Condensed Consolidated Statements of Income. The components of net periodic pension and Other Benefits cost for the three months ended March 31, 2020, and 2019 were as follows:

	PENSION BENEFITS		OTHER BENEFITS
	FOR THE THREE MONTHS ENDED MAR. 31,		FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019	2020	2019
Components of periodic benefit costs
Service cost	$2,328	$2,067	$508	$288
Interest cost	5,130	5,650	410	400
Expected return on plan assets	(6,245)	(6,622)	—	—
Amortizations
Prior period service credit	(15)	(18)	—	—
Net loss (gain)	3,672	1,875	339	(45)
Net periodic benefit cost	$4,870	$2,952	$1,257	$643

Because 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 three months ended March 31, 2020, was $0.4 million. The expense of the pension plan related to Cleco’s other subsidiaries for the three months ended March 31, 2019, was $0.5 million.

Cleco Holdings 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. The expense related to other benefits reflected in Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2020, was $1.2 million. The expense related to other benefits reflected in Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2019, was $0.7 million. The current and non-current portions of the Other Benefits liability for Cleco and Cleco Power at March 31, 2020, and December 31, 2019, were as follows:

Cleco
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Current	$4,401	$4,401
Non-current	$48,175	$48,321

Cleco Power
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Current	$3,815	$3,815
Non-current	$41,994	$42,080

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SERP

Certain Cleco officers are covered by SERP. 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. The life insurance policies issued on SERP participants designate the rabbi trust as the beneficiary. Market conditions could have a significant impact on the cash surrender value of the life insurance policies. Proceeds from the life insurance policies are expected to be used to pay the SERP participants’ death benefits, as well as future SERP payments. However, because 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 that employed the officer. Cleco Power is the plan sponsor and Support Group is the plan administrator.

The non-service components of net periodic benefit cost related to SERP are included in Other income (expense), net within Cleco and Cleco Power’s Condensed Consolidated Statements of Income. The components of the net periodic benefit cost related to SERP for the three months ended March 31, 2020, and 2019 were as follows:

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Components of periodic benefit costs
Service cost	$95	$113
Interest cost	733	825
Amortizations
Prior period service credit	(40)	(35)
Net loss	757	392
Net periodic benefit cost	$1,545	$1,295

The expense related to SERP reflected on Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2020, was $0.2 million. The expense related to SERP reflected on Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2019, was $0.3 million.

Liabilities relating to SERP are reported on the individual subsidiaries’ financial statements. The current and non-current portions of the SERP liability for Cleco and Cleco Power at March 31, 2020, and December 31, 2019, were as follows:

Cleco
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Current	$4,599	$4,599
Non-current	$84,219	$84,529

Cleco Power
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Current	$760	$760
Non-current	$13,863	$13,964

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401(k) Plan

Cleco’s 401(k) Plan is intended to provide active, eligible employees with voluntary, long-term savings and investment opportunities. The 401(k) Plan is a defined contribution plan and is subject to the applicable provisions of the Employee Retirement Income Security Act of 1974. In accordance with the 401(k) Plan, employer contributions are made in the form of cash. Cash contributions are invested in proportion to the participant’s voluntary contribution investment choices. Participation in the Plan is voluntary, and active Cleco employees are eligible to participate. Cleco’s 401(k) Plan was amended upon the close of the Cleco Cajun Transaction to include Cleco Cajun employees. Cleco’s 401(k) Plan expense for the three months ended March 31, 2020, and 2019 was as follows:

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
401(k) Plan expense	$3,256	$2,267

Cleco Power is the plan sponsor for the 401(k) Plan. The expense of the 401(k) Plan related to Cleco’s other subsidiaries for the three months ended March 31, 2020, and 2019 was as follows:

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
401(k) Plan expense	$1,662	$930

Note 10 — Income Taxes

Effective Tax Rates

The following tables summarize the effective income tax rates for Cleco and Cleco Power for the three months ended March 31, 2020, and 2019:

Cleco
	FOR THE THREE MONTHS ENDED MAR. 31,
	2020	2019
Effective tax rate	19.8%	22.6%

Cleco Power
	FOR THE THREE MONTHS ENDED MAR. 31,
	2020	2019
Effective tax rate	22.0%	23.0%

For the three months ended March 31, 2020, and 2019, the effective income tax rates for both Cleco and Cleco Power were different than the federal statutory rate primarily due to permanent tax differences; the flowthrough of tax benefits, including AFUDC equity; and state tax expense.

Net Operating Loss

For the 2019 tax year, Cleco created approximately $551.4 million and $82.6 million of federal and state net operating losses, respectively, primarily due to the Cleco Cajun Transaction.

The federal net operating loss may be carried forward indefinitely, and state net operating loss carryforwards will begin to expire in 2039.

Cleco considers it more likely than not that these income tax losses will be utilized to reduce future income tax payments and utilize the entire net operating loss carryforward within the statutory deadlines.

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Uncertain Tax Positions

Cleco classifies all interest related to uncertain tax positions as a component of interest payable and interest expense. At March 31, 2020, and December 31, 2019, Cleco and Cleco Power had no liability for uncertain tax positions or interest payable related to uncertain tax positions. Cleco estimates that it is reasonably possible that the balance of unrecognized tax benefits as of March 31, 2020, for Cleco and Cleco Power would be unchanged in the next 12 months. The settlement of open tax years could involve the payment of additional taxes, and/or the recognition of tax benefits, which may have an effect on Cleco’s effective tax rate.

Income Tax Audits

Cleco participates in the IRS’s Compliance Assurance Process in which financial results are examined and agreed upon prior to filing the federal consolidated tax return. While the statute of limitations remains open for tax years 2016, 2017, and 2018, management believes the likelihood of further examination by the IRS is remote.

The state income tax years 2016, 2017, and 2018 remain subject to examination by the Louisiana Department of Revenue.

Cleco classifies income tax penalties as a component of other expense. For the three months ended March 31, 2020, and 2019, no penalties were recognized.

Coronavirus Aid, Relief and Economic Security (CARES Act)

On March 27, 2020, the CARES Act was enacted and signed into law in response to the COVID-19 pandemic. Among other provisions, the CARES Act includes modifications on the limitations of business interest for the 2019 and 2020 tax years. The modifications increase the allowable business interest deduction from 30% to 50% of adjusted taxable income. The modification increased Cleco’s allowable interest expense deduction and, as a result, decreased taxable income, creating larger net operating loss carryforwards for the tax year ended December 31, 2019. As a result of the CARES Act, Cleco does not expect any disallowed interest for the 2019 and 2020 tax years.

Note 11 — Disclosures about Segments

Cleco’s reportable segments are based on its method of internal reporting, which disaggregates business units by its first-tier subsidiary. Cleco’s reportable segments are Cleco Power and Cleco Cajun.

Each reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco’s CEO with discrete financial information and, at least quarterly, present discrete financial information to Cleco and Cleco Power’s Boards of Managers. The reportable segment prepares budgets that are presented to and approved by Cleco and Cleco Power’s Boards of Managers. The column shown as Other in the following tables includes the holding company, a shared services subsidiary, and an investment subsidiary. Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a reportable segment. For more information on the transaction, see Note 2 — “Business Combinations.” There are no other changes to Cleco’s existing reportable segments.

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The financial results in the following tables 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 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 as well as transmission services provided by Cleco Power to Cleco Cajun.

Segment Information For The Three Months Ended Mar. 31,
2020 (THOUSANDS)	CLECO POWER	CLECO CAJUN	OTHER	ELIMINATIONS	CONSOLIDATED
Revenue
Electric operations	$224,430	$89,147	$(2,420)	$—	$311,157
Other operations	15,764	30,961	1	(1,818)	44,908
Affiliate revenue	1,106	161	29,278	(30,545)	—
Electric customer credits	(8,340)	(153)	—	—	(8,493)
Operating revenue, net	$232,960	$120,116	$26,859	$(32,363)	$347,572
Depreciation and amortization	$43,677	$10,103	$2,094	$(1)	$55,873
Interest income	$954	$155	$100	$(52)	$1,157
Interest charges	$18,581	$10	$16,610	$(52)	$35,149
Federal and state income tax expense (benefit)	$3,338	$6,421	$(8,197)	$—	$1,562
Net income (loss)	$11,831	$19,535	$(25,039)	$1	$6,328
Additions to property, plant, and equipment	$61,477	$3,341	$806	$—	$65,624
Equity investment in investees	$17,072	$—	$—	$—	$17,072
Goodwill	$1,490,797	$—	$—	$—	$1,490,797
Total segment assets	$6,098,446	$1,020,099	$616,068	$(58,418)	$7,676,195

2019 (THOUSANDS)	CLECO POWER	CLECO CAJUN	OTHER	ELIMINATIONS	CONSOLIDATED
Revenue
Electric operations	$257,175	$58,194	$(2,420)	$—	$312,949
Other operations	19,430	19,965	2	—	39,397
Affiliate revenue	300	—	26,535	(26,835)	—
Electric customer credits	(8,160)	—	—	—	(8,160)
Operating revenue, net	$268,745	$78,159	$24,117	$(26,835)	$344,186
Depreciation and amortization	$42,377	$5,410	$2,069	$—	$49,856
Interest income	$994	$254	$417	$(174)	$1,491
Interest charges	$17,145	$—	$17,028	$(174)	$33,999
Federal and state income tax expense (benefit)	$7,998	$3,529	$(5,540)	$(1)	$5,986
Net income (loss)	$26,712	$11,056	$(17,210)	$(1)	$20,557
Additions to property, plant, and equipment	$81,040	$1,530	$1,109	$—	$83,679
Equity investment in investees(1)	$17,072	$—	$—	$—	$17,072
Goodwill(1)	$1,490,797	$—	$—	$—	$1,490,797
Total segment assets(1)	$5,967,327	$1,011,591	$546,096	$(48,716)	$7,476,298

(1)
Balances as of December 31, 2019

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Note 12 — Regulation and Rates

At March 31, 2020, Provision for rate refund on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets consisted primarily of $19.7 million for the estimated refund for the tax-related benefits from the TCJA, $3.5 million for the estimated refund related to the FERC audit, $2.2 million for the cost of service savings refunds, and $1.0 million for the change in transmission ROE. For more information about the FERC audit, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — FERC Audit.”

Transmission ROE

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. As of March 31, 2020, Cleco Power had $1.0 million accrued for the change in ROE. For more information on the ROE complaints, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE.”

FRP

Cleco Power’s annual retail earnings are subject to an FRP that was approved by the LPSC in June 2014. Under the terms of Cleco Power’s current FRP, Cleco Power is allowed to earn a target ROE of 10.0%, while providing the opportunity to earn up to 10.9%. Additionally, 60.0% of retail earnings between 10.9% and 11.75%, and all retail earnings over 11.75%, are required to be refunded to customers. The amount of credits due to customers, if any, is determined by Cleco Power and the LPSC, annually. Credits are typically included on customers’ bills the following summer, but the amount and timing of the refunds are ultimately subject to LPSC approval. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP, with anticipated new rates being effective July 1, 2020. Cleco Power has responded to several sets of data requests relating to the new FRP.

Cleco Power must file annual monitoring reports no later than October 31 for the 12-month period ending June 30. In January 2020, Cleco Power reached an agreement with the LPSC Staff regarding the treatment and realignment of SSR revenue between base and fuel revenue that resulted in $2.3 million of refunds for the 2018 monitoring report and confirmed no refunds for the 2017 monitoring report. The settlement also applies to treatment of SSR revenues for the 2019 monitoring report. The 2017 monitoring report was approved by the LPSC Staff on February 19, 2020. Cleco Power refunded the $2.3 million for the 2018 monitoring report in March 2020 as agreed to in the settlement of the 2017 monitoring report.

On April 30, 2020, the LPSC filed the uncontested Joint Report and Draft Order on Cleco Power’s FRP for the 12 months ended June 30, 2018. The conclusions were an earnings-related refund of $2.3 million, which was refunded on March 2020 bills, and no adjustments to rider FRP. Cleco Power expects approval on the 2018 monitoring report in the second quarter of 2020. Cleco Power has also responded to data requests relating to the 2019 FRP monitoring report.

Cleco Power’s monitoring reports also included a $1.2 million annual cost of service savings as a result of the 2016 Merger Commitments. The cost of service savings are not subject to the target ROE or any sharing mechanism. The cost of service savings are refunded annually in September and will continue until Cleco Power’s next FRP is in effect, which is expected in July 2020. At March 31, 2020, Cleco Power had $2.2 million accrued for the estimated cost of service savings refunds.

TCJA

The provisions of the TCJA reduced the top federal statutory corporate income tax rate from 35% to 21%. As a result of the tax rate reduction, on January 1, 2018, Cleco Power began accruing an estimated reserve for the reduction in the federal statutory corporate income tax rate. In February 2018, the LPSC directed utilities, including Cleco Power, to provide considerations of the appropriate manner to flow through to ratepayers the benefits of the reduction in corporate income taxes as a result of the TCJA. In July 2019, the LPSC approved Cleco Power’s rate refund of $79.2 million, plus interest, for the reduction in the statutory federal tax rate for the period from January 2018 to June 2020. The refund is being credited to customers over 12 months beginning August 1, 2019. At March 31, 2020, Cleco Power had $19.7 million accrued for the estimated federal tax-related benefits from the TCJA and $1.6 million accrued in related interest.

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Also, in July 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT, resulting from the enactment of the TCJA, in Cleco Power’s application for its next FRP, which was filed on June 28, 2019.

SSR

In September 2016, Cleco Power filed an Attachment Y with MISO requesting retirement of Teche Unit 3 effective April 1, 2017. MISO conducted a study which determined the proposed retirement of Teche Unit 3 would result in violations of specific applicable reliability standards for which no mitigation is available. As a result, MISO designated Teche Unit 3 as an SSR unit until such time that an appropriate alternative solution could be implemented to mitigate reliability issues. One mitigating factor identified was Cleco Power’s Terrebonne to Bayou Vista Transmission project, which was completed in April 2019. Cleco Power received a termination notice, effective April 30, 2019, and filed paperwork to withdraw the filed Attachment Y. While operating as an SSR unit, Cleco Power received monthly payments that included recovery of expenses, including capital expenditures, related to the operations of Teche Unit 3. Additionally, MISO allocated SSR costs to the load serving entities that required the operation of the SSR unit, including Cleco Power. These payments and cost allocations were finalized as part of a MISO SSR settlement approved in December 2018. Cleco Power operated Teche Unit 3 as an SSR unit from April 2017 until April 2019.

Cleco Power expects Teche Unit 3 to be available to run until the estimated 2021 in-service date of the Bayou Vista to Segura Transmission project, at which time Cleco Power does not expect to offer the unit into MISO, barring any grid or customer reliability issues or other similar reasons. At March 31, 2020, Cleco Power had $6.1 million accrued for the net capital refund for capital expenditures paid for by third parties while operating under the SSR agreement. As part of the settlement, one of the load serving entities agreed to reimburse Cleco Power for their portion of the capital refund. Management is unable to determine the timing of the capital refund.

Note 13 — Variable Interest Entities

Cleco and Cleco Power apply the equity method of accounting to report the investment in Oxbow in the consolidated financial statements. Under the equity method, the assets and liabilities of this entity are reported as Equity investment in investee on Cleco and Cleco Power’s Condensed 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 and Cleco Power’s Condensed Consolidated Statements of Income.

Oxbow is owned 50% by Cleco Power and 50% by SWEPCO. Cleco Power is not the primary beneficiary because it shares the power to control Oxbow’s significant activities with SWEPCO. Cleco Power’s current assessment of its maximum exposure to loss related to Oxbow at March 31, 2020, consisted of its equity investment of $17.1 million.

The following table presents the components of Cleco Power’s equity investment in Oxbow:

INCEPTION TO DATE (THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Purchase price	$12,873	$12,873
Cash contributions	6,399	6,399
Dividends	(2,200)	(2,200)
Total equity investment in investee	$17,072	$17,072

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

(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Oxbow’s net assets/liabilities	$34,145	$34,145
Cleco Power’s 50% equity	$17,072	$17,072
Cleco Power’s maximum exposure to loss	$17,072	$17,072

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The following table contains summarized financial information for Oxbow:

	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Operating revenue	$1,882	$1,958
Operating expenses	1,882	1,958
Income before taxes	$—	$—

DHLC mines lignite reserves at Oxbow through the Amended Lignite Mining Agreement. The lignite reserves are intended to be used to provide fuel to the Dolet Hills Power Station. For more information on DHLC and the Oxbow mine, see Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Risks and Uncertainties.”

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

Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Litigation

2016 Merger

In connection with the 2016 Merger, four actions were filed in the Ninth Judicial District Court for Rapides Parish, Louisiana and three actions were filed in the Civil District Court for Orleans Parish, Louisiana. The petitions in each action generally alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process, agreeing to the 2016 Merger at a price that allegedly undervalued Cleco, and failing to disclose material information about the 2016 Merger. The petitions also alleged that Como 1, Cleco Corporation, Merger Sub, and, in some cases, certain of the investors in Como 1 either aided and abetted or entered into a civil conspiracy to advance those supposed breaches of duty. The petitions sought various remedies, including monetary damages, which includes attorneys’ fees and expenses.

The four actions filed in the Ninth Judicial District Court for Rapides Parish are captioned as follows:

• Braunstein v. Cleco Corporation, No. 251,383B (filed October 27, 2014),

• Moore v. Macquarie Infrastructure and Real Assets, No. 251,417C (filed October 30, 2014),

• Trahan v. Williamson, No. 251,456C (filed November 5, 2014), and

• L’Herisson v. Macquarie Infrastructure and Real Assets, No. 251,515F (filed November 14, 2014).

In November 2014, the plaintiff in the Braunstein action moved for a dismissal of the action without prejudice, and that motion was granted in November 2014. In December 2014, the Court consolidated the remaining three actions and appointed interim co-lead counsel, and dismissed the investors in Cleco Partners as defendants, per agreement of the parties. Also, in December 2014, the plaintiffs in the consolidated action filed a Consolidated Amended Verified Derivative and Class Action Petition for Damages and Preliminary and Permanent Injunction.

The three actions filed in the Civil District Court for Orleans Parish were captioned as follows:

• Butler v. Cleco Corporation, No. 2014-10776 (filed November 7, 2014),

• Creative Life Services, Inc. v. Cleco Corporation, No. 2014-11098 (filed November 19, 2014), and

• Cashen v. Cleco Corporation, No. 2014-11236 (filed November 21, 2014).

In December 2014, the directors and Cleco filed declinatory exceptions in each action on the basis that each action was improperly brought in Orleans Parish and should either be transferred to the Ninth Judicial District Court for Rapides Parish or dismissed. Also, in December 2014, the plaintiffs in each action jointly filed a motion to consolidate the three actions pending in Orleans Parish and to appoint interim co-lead plaintiffs and co-lead counsel. In January 2015, the Court in the Creative Life Services case sustained the defendants’ declinatory exceptions and dismissed the case so that it could be transferred to the Ninth Judicial District Court for Rapides Parish. In February 2015, the plaintiffs in Butler and Cashen also consented to the dismissal of their

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cases from Orleans Parish so they could be transferred to the Ninth Judicial District Court for Rapides Parish. By operation of the December 2014 order of the Ninth Judicial District Court for Rapides Parish, the Butler, Cashen, and Creative Life Services actions were consolidated into the actions pending in Rapides Parish.

In February 2015, the Ninth Judicial District Court for Rapides Parish held a hearing on a motion for preliminary injunction filed by plaintiffs in the consolidated action seeking to enjoin the shareholder vote for approval of the Merger Agreement. The District Court heard and denied the plaintiffs’ motion. In June 2015, the plaintiffs filed their Second Consolidated Amended Verified Derivative and Class Action Petition. Cleco filed exceptions seeking dismissal of the second amended petition in July 2015. The LPSC voted to approve the 2016 Merger before the Court could consider the plaintiffs’ peremptory exceptions.

In March 2016 and May 2016, the plaintiffs filed their Third Consolidated Amended Verified Derivative Petition for Damages and Preliminary and Permanent Injunction and their Fourth Verified Consolidated Amended Class Action Petition, respectively. The fourth amended petition, which remains the operative petition and was filed after the 2016 Merger closed, eliminated the request for preliminary and permanent injunction and also named an additional executive officer as a defendant. The defendants filed exceptions seeking dismissal of the fourth amended Petition. In September 2016, and the District Court granted the exceptions of no cause of action and no right of action and dismissed all claims asserted by the former shareholders. The plaintiffs appealed the District Court’s ruling to the Louisiana Third Circuit Court of Appeal. In December 2017, the Third Circuit Court of Appeal issued an order reversing and remanding the case to the District Court for further proceedings. In January 2018, Cleco filed a writ with the Louisiana Supreme Court seeking review of the Third Circuit Court of Appeal’s decision. The writ was denied in March 2018 and the parties are engaged in discovery in the District Court. In November 2018, Cleco filed renewed exceptions of no cause of action and res judicata, seeking to dismiss all claims. On December 21, 2018, the court dismissed Cleco Partners and Cleco Holdings as defendants per the agreement of the parties, leaving as the only remaining defendants certain former executive officers and independent directors. The District Court denied the defendants’ exceptions on January 14, 2019. A hearing on the plaintiffs’ motion for certification of a class was scheduled for August 26, 2019; however, prior to the hearing, the parties reached an agreement to certify a limited class. On September 7, 2019, the District Court certified a class limited to shareholders who voted against, abstained from voting, or did not vote on the 2016 Merger. Cleco believes that the allegations of the petitions in each action are without merit and that it has substantial meritorious defenses to the claims set forth in each of the petitions.

Gulf Coast Spinning

In September 2015, a potential customer sued Cleco for failure to fully perform an alleged verbal agreement to lend or otherwise fund its startup costs to the extent of $6.5 million. Gulf Coast Spinning Company, LLC (Gulf Coast), the primary plaintiff, alleges that Cleco promised to assist it in raising approximately $60.0 million, which Gulf Coast needed to construct a cotton spinning facility near Bunkie, Louisiana. According to the petition filed by Gulf Coast in the 12^th Judicial District Court for Avoyelles Parish, Louisiana (the “District Court”), Cleco made such promises of funding assistance in order to cultivate a new industrial electric customer which would increase its revenues under a power supply agreement that it executed with Gulf Coast. Gulf Coast seeks unspecified damages arising from its inability to raise sufficient funds to complete the project, including lost profits.

Cleco filed an Exception of No Cause of Action arguing that the case should be dismissed. The District Court denied Cleco’s exception in December 2015, after considering briefs and arguments. In January 2016, Cleco appealed the District Court’s denial of its exception by filing with the Third Circuit Court of Appeal. In June 2016, the Third Circuit Court of Appeal denied the request to have the case dismissed. In July 2016, Cleco filed a writ to the Louisiana Supreme Court seeking a review of the District Court’s denial of Cleco’s exception. In November 2016, the Louisiana Supreme Court denied Cleco’s writ application.

In February 2016, the parties agreed to a stay of all proceedings pending discussions concerning settlement. In May 2016, the District Court lifted the stay at the request of Gulf Coast. The parties are currently participating in discovery. Cleco believes the allegations of the petition are contradicted by the written documents executed by Gulf Coast, are otherwise without merit, and that it has substantial meritorious defenses to the claims alleged by Gulf Coast.

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Sabine River Flood

In March 2017, Cleco was served with a summons in Perry Bonin, Ace Chandler, and Michael Manuel, et al v. Sabine River Authority of Texas and Sabine River Authority of Louisiana, No. B-160173-C. The action was filed in the 163rd Judicial District Court for Orange County, Texas, and relates to flooding that occurred in Texas and Louisiana in March 2016. The plaintiffs have alleged that the flooding was the result of the release of water from the Toledo Bend spillway gates into the Sabine River. While the plaintiffs have made numerous allegations, they have specifically alleged that Cleco Power, included as one of several companies and governmental bodies, failed to repair one of the two hydroelectric generators at the Toledo Bend Dam, which in turn contributed to the flooding. Cleco Power does not operate the hydroelectric generator.

The suit was removed to federal court in Texas. The new federal case is Perry Bonin, et al. v. Sabine River Authority of Texas et al., No. 17-cv-134, U.S. District Court for the Eastern District of Texas (Bonin Case). The plaintiffs moved to remand the case to state court, but the district court found that the case raises a substantial federal question and denied the motion to remand. Cleco Power, along with its co-defendants, filed a motion to dismiss on various grounds, primarily arguing that the plaintiffs’ claims are preempted because they infringe on FERC’s exclusive control of dam operations. The district court granted the motion to dismiss in part, declining to rule on some of the arguments raised by the defendants, and granted the plaintiffs leave to amend their complaint. The plaintiffs filed a Fifth Amended Complaint in March 2018. Cleco Power filed a new motion to dismiss the plaintiffs’ claims.

In March 2018, approximately 26 other individual plaintiffs filed a petition against Cleco Power and other defendants in Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. D180096-C. The action was filed in the 260th Judicial District Court for Orange County, Texas. The defendants removed the case to federal court in April 2018. The new federal case is Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. 18-cv-153, U.S. District Court for the Eastern District of Texas. The allegations are essentially identical to those in the Bonin Case. Also, in April 2018, Cleco Power filed a motion to dismiss on the same grounds that previously were successful in the Bonin Case. In July 2018, the district court entered an order consolidating the Addison Case with the Bonin Case. Management believes that both cases, as they relate to Cleco Power, have no merit. In August 2018, the Judge entered an order requiring the plaintiffs to file a more definitive statement to clarify the plaintiffs’ claims. In response thereto, the plaintiffs filed a Sixth Amended Petition in September 2018. Cleco Power filed a response in October 2018. All claims were dismissed against Cleco Power by ruling of the Judge on March 18, 2019. The plaintiffs filed an appeal of the dismissal with the United States Court of Appeals for the Fifth Circuit. The case is fully briefed before the Fifth Circuit Court of Appeals, and an oral argument was scheduled for the week of March 30, 2020; however, oral arguments have been delayed due to impacts from the COVID-19 pandemic.

Dispute with Saulsbury Industries

In October 2018, Cleco Power sued Saulsbury Industries, Inc., the former general contractor for the St. Mary Clean Energy Center project, seeking damages for Saulsbury Industries, Inc.’s failure to complete the St. Mary Clean Energy Center project on time and for costs incurred by Cleco Power in hiring a replacement general contractor. The action was filed in the Ninth Judicial District Court for Rapides Parish, No. 263339. Saulsbury Industries, Inc. removed the case to the U.S. District Court for the Western District of Louisiana, on March 1, 2019.

In January 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC, in the U.S. District Court for the Western District of Louisiana. Saulsbury Industries, Inc. alleging that Cleco Power and Cabot Corporation caused delays in the St. Mary Clean Energy Center project, resulting in alleged impacts to Saulsbury Industries, Inc.’s direct and indirect costs. On June 5, 2019, Cleco Power and Cabot Corporation each filed separate motions to dismiss. On October 24, 2019, the District Court denied Cleco’s motion as premature and ruled that Saulsbury Industries, Inc. had six weeks to conduct discovery on specified jurisdictional issues. The current procedural posture of the Western District of Louisiana case reflects a recognition by Cleco Power and Saulsbury Industries, Inc. that subject matter jurisdiction has not been established in relation to Cleco Power and Saulsbury Industries, Inc. and that this action, insofar as it relates to Cleco Power and Saulsbury Industries, Inc., will not proceed in federal court.

On October 10, 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC in the 16th Judicial District Court for St. Mary Parish, No. 133910-A.

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Saulsbury Industries, Inc. asserted the same claim as the Western District Litigation and further asserts claims for payment on an open account. On December 9, 2019, Cleco moved to stay the case, arguing that the Rapides Parish suit should proceed. On February 14, 2020, the court granted Cleco’s motion, which stay order remains in place until lifted.

LPSC Audits

Fuel Audit

Generally, Cleco Power’s cost of fuel used for electric generation and the cost of purchased power are recovered through the LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. Recovery of FAC costs is subject to periodic fuel audits by the LPSC. The LPSC FAC General Order issued in November 1997, in Docket No. U-21497 provides that an audit of FAC filings will be performed at least every other year. Cleco Power has FAC filings for January 2018 and thereafter that remain subject to audit. On April 21, 2020, Cleco Power received notice from the LPSC of its filing for Request For Proposals to hire outside consultants to perform the FAC audit for the period of January 2018 to December 2019. The total amount of fuel expense expected to be included in the audit is $565.8 million. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. Historically, the disallowances have not been material. If a disallowance of fuel cost is ordered resulting in a refund, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.

Environmental Audit

In 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides Cleco Power an EAC to recover from its customers certain costs of environmental compliance. 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. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. Cleco Power has EAC filings for January 2018 and thereafter that remain subject to audit. On March 11, 2020, Cleco Power received notice from the LPSC of its filing for Request For Proposals to hire outside consultants to perform the EAC audit for the period of January 2018 to December 2019. The total amount of environmental expense expected to be included in the audit is $26.2 million. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. Historically, the disallowances have not been material. If a disallowance of environmental cost is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.

Cleco Power incurs environmental compliance expenses for reagents associated with the compliance standards of Mercury and Air Toxics Standards (MATS). In June 2015, the U.S. Supreme Court remanded the MATS rule to the D.C. Circuit Court of Appeals. In December 2015, the D.C. Circuit Court of Appeals remanded the rule to the EPA; however, the D.C. Circuit Court of Appeals did not vacate this rule. In April 2016, the EPA released a final supplemental finding that, even considering costs, it is appropriate and necessary to regulate hazardous air pollutants. By the June 2016 deadline, six petitions were filed with the U.S. Court of Appeals for the D.C. Circuit Court of Appeals for review of the EPA’s findings. At the request of the EPA, in April 2017, the court issued an order holding the cases in abeyance pending the EPA’s review of its supplemental finding. These expenses are also eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC.

FERC Audit

Generally, Cleco Power records wholesale transmission revenue through approved formula rates, Attachment O of the MISO tariff and certain grandfathered agreements. The calculation of the rate formulas, as well as FERC accounting and reporting requirements, are subject to periodic audits by FERC. In March 2018, the Division of Audits and Accounting, within the Office of Enforcement of FERC, initiated an audit of Cleco Power for the period of January 1, 2014, through June 30, 2019. On September 27, 2019, Cleco Power received the final audit report, which indicated 12 findings of noncompliance with a combination of FERC accounting and

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reporting requirements and computation of revenue requirements along with 59 recommendations associated with the audit period. Cleco Power submitted a plan for implementing the audit recommendations on October 28, 2019. Cleco Power also submitted the refund analysis on November 7, 2019, which resulted in an estimated refund of $3.5 million related to the FERC audit findings, pending final assessment by the FERC Division of Audits and Accounting. This amount was recorded in Provision for rate refund on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020. Cleco Power anticipates this amount to be refunded to its wholesale transmission customers as a reduction in Attachment O and grandfathered agreement rates over 12 months beginning June 1, 2020.

Transmission ROE

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. The complaints sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 6.68%.

The complaints covered the period December 2013 through May 2016. In June 2016, an administrative law judge issued an initial decision in the second rate case docket recommending a 9.70% base ROE. In September 2016, FERC issued a Final Order in response to the first complaint establishing a 10.32% ROE. However, on November 21, 2019, FERC voted to adopt a new methodology for evaluating base ROE for public utilities under the Federal Power Act. In addition, FERC set the MISO transmission owners’ region-wide base ROE at 9.88% for the refund period covered in the first complaint and going forward. The draft FERC order further found that complainants in the second complaint proceeding failed to show that the 9.88% base ROE was unjust and unreasonable and thus dismissed the second complaint. Cleco Power is unable to determine when a final FERC Order will be issued. As of March 31, 2020, Cleco Power had $1.0 million accrued for the change in the ROE.

In November 2014, the MISO transmission owners committee, of which Cleco is a member, filed a request with FERC for an incentive to increase the new ROE by 50 basis points for RTO participation as allowed by the MISO tariff. In January 2015, FERC granted the request. Beginning January 1, 2020, the collection of the adder is being included in MISO’s transmission rates for a total ROE of 10.38%.

South Central Generating

In 2017, Louisiana Generating received insurance settlement proceeds for costs incurred to resolve a lawsuit which was brought by the EPA and the LDEQ against Louisiana Generating related to Big Cajun II, Unit 3. Entergy Gulf States, as co-owner of Big Cajun II, Unit 3, is expected to be allocated a portion of the insurance settlement proceeds. Any amount allocated to Entergy Gulf States will be determined by ongoing litigation and negotiations. South Central Generating estimated this amount to be $10.0 million. As part of the Cleco Cajun Transaction, Cleco Cajun assumed the $10.0 million contingent liability and NRG Energy indemnified Cleco for losses associated with this litigation matter. As a result, Cleco also recorded a $10.0 million indemnification asset, which was included in the purchase price allocation.

Prior to the Cleco Cajun Transaction, South Central Generating was involved in various litigation matters, including environmental and contract proceedings, before various courts regarding matters arising out of the ordinary course of business. Management is unable to estimate any potential losses that Cleco Cajun may ultimately be responsible for with respect to any one of these matters. As part of the Cleco Cajun Transaction, NRG Energy indemnified Cleco for losses as of the closing date associated with matters that existed as of the closing date, including pending litigation.

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 may be in excess of amounts currently accrued. Management regularly analyzes current information and, as of March 31, 2020, believes the probable and reasonably estimable liabilities based on the eventual disposition of these matters are $5.1 million and has accrued this amount.

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Off-Balance Sheet Commitments and Guarantees

Cleco Holdings 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 Holdings’ subsidiaries and equity investees (affiliates). Cleco Holdings and Cleco Power have also agreed to contractual terms that require the Registrants to pay third parties if certain triggering events occur. These contractual terms generally are defined as guarantees.

Cleco Holdings 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 Holdings had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco and Cleco Power’s Consolidated Balance Sheets because management has determined that Cleco and Cleco Power’s affiliates are able to perform the obligations under their contracts and that it is not probable that payments by Cleco or Cleco Power will be required.

Cleco Holdings provided guarantees and indemnities to Entergy Louisiana and Entergy Gulf States as a result of the sale of the Perryville generation facility in 2005. The remaining indemnifications relate to environmental matters that may have been present prior to closing. These remaining indemnifications have no time limitations. The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million. Management does not expect to be required to pay Entergy Louisiana and Entergy Gulf States under these guarantees.

On behalf of Acadia, Cleco Holdings provided guarantees and indemnifications as a result of the sales of Acadia Unit 1 to Cleco Power and Acadia Unit 2 to Entergy Louisiana in 2010 and 2011, respectively. The remaining indemnifications relate to the fundamental organizational structure of Acadia. These remaining indemnifications have no time limitations or maximum potential future payments. Management does not expect to be required to pay Cleco Power or Entergy Louisiana under these guarantees.

Cleco Holdings provided indemnifications to Cleco Power as a result of the transfer of Coughlin to Cleco Power in March 2014. Cleco Power also provided indemnifications to Cleco Holdings and Evangeline as a result of the transfer of Coughlin to Cleco Power. The maximum amount of the potential payment to Cleco Power, Cleco Holdings, and Evangeline for their respective indemnifications is $40.0 million, except for indemnifications relating to the fundamental organizational structure of each respective entity, of which the maximum amount is $400.0 million. Management does not expect to be required to make any payments under these indemnifications.

As part of the Amended Lignite Mining Agreement, Cleco Power and SWEPCO, joint owners of Dolet Hills Power Station, have agreed to pay the loan and lease principal obligations of the lignite miner, DHLC, when due if DHLC 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 future invoices for lignite delivered. The maximum projected payment by Cleco Power under this guarantee is estimated to be $83.0 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. In April 2020, Cleco Power and SWEPCO mutually agreed to not develop additional mining areas for future lignite extraction and subsequently provided notice to the LPSC of the intent to cease mining at the Dolet Hills and Oxbow mines by June 2020. The mine closure is subject to LPSC review and approval. The Amended Lignite Mining Agreement 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 this guarantee.

At March 31, 2020, Cleco Holdings had a $34.5 million letter of credit to MISO pursuant to energy market requirements related to Cleco Cajun’s participation in MISO. The letter of credit automatically renews each year and has no impact on the Cleco Holdings’ credit facility.

Generally, neither Cleco Holdings nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations. There are no assets held as collateral for third parties that either Cleco Holdings or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees or indemnification obligations.

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Other Commitments

Cleco has accrued for liabilities related to third parties, employee medical benefits, and AROs.

Risks and Uncertainties

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

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.

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 and Cleco’s financial condition could be materially adversely affected.

Cleco Power and Cleco Cajun are participants in the MISO market. Energy prices in the MISO market are based on LMP, which includes a component directly related to congestion on the transmission system. Pricing zones with greater transmission congestion may have higher LMPs. Physical transmission constraints present in the MISO market could increase energy costs within pricing zones. Cleco Power and Cleco Cajun use FTRs to mitigate transmission congestion price risks. Changes to anticipated transmission paths may result in an unexpected increase in energy costs.

On March 1, 2019, Cleco Power began to operate Dolet Hills Power Station from June through September of each year; however, Dolet Hills Power Station will continue to be available to operate in other months, if needed. In January 2020, Cleco Power’s joint owner in Dolet Hills Power Station unilaterally entered into a settlement with the Arkansas Public Service Commission to seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. This settlement does not bind Cleco Power to agree to retire the Dolet Hills Power Station by 2026.

In April 2020, Cleco Power and SWEPCO mutually agreed to not develop additional mining areas for future lignite extraction and subsequently provided notice to the LPSC of the intent to cease mining at the Dolet Hills and Oxbow mines by June 2020, subject to LPSC review and approval. Early closure of the mines would most likely result in increased costs billed through fuel, which management currently believes are recoverable. Management does not believe an early closure of the mines would have an adverse impact on the recovery value of the plant. Cleco Power has the ability to secure alternative fuel sources and expects to have sufficient lignite fuel available to continue seasonal operations of the Dolet Hills Power Station through at least the 2020 and 2021 seasonal operations periods. Also in April 2020, Cleco Power announced its intent to seek regulatory approval to retire the Dolet Hills Power Station at the end of 2021, subject to recovery mechanisms. This does not bind Cleco Power to a specific retirement plan and Cleco Power will continue to evaluate the cost of operating the Dolet Hills Power Station compared with other alternatives and decide the best course of action for the Dolet Hills Power Station within the LPSC regulatory requirements and recovery mechanisms.

Note 15 — Affiliate Transactions

At March 31, 2020, Cleco had an affiliate payable of $33.8 million to Cleco Group primarily for affiliate settlement of taxes payable.

Cleco Power has balances that are payable to or due from its affiliates. The following table is a summary of those balances:

	AT MAR. 31, 2020		AT DEC. 31, 2019
(THOUSANDS)	ACCOUNTS RECEIVABLE	ACCOUNTS PAYABLE	ACCOUNTS RECEIVABLE	ACCOUNTS PAYABLE
Cleco Holdings	$10,420	$170	$10,351	$194
Support Group	1,082	10,197	3,172	13,890
Cleco Cajun	535	119	958	39
Total	$12,037	$10,486	$14,481	$14,123

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Note 16 — Intangible Assets and Liabilities

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 was fully amortized in March 2020 and had no residual value at the end of its life.

As a result of the 2016 Merger, fair value adjustments were recorded on Cleco’s Condensed Consolidated Balance Sheet for the valuation of the Cleco trade name and long-term wholesale power supply agreements. At the end of their life, these intangible assets will have no residual value. The trade name intangible asset is being amortized over its estimated economic useful life of 20 years. The intangible assets related to the power supply agreements are amortized over the estimated life of each applicable contract ranging between 7 and 19 years and the amortization is included in Electric operations on Cleco’s Condensed Consolidated Statements of Income.

As a result of the Cleco Cajun Transaction, fair value adjustments were recorded on Cleco’s Condensed Consolidated Balance Sheet for the difference between the contract and market price of acquired long-term wholesale power agreements. The fair value of intangible assets of $98.9 million and intangible liabilities of $14.2 million was reflected in the purchase price allocation. At the end of their life, these intangible assets and liabilities will have no residual value. These intangibles are amortized over the estimated life of each applicable contract ranging between 2 and 8 years. The amortization is included in Electric operations on Cleco’s Condensed Consolidated Statements of Income.

As part of the Cleco Cajun Transaction, Cleco assumed an LTSA for maintenance services related to the Cottonwood Plant. An intangible liability of $24.1 million was reflected in the purchase price allocation and is being amortized using the straight-line method over the estimated life of the LTSA of seven years. The amortization is included as a reduction to the LTSA prepayments on Cleco’s Condensed Consolidated Balance Sheet. For more information on the fair value adjustments of intangible assets and liabilities related to the Cleco Cajun Transaction, see Note 2 — “Business Combinations.”

The following tables present Cleco and Cleco Power’s amortization of intangible assets and liabilities:

Cleco
	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Intangible assets
Cleco Katrina/Rita right to bill and collect storm recovery charges	$517	$4,870
Trade name	$64	$64
Power supply agreements	$6,400	$5,190
Intangible liabilities
LTSA	$871	$581
Power supply agreements	$882	$211

Cleco Power
	FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)	2020	2019
Cleco Katrina/Rita right to bill and collect storm recovery charges	$517	$4,870

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The following tables summarize the balances for intangible assets and liabilities subject to amortization for Cleco and Cleco Power:

Cleco
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Intangible assets
Cleco Katrina/Rita right to bill and collect storm recovery charges	$70,594	$70,594
Trade name	5,100	5,100
Power supply agreements	184,004	184,004
Total intangible assets carrying amount	259,698	259,698
Intangible liabilities
LTSA	24,100	24,100
Power supply agreements	14,200	14,200
Total intangible liability carrying amount	38,300	38,300
Net intangible assets carrying amount	221,398	221,398
Accumulated amortization	(120,395)	(115,167)
Net intangible assets subject to amortization	$101,003	$106,231

Cleco Power
(THOUSANDS)	AT MAR. 31, 2020	AT DEC. 31, 2019
Cleco Katrina/Rita right to bill and collect storm recovery charges	$177,537	$177,537
Accumulated amortization	(177,537)	(177,020)
Net intangible assets subject to amortization	$—	$517

Note 17 — Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss are summarized in the following tables for Cleco and Cleco Power. All amounts are reported net of income taxes. Amounts in parentheses indicate debits.

Cleco
	FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)	POSTRETIREMENT BENEFIT NET LOSS
Balances, beginning of period	$(17,513)
Amounts reclassified from AOCI
Amortization of postretirement benefit net gain	414
Balances, Mar. 31, 2020	$(17,099)

	FOR THE THREE MONTHS ENDED MAR. 31, 2019
(THOUSANDS)	POSTRETIREMENT BENEFIT NET GAIN
Balances, beginning of period	$1,786
Amounts reclassified from AOCI
Amortization of postretirement benefit net loss	(135)
Balances, Mar. 31, 2019	$1,651

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Cleco Power
	FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)	POSTRETIREMENT BENEFIT NET LOSS	NET LOSS ON CASH FLOW HEDGES	TOTAL AOCI
Balances, beginning of period	$(16,717)	$(5,868)	$(22,585)
Amounts reclassified from AOCI
Amortization of postretirement benefit net loss	426	—	426
Reclassification of net loss to interest charges	—	64	64
Balances, Mar. 31, 2020	$(16,291)	$(5,804)	$(22,095)

	FOR THE THREE MONTHS ENDED MAR. 31, 2019
(THOUSANDS)	POSTRETIREMENT BENEFIT NET LOSS	NET LOSS ON CASH FLOW HEDGES	TOTAL AOCI
Balances, beginning of period	$(7,060)	$(6,122)	$(13,182)
Amounts reclassified from AOCI
Amortization of postretirement benefit net loss	156	—	156
Reclassification of net loss to interest charges	—	64	64
Balances, Mar. 31, 2019	$(6,904)	$(6,058)	$(12,962)

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