Cleco Corporate S-4 Registration of securities issued in business combination transactions

As filed with the Securities and Exchange Commission on March 17, 2017

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

CLECO CORPORATE HOLDINGS LLC

(Exact name of registrant as specified in its charter)

Louisiana	4911	72-1445282
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code)	(I.R.S. Employer Identification No.)

2030 Donahue Ferry Road

Pineville, Louisiana 71360-5226

(318) 484-7400

(Address, Including ZIP Code, and Telephone Number,

Including Area Code, of Registrant’s Principal Executive Offices)

Julia E. Callis

Chief Compliance Officer and General Counsel

2030 Donahue Ferry Road

Pineville, Louisiana 71360-5226

(318) 484-7400

(Name, Address, Including ZIP Code and Telephone Number,

Including Area Code, of Agent for Service)

with a copy to:

Michelle A. Earley, Esq.

David F. Taylor, Esq.

600 Congress Avenue

Suite 2200

Austin, TX 78701-3055

(512) 305-4700

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this registration statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer) ☐

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer) ☐

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered	Amount to be registered	Proposed maximum offering price per unit(1)	Proposed maximum aggregate offering price(1)	Amount of registration fee(1)
3.743% Senior Secured Notes due 2026	$535,000,000	100%	$535,000,000	$62,006.50
4.973% Senior Secured Notes due 2046	$350,000,000	100%	$350,000,000	$40,565.00

(1) This registration fee has been calculated pursuant to Rule 457(f)(2) under the Securities Act of 1933, as amended.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion dated March 17, 2017

Prospectus

Cleco Corporate Holdings LLC

Offer to Exchange

up to $535,000,000 3.743% Senior Secured Notes due 2026

for a like principal amount of 3.743% Senior Secured Notes due 2026,

which have been registered under the Securities Act and

up to $350,000,000 4.973% Senior Secured Notes due 2046

for a like principal amount of 4.973% Senior Secured Notes due 2046,

which have 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 pm, New York City time, on             , 2017, unless we extend the offer. We currently do not intend to extend the expiration date.

• 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.

• We do not intend to apply for listing of the Exchange Notes on any securities exchange or to arrange for them 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 that it will deliver a prospectus in connection with any resale of such Exchange Notes. The letter of transmittal states that by so acknowledging and delivering a prospectus, a 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, for a period of 180 days after consummation of the exchange offer, 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.

The date of this prospectus is             , 2017

No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You should not rely on any unauthorized information or representations. This prospectus is an offer to exchange only the Notes offered by this prospectus, and only under the circumstances and in those jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

TABLE OF CONTENTS

CERTAIN DEFINITIONS	ii
PRESENTATION OF FINANCIAL INFORMATION	iv
NON-GAAP FINANCIAL MEASURES	v
FORWARD-LOOKING STATEMENTS	v
SUMMARY	1
SUMMARY CONSOLIDATED FINANCIAL INFORMATION	12
RISK FACTORS	14
USE OF PROCEEDS	35
CAPITALIZATION	36
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
BUSINESS	71
PROPERTIES	86
LEGAL PROCEEDINGS	87
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	88
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	91
MANAGEMENT	92
EXECUTIVE COMPENSATION	98
PRINCIPAL OWNERS	131
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	132
THE EXCHANGE OFFER	133
DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS	142
DESCRIPTION OF THE EXCHANGE NOTES	144
REGISTRATION RIGHTS AGREEMENT	177
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS	179
PLAN OF DISTRIBUTION	185
LEGAL MATTERS	186
EXPERTS	186
WHERE YOU CAN FIND MORE INFORMATION	186
EXCHANGE AGENT	188
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS	F-1

i

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 Notes, in which case such terms refer only to Cleco Corporate Holdings LLC; the term “Outstanding Notes” refers to the outstanding 3.743% Senior Secured Notes due 2026 and the outstanding 4.973% Senior Secured Notes due 2046; the term “Exchange Notes” refers to the 3.743% Senior Secured Notes due 2026 registered under the Securities Act and the 4.973% Senior Secured Notes due 2046 registered under the Securities Act; 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:

ABBREVIATION OR ACRONYM	DEFINITION
401(k) Savings 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
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
Amended Lignite Mining Agreement	Amended and restated lignite mining agreement effective December 29, 2009
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ARRA	American Recovery and Reinvestment Act of 2009
Attala	Attala Transmission LLC, a wholly owned subsidiary of Cleco Holdings
bcIMC	British Columbia Investment Management Corporation
Brame Energy Center	A facility consisting of Nesbitt Unit 1, Rodemacher Unit 2, and Madison Unit 3
CAA	Clean Air Act
CCR	Coal combustion by-products or residual
CEO	Chief Executive Officer
Cleco	Cleco Holdings and its subsidiaries
Cleco Group	Cleco Group LLC, a wholly owned subsidiary of Cleco Partners
Cleco Holdings	Cleco Corporate Holdings LLC
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, bcIMC, John Hancock Financial, and other infrastructure investors.
Cleco Power	Cleco Power LLC and its subsidiaries, a wholly owned subsidiary of Cleco Holdings
CO2	Carbon dioxide
Coughlin	Cleco Power’s 775-MW, combined-cycle power plant located in St. Landry, Louisiana
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
DHLC	Dolet Hills Lignite Company, LLC, a wholly owned subsidiary of SWEPCO

ii

ABBREVIATION OR ACRONYM	DEFINITION
Diversified Lands	Diversified Lands LLC, a wholly owned subsidiary of Cleco Holdings
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE	U.S. Department of Energy
Dolet Hills	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
EBITDA	Earnings (losses) before Interest, Taxes, Depreciation, and Amortization
EGU	Electric Generating Unit
Entergy Gulf States	Entergy Gulf States Louisiana, L.L.C.
Entergy Louisiana	Entergy Louisiana, LLC
EPA	U.S. Environmental Protection Agency
ERO	Electric Reliability Organization
ESPP	Employee Stock Purchase Plan
Evangeline	Cleco Evangeline LLC, a wholly owned subsidiary of Midstream
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTR	Financial Transmission Right
FRP	Formula Rate Plan
GAAP	Generally Accepted Accounting Principles in the U.S.
GO Zone	Gulf Opportunity Zone Act of 2005 (Public Law 109-135)
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
ISO	Independent System Operator
kWh	Kilowatt-hour(s)
LDEQ	Louisiana Department of Environmental Quality
LED	Louisiana Economic Development
LIBOR	London Interbank Offered Rate
LMP	Locational Marginal Price
LPSC	Louisiana Public Service Commission
LTIP	Long-Term Incentive Compensation Plan
Madison Unit 3	A 641-MW generating unit at Cleco Power’s plant site in Boyce, Louisiana
MATS	Mercury and Air Toxics Standards
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
Merger Agreement	Agreement and Plan of Merger, dated as of October 17, 2014, by and among Cleco Partners, Merger Sub, and Cleco Corporation
Merger Commitments	Cleco Partners’, 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
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 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
MIP	Macquarie Infrastructure Partners Inc.
MIRA	Macquarie Infrastructure and Real Assets Inc.
MISO	Midcontinent Independent System Operator, Inc.
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, a credit rating agency
MSCI EAFE Index	Morgan Stanley Capital International Europe, Australia, Far East Index

iii

ABBREVIATION OR ACRONYM	DEFINITION
MW	Megawatt(s)
MWh	Megawatt-hour(s)
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NMTC	New Markets Tax Credit
NMTC Fund	USB NMTC Fund 2008-1 LLC was formed to invest in projects qualifying for New Markets Tax Credits and Solar Projects
NOAA	National Oceanic and Atmospheric Administration
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 oxides
NYSE	New York Stock Exchange
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
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordable Care Act, as amended
ppb	Parts per billion
Predecessor	Pre-merger activity of Cleco. Cleco has accounted for the merger transaction by applying the acquisition method of accounting. The predecessor period is not comparable to the successor period.
RFP	Request for Proposal
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
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Services, a credit rating agency
SEC	U.S. Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
SPP RE	Southwest Power Pool Regional Entity
Successor	Post-merger activity of Cleco. Cleco has accounted for the 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.

PRESENTATION OF FINANCIAL INFORMATION

The Issuer of the Notes is Cleco Corporate Holdings LLC, a Louisiana limited liability company. Cleco Corporate Holdings LLC, successor to Cleco Corporation, was converted from a Louisiana corporation to a Louisiana limited liability company in connection with the Transactions (as defined herein). The consolidated financial information prior to April 13, 2016 (the effective date of the conversion) included in this prospectus is historical financial information of Cleco Corporation and its consolidated subsidiaries.

iv

NON-GAAP FINANCIAL MEASURES

We refer to the term Adjusted EBITDA in various places in this prospectus. We define Adjusted EBITDA as the sum of (1) net income, (2) depreciation and amortization, (3) income tax expense, (4) interest expense and (5) other nonrecurring expenses related to the Merger (as defined herein). This measure is a supplemental financial measure that is not prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). Any analysis of non-GAAP financial measures should be used only in conjunction with results presented in accordance with GAAP.

We use Adjusted EBITDA, along with other measures, to assess our overall financial and operating performance. We believe that Adjusted EBITDA, a non-GAAP measure, as we have defined it, is useful in identifying trends in our performance because it excludes items that have little or no significance to our day-to-day operations. This measure provides an assessment of controllable expenses and affords management the ability to make decisions that are expected to facilitate meeting current financial goals, as well as achieve optimal financial performance. This measure also provides indicators for management to determine if adjustments to current spending levels are needed.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

• Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

• Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

• Adjusted EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

• although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

• other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.

Because of these limitations, Adjusted EBITDA should not be considered as a measure of discretionary cash available to us to invest in our business. We compensate for these limitations by relying primarily on our GAAP result and using Adjusted EBITDA only supplementally. For a description of how Adjusted EBITDA is calculated and a reconciliation of Adjusted EBITDA to net income, see note (4) to the table set forth in “Summary—Summary Consolidated Historical Financial Information” in this prospectus.

FORWARD-LOOKING STATEMENTS

Certain statements included in this prospectus may be “forward-looking statements” within the meaning of the Securities Act and 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.

v

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 effects of the Merger on April 13, 2016, on the business relationships, operating results, and business generally of Cleco and Cleco Power;

• regulatory factors such as changes in rate-setting practices or policies, the unpredictability in 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 Formula Rate Plan extensions may have on operating decisions of Cleco Power, the results of periodic NERC and LPSC audits, participation in MISO and the related operating challenges and uncertainties, including increased wholesale competition relative to more suppliers, and compliance with the Electric Reliability Organization Enterprise’s reliability standards for bulk power systems by Cleco Power;

• the ability to recover fuel costs through the fuel adjustment clause;

• 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; unscheduled generation outages; unanticipated maintenance or repairs; unanticipated changes to fuel costs or fuel supply costs, fuel shortages, transportation problems, or other developments; fuel mix of our generating facilities; decreased customer load; environmental incidents and compliance costs; and power transmission system constraints;

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

• global and domestic economic conditions, including the ability of customers to continue paying utility bills, related growth and/or down-sizing of businesses in our service area, monetary fluctuations, changes in commodity prices and inflation rates;

• the ability of the lignite reserves at Dolet Hills to provide sufficient fuel to the Dolet Hills Power Station until at least 2036;

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

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

• reliability of Cleco Power’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 coal combustion by-products or residual, greenhouse gases and energy efficiency that could limit or terminate the operation of certain generating units, increase costs or reduce customer demand for electricity;

• our ability to recover the costs of compliance with environmental laws and regulations, including those through the environmental adjustment clause;

• financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, Federal Energy Regulatory Commission, 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 and energy service activities, including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, interest rates and warranty risks;

vi

• 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 tax laws), changes in tax rates, disallowances of tax positions or changes in other regulating policies that may result in a change to tax benefits or expenses;

• the restriction on the ability of Cleco Power to make distributions to the Issuer in certain instances, as agreed to as part of the regulatory commitments made to the LPSC in connection with the Merger;

• our holding company structure and our dependence on the earnings, dividends or distributions from our subsidiaries to meet our debt obligations;

• acts of terrorism, cyber-attacks, data security breaches or other attempts to disrupt our business or the business of third parties, or other man-made disasters;

• nonperformance by and creditworthiness of the guarantor counterparty of the USB NMTC Fund 2008-1 LLC;

• our credit ratings and those of Cleco Power;

• ability to remain in compliance with debt covenants;

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

• employee work force factors, including work stoppages, aging workforce and changes in management; 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 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.

vii

SUMMARY

This summary highlights certain information about our business and about this offering of the Exchange Notes. 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. Unless the context otherwise requires, in this prospectus “we,” “us” and “our” refer to Cleco and its consolidated subsidiaries; the term “Outstanding Notes” refers to the outstanding 3.743% Senior Secured Notes due 2026 and the outstanding 4.973% Senior Secured Notes due 2046; the term “Exchange Notes” refers to the 3.743% Senior Secured Notes due 2026 registered under the Securities Act and the 4.973% Senior Secured Notes due 2046 registered under the Securities Act; and the term “Notes” refers to both the Outstanding Notes and the Exchange Notes.

Overview

Cleco is a regional energy company that conducts substantially all of its business operations through its primary subsidiary, Cleco Power LLC (“Cleco Power”), which engages primarily in the generation, transmission, distribution and sales of electricity. Cleco Power is a regulated electric utility company that owns nine generating units with a total nameplate capacity of 3,310 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi.

Since our operations are primarily conducted through Cleco Power, our 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 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.

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, in connection with the Merger (as defined below), 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. Cleco is a public utility holding company which holds investments in several subsidiaries, including Cleco Power. Substantially all of our operations are conducted through Cleco Power. 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 atwww.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.

The Merger

On October 17, 2014, the Company (through its predecessor, Cleco Corporation) entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Cleco Partners L.P., a Delaware limited partnership (“Parent”), and Cleco MergerSub, Inc., a Delaware corporation and a wholly owned subsidiary of Parent (“Merger Sub”). Parent is controlled by investment vehicles associated with Macquarie Infrastructure and Real Assets, British Columbia Investment Management Corporation and John Hancock Financial. Pursuant to the Merger Agreement, upon the terms and subject to the conditions thereof, Merger Sub merged with and into the Company, with the Company surviving as a wholly owned subsidiary of Parent (the “Merger”). The Merger was consummated on April 13, 2016.

1

In connection with obtaining regulatory approval for the Merger from the Louisiana Public Service Commission (“LPSC”), we agreed to certain regulatory commitments, including commitments to (i) provide rate credits of $136 million posted to an escrow account for the benefit of retail customers accounts in the residential and small commercial customer classes, (ii) provide additional economic development funding of $7 million and (iii) maintain rates in accordance with our existing formula rate plan until 2020.

Financing of the Merger

In connection with the closing of the Merger, the Company entered in to senior secured credit facilities (the “Senior Secured Credit Facilities”) providing for a $100.0 million five-year revolving credit facility (the “Revolving Credit Facility”) and a $1,350.0 million acquisition loan facility, which would become due in 2019 (the “Acquisition Loan Facility”). Funds from the Acquisition Loan Facility were used to finance the Merger and the Acquisition Loan Facility was subsequently refinanced and repaid, as described below under “Repayment of Acquisition Loan Facility”.

We refer to the Merger, an equity contribution by Parent, the borrowings under the Revolving Credit Facility and Acquisition Loan Facility, the offering and sale of the Outstanding Notes, and the application of the proceeds therefrom and the other transactions described above as the “Transactions.”

Repayment of Acquisition Loan Facility

In May and June 2016, the Company refinanced the Acquisition Loan Facility with a series of other long-term financings as follows:

• On May 17, 2016, the Company completed the private sale of the Outstanding Notes.

• On May 24, 2016, the Company completed the private sale of $165.0 million of 3.250% Senior Secured Notes due May 2023 (the “3.250% Senior Notes”).

• On June 28, 2016, the Company entered into a $300.0 million variable rate bank term loan due June 28, 2021 (the “Term Loan”).

The proceeds from the issuance and sale of the Outstanding Notes, the 3.250% Senior Notes, and the Term Loan were used to repay the Acquisition Loan Facility. See “Description of Certain Other Indebtedness—Cleco”.

About our Parent

Parent is a Delaware limited partnership that was formed solely for the purpose of entering into the Merger Agreement and consummating the transactions contemplated by the Merger Agreement. Parent has not conducted any activities to date other than activities incidental to its formation and in connection with the transactions contemplated by the Merger Agreement. Parent was formed by MIP Cleco Partners L.P. (an affiliate of Macquarie Infrastructure Partners III, L.P.) and is owned and managed by a consortium of investors, including MIP Cleco Partners L.P., affiliates of British Columbia Investment Management Corporation and John Hancock Financial.

Macquarie Infrastructure Partners III

Macquarie Infrastructure Partners III, L.P. and Macquarie Infrastructure Partners III (PV), L.P. (collectively, “MIP III”) are Delaware limited partnerships headquartered in New York. MIP III is a diversified, unlisted fund focusing on infrastructure investments in the United States and Canada. MIP III is managed by an entity within the Macquarie Infrastructure and Real Assets operating division of Macquarie Group Limited (“MIRA”).

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British Columbia Investment Management Corporation

British Columbia Investment Management Corporation (“bcIMC”) is based in Victoria, British Columbia and is a long-term institutional investor that invests in all major asset classes, including infrastructure and other strategic investments. bcIMC manages investments across asset classes and invests on behalf of public sector pension plans, the Province of British Columbia, provincial government bodies including Crown corporations and institutions, and publicly administered trust funds.

John Hancock Financial

John Hancock Financial is a division of Manulife, a Canada-based financial services group with principal operations in Asia, Canada and the United States. Operating as Manulife in Canada and Asia and primarily as John Hancock in the United States, the group of companies offers clients a diverse range of financial protection products and wealth management services through its network of employees, agents, and distribution partners.

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SUMMARY OF THE EXCHANGE OFFER

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, among other things, 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:

• $535.0 million aggregate principal amount of outstanding 3.743% Senior Secured Notes due 2026 which have not been registered under the Securities Act (“2026 Outstanding Notes”) for up to $535.0 million aggregate principal amount of 3.743% Senior Secured Notes due 2026 which have been registered under the Securities Act (“2026 Exchange Notes”, and together with the 2026 Outstanding Notes, the “2026 Notes”), and

• $350.0 million aggregate principal amount of outstanding 4.973% Senior Secured Notes due 2046 which have not been registered under the Securities Act (“2046 Outstanding Notes”) for up to $350.0 million aggregate principal amount of 4.973% Senior Secured Notes due 2046 which have been registered under the Securities Act (“2046 Exchange Notes” and together with the 2046 Outstanding Notes, the “2046 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 this 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.

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

Expiration Date This exchange offer will expire at 5:00 p.m., New York City time, on             , 2017, unless we extend the offer.

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 or 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.

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See “The Exchange Offer—Procedures for Tendering.”

Guaranteed Delivery Procedures for Tendering Outstanding Notes If you cannot meet the expiration deadline or you cannot deliver your Outstanding Notes, the letter of transmittal or any other documentation to comply with the applicable procedures under DTC, Euroclear or Clearstream standard operating procedures for electronic tenders in a timely fashion, you may tender your notes according to the guaranteed delivery procedures set forth under “The Exchange Offer—Guaranteed Delivery Procedures.”

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 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 this exchange offer expires. The Exchange Notes will be delivered promptly after expiration of this 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 this 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 this exchange offer expires.

Consequences if You Do Not Exchange Your 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.

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

United States Federal Income Tax Considerations 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 “Material United States Federal Income Tax Considerations.”

Exchange Agent Wells Fargo Bank, N.A.

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

Registration Rights Agreement When we issued the Outstanding Notes on May 17, 2016, 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 210 and 270 days of such date, respectively, 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 became obligated to pay additional interest on the Outstanding Notes until 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 generally accepted accounting principles. See “The Exchange Offer—Accounting Treatment.”

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SUMMARY OF THE TERMS OF THE EXCHANGE NOTES

The Exchange Notes will be identical to 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 debt as the 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 (successor to Cleco Corporation)

Notes Offered $885 million aggregate principal amount of Exchange Notes consisting of:

• $535 million aggregate principal amount of 2026 Exchange Notes, and

• $350 million aggregate principal amount of 2046 Exchange Notes,

ranking pari passu to one another.

Interest Rate 2026 Notes: 3.743% per annum, and

2046 Notes: 4.973% per annum.

Maturity Date The 2026 Notes will mature on May 1, 2026 and the 2046 Notes will mature on May 1, 2046, unless such series of Notes are redeemed in whole as described below under “Description of the Exchange Notes—Optional Redemption.”

Interest Payment Dates May 1 and November 1 of each year, with the next payment due on May 1, 2017.

Optional Redemption At any time and from time to time prior to February 1, 2026 in the case of the 2026 Notes or November 1, 2045 in the case of the 2046 Notes, we may, at our option, redeem the Notes in whole or in part, at any time, at a redemption price equal to the greater of (a) 100% of the principal amount of the Notes then outstanding to be redeemed and (b) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed that would be due if such Notes matured on February 1, 2026 in the case of the 2026 Notes and November 1, 2045 in the case of the 2046 Notes (not including any portion of such interest payments accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus 30 basis points for the 2026 Notes and plus 40 basis points for the 2046 Notes, respectively, plus in either case, accrued and unpaid interest, including additional interest, thereon to, but excluding, the date of redemption.

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At any time on or after February 1, 2026 in the case of the 2026 Notes or November 1, 2045 in the case of the 2046 Notes, we may, at our option, redeem the Notes, in whole or in part, at 100% of the principal amount being redeemed plus accrued and unpaid interest thereon to, but excluding, the redemption date.

Ranking The Notes will, until the Collateral Release Date (as defined below), be our senior secured obligations and will:

• rank pari passu in right of payment with all of the Issuer’s existing and future senior indebtedness, but to the extent of the value of the collateral securing the Notes (the “Collateral”) will be effectively senior to all of our unsecured senior indebtedness (as of the date hereof, the Issuer’s other outstanding secured indebtedness consisted of 3.250% Senior Notes and the Term Loan);

• 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.

On and after the Collateral Release Date, the Notes will be our senior unsecured obligations and will:

• rank pari passu in right of payment with all of our existing and future senior unsecured and unsubordinated indebtedness;

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

• be senior in right of payment to any of our 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.

As of December 31, 2016, we had approximately $1,347.7 million of senior secured debt outstanding, including the Outstanding Notes. As of December 31, 2016, Cleco Power and its subsidiaries had approximately $1,254.8 million of debt outstanding.

Collateral The Notes will, until the Collateral Release Date, be secured on a first-lien basis by the same assets that secure the Revolving Credit Facility, 3.250% Senior Notes, and the Term Loan, which assets consist principally of 100% of the limited liability company membership interests in Cleco Power and 100% of any loans made by the Issuer to Cleco Power from time to time. See “Description of the Exchange Notes—Security.”

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The Collateral is subject to important limitations. For more information, see “Risk Factors—Risks relating to the Notes—The Collateral securing the Notes is limited in nature, and the proceeds from the Collateral may be inadequate to satisfy payments on the Notes.”

Collateral Release Date On the date on which we have retired all of our indebtedness that is secured by the Collateral, other than the Notes (the “Collateral Release Date”), the Notes will become unsecured and rank equally with all of our other unsecured senior indebtedness. The Collateral Release Date is not expected to occur before May 1, 2023, unless prior to such date we repurchase, amend or otherwise retire our indebtedness that is secured by the Collateral (other than the Notes).

Intercreditor The trustee under the indenture and the administrative agent under the Senior Secured Credit Facilities entered into the collateral agency and intercreditor agreement (the “Intercreditor”) as to the equal priorities of their entitlement, and the entitlement of holders of additional obligations permitted to be secured by liens on the Collateral, to proceeds of such Collateral, to set forth the relative rights of such parties to the exercise of rights and remedies in respect of the Collateral and certain other matters relating to the administration of security interests. See “Description of the Exchange Notes— Security—Intercreditor Arrangements.”

Change of Control Upon the occurrence of a Change of Control Repurchase Event, each holder of the Notes will have the right, at the holder’s option, to require us to repurchase all or any part of the holder’s 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 Notes, see “Description of the Exchange Notes—Events of Default.”

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

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No Guarantees or Credit Support The obligations to pay the principal of, premium, if any, and interest on the Notes are solely the obligations of the Issuer, and none of Parent, the members of the consortium that own Parent, or any of our subsidiaries or other affiliates will guarantee or provide any credit support for the obligations under the Notes.

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

Form of Notes The 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 Notes, except in limited circumstances described herein. See “Description of the Exchange Notes—Book-Entry; Delivery and Form.”

Material Covenants The indenture governing the Notes contains certain material covenants that, among other things, restrict the Issuer’s 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 offering memorandum under the caption “Description of the Exchange Notes—Material Covenants.”

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

Trustee Wells Fargo Bank, N.A.

Collateral Agent Wells Fargo Bank, N.A.

Governing Law The Notes, the indenture and the other documents for the offering of the Notes are governed by the laws of the State of New York.

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 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 issuer of the Notes, Cleco Corporate Holdings LLC, is the successor to Cleco Corporation, and was converted from a Louisiana corporation to a Louisiana limited liability company in connection with the Transactions (as defined herein). The consolidated financial information prior to April 13, 2016 (the effective date of the conversion) below is historical financial information of Cleco Corporation and its consolidated subsidiaries.

The summary consolidated financial information for the five years ended December 31, 2016 is derived from our audited consolidated financial statements included in this prospectus. This information is only a summary. You should read it in conjunction with our historical financial statements and related notes included in this prospectus, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	PREDECESSOR															SUCCESSOR
	Fiscal Year Ended December 31,												Jan. 1, 2016 – Apr. 12, 2016			Apr. 13, 2016 – Dec. 31, 2016
	2012			2013			2014			2015
	(in thousands unless otherwise indicated)
Income statement data:
Operating revenue, net	$	993,697		$	1,096,714		$	1,269,485		$	1,209,402		$	299,870		$	853,005
Operating expenses(1)		712,046			788,382			983,453			922,063			279,507			816,714
Operating income		281,651			308,332			286,032			287,339			20,363			36,291
Net income (loss)		163,648			160,685			154,739			133,669			(3,960	)		(24,113	)
Balance sheet and other data (at end of period):
Cash and cash equivalents		31,020			28,656			44,423			68,246						23,077
Total assets		4,147,349			4,215,262			4,368,418			4,323,354						6,343,144
Long-term debt, net(2)		1,257,258			1,315,500			1,338,998			1,267,703						2,738,571
Shareholders’ / Member’s equity		1,499,213			1,586,197			1,627,270			1,674,841						2,046,763
Cash flow statement data:
Net cash provided by operating activities		263,105			341,690			335,169			361,022			129,780			51,322
Net cash used in investing activities		(299,164	)		(236,216	)		(246,514	)		(167,951	)		(36,811	)		(161,145	)
Net cash (used in) provided by financing activities		(96,497	)		(107,838	)		(72,888	)		(169,248	)		(40,855	)		12,570
Other financial data (unaudited):
Capital expenditures(3)		238,322			184,533			202,256			153,756			41,699			140,709
Adjusted EBITDA(4)		445,192			466,269			458,046			442,639			100,354			326,426
Ratio of earnings to fixed charges		3.59x			3.78x			3.91x			3.65x			*			*
	Fiscal Year Ended December 31,
	2012			2013			2014			2015						2016
Key utility productivity indicators:
Electricity sold (GWh)		10,614			10,960			12,397			11,871						11,659
Generation nameplate capacity (MW)(5)		2,565			2,565			3,340			3,333						3,310
Rate base (in billions)	$	2.5		$	2.6		$	2.7		$	2.8					$	2.7

* Earnings were inadequate to cover fixed charges. The coverage deficiency was $492 for the period January 1, 2016 to April 12, 2016 and $46,935 for the period April 13, 2016 to December 31, 2016.

(1) Includes merger transaction and commitment costs of $174,696 for the period April 13, 2016 to December 31, 2016, $34,912 for the period January 1, 2016 to April 12, 2016, $4,591 for the year ended December 31, 2015, and $17,848 for the year ended December 31, 2014. There were no merger transaction and commitment costs for the years ended December 31, 2013 and 2012.

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(2) Represents long-term debt, net of unamortized discount and debt issuance costs, and excludes current portions of long-term debt.

(3) Capital expenditures exclude the allowance for funds used during construction (AFUDC), which is the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.

(4) We define Adjusted EBITDA as the sum of (1) net income, (2) depreciation and amortization, (3) income tax expense, (4) interest expense and (5) other nonrecurring expenses related to the Merger (as defined herein). Adjusted EBITDA provides us with a measure of financial performance independent of items that are beyond the control of management in the short term, such as depreciation and amortization, taxation and interest expense, and unrealized gains or losses on derivative instruments. Adjusted EBITDA measures our financial performance based on operational factors that management can influence in the short term, namely the cost structure and expenses of the organization.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations are:

• Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

• Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

• Adjusted EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

• although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

• other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as comparative measures.

Adjusted EBITDA is not an alternative to net income, income from continuing operations, or cash flows provided by or used in operating activities as calculated and presented in accordance with GAAP. You should not rely on Adjusted EBITDA as a substitute for any such GAAP financial measure. We strongly urge you to review the reconciliation presented below, along with our consolidated statements of income, balance sheets, statements of comprehensive income and statements of cash flows. In addition, because Adjusted EBITDA is not a measure of financial performance under GAAP and is susceptible to varying calculations, Adjusted EBITDA as presented may differ from and may not be comparable to similarly titled measures used by other companies.

	PREDECESSOR											SUCCESSOR
	Fiscal Year Ended December 31,								Jan. 1, 2016 – Apr. 12, 2016			Apr. 13, 2016 – Dec. 31, 2016
	2012		2013		2014		2015
	(in thousands)
Net income	$	163,648	$	160,685	$	154,739	$	133,669	$	(3,960	)	$	(24,113	)
Interest expense, net		83,810		83,149		71,838		77,096		21,858			88,926
Income tax expense (benefit)		65,327		79,575		67,116		77,704		3,468			(22,822	)
Depreciation and amortization		132,407		142,860		146,505		149,579		44,076			109,739
Other(a)		—		—		17,848		4,591		34,912			174,696
Adjusted EBITDA	$	445,192	$	466,269	$	458,046	$	442,639	$	100,354		$	326,426

(a) Represents expenses related to the Merger.

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

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RISK FACTORS

In deciding whether to participate in the exchange offer, you should carefully consider the risks 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.

RISKS RELATED TO THE EXCHANGE OFFER

Holders who fail to exchange their Outstanding Notes will continue to be subject to restrictions on transfer and may have reduced liquidity after the exchange offer.

If you do not exchange your Outstanding Notes in the exchange offer, you will continue to be subject to the restrictions on transfer applicable to the Outstanding Notes. The restrictions on transfer of your Outstanding Notes arise because we issued the Outstanding Notes under exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. In general, you may only offer or sell the Outstanding Notes if they are registered under the Securities Act and applicable state securities laws, or are offered and sold under an exemption from these requirements. We do not plan to register the Outstanding Notes under the Securities Act.

Furthermore, we have not conditioned the exchange offer on receipt of any minimum or maximum principal amount of Outstanding Notes. As Outstanding Notes are tendered and accepted in the exchange offer, the principal amount of remaining Outstanding Notes will decrease. This decrease could reduce the liquidity of the trading market for the Outstanding Notes. We cannot assure you of the liquidity, or even the continuation, of the trading market for the Outstanding Notes following the exchange offer.

For further information regarding the consequences of not tendering your Outstanding Notes in the exchange offer, see the discussions below under the captions “The Exchange Offer—Consequences of Failure to Properly Tender Outstanding Notes in the Exchange” and “Material United States Federal Income Tax Considerations.”

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.”

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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. If you are deemed to have received restricted securities, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

RISKS RELATING TO THE EXCHANGE NOTES

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

The Exchange Notes will be structurally subordinated to indebtedness and other liabilities of Cleco Power and our other subsidiaries. As of December 31, 2016, Cleco Power and its subsidiaries had approximately $1,254.8 million of debt outstanding. Any right that we have pursuant to our equity interest in Cleco Power to receive any assets of Cleco Power upon the liquidation or reorganization of Cleco Power, and the consequent rights of holders of the Exchange Notes to realize proceeds from the sale of Cleco Power’s assets, will effectively be subordinated to the claims of Cleco Power’s creditors, including trade creditors. Accordingly, in the event of a bankruptcy, liquidation or reorganization of Cleco Power, Cleco Power 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 Cleco Power. The security interest in the pledged stock of Cleco Power will not alter the subordination of the Exchange Notes to the claims of creditors of Cleco Power.

The Collateral securing the Exchange Notes is limited in nature, and the proceeds from the Collateral may be inadequate to satisfy payments on the Notes.

The Collateral securing the Exchange Notes is limited in nature. The Exchange Notes will only be secured on a first-lien basis by 100% of the limited liability company membership interests in Cleco Power and all indebtedness, if any, owed by Cleco Power to Issuer from time to time. The Exchange Notes will not be secured by any of our other assets or the assets of our subsidiaries. Because the Exchange Notes are not secured by all of our assets, if an event of default occurs and the Exchange Notes are accelerated, the Exchange Notes will rank equal in right of payment with the holders of other unsubordinated and unsecured indebtedness of the relevant entity with respect to such unencumbered assets.

At the closing of this offering, the Collateral securing the Exchange Notes will consist solely of the limited liability company membership interests of Cleco Power. To the extent that Cleco Power subsequently issues debt in favor of the Issuer in the future, the Issuer may need to seek approval from the LPSC prior to pledging such debt as Collateral securing the Exchange Notes. If the Issuer is required to seek LPSC approval to pledge such indebtedness as Collateral, there can be no assurance that the Issuer will obtain such approval.

The value of the Collateral will depend on market and economic conditions at the time, the availability of buyers and other factors beyond our control. The proceeds of any sale of the Collateral following a default by us may not be sufficient to satisfy the amounts due on the Exchange Notes. No appraisal of the fair market value of the Collateral has been prepared in connection with this offering, and the value of the interest of the holders of the Exchange Notes in the Collateral may not equal or exceed the principal amount of the Exchange Notes. The Collateral is by its nature illiquid, subject to regulatory-based restrictions on transferability, and therefore may not be able to be sold in a short period of time or at all.

In addition, the indenture and the credit agreement governing our Senior Secured Credit Facilities permit us in certain circumstances to incur additional debt secured equally and ratably by the Collateral. Therefore, the value of the Collateral may be inadequate to satisfy the amounts due under our secured indebtedness, including our Senior Secured Credit Facilities, the Notes, the 3.250% Senior Notes, the Term Loan and any future indebtedness secured by the Collateral.

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The Exchange Notes will become unsecured on the Collateral Release Date.

We may decide to retire all of our indebtedness which is secured by the Collateral other than the Notes. If we opt to retire such indebtedness, on such date, which we refer to herein as the Collateral Release Date, the Exchange Notes will become unsecured and rank equally with all of our other unsecured senior indebtedness. The Collateral Release Date is not expected to occur May 1, 2023, unless prior to such date we repurchase, amend or otherwise retire our indebtedness that is secured by the Collateral (other than the Notes). On and after the Collateral Release Date, the Exchange Notes will be our senior unsecured obligations and will: (a) rankpari passuin right of payment with all of our existing and future senior indebtedness; (b) be effectively subordinated to all existing and future secured indebtedness of ours to the extent of the value of the collateral securing such indebtedness; (c) be senior in right of payment to any of our future subordinated indebtedness; and (d) be structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of the Issuer’s subsidiaries, including Cleco Power.

It may be difficult to realize the value of the Collateral securing the Exchange Notes.

The collateral agent’s ability to foreclose on the Collateral on behalf of the holders of the Exchange Notes may be subject to perfection, the consent of third parties, regulatory approvals, priority issues and other practical problems associated with the realization of the collateral agent’s security interest in the Collateral. We cannot assure holders of the Exchange Notes that any consents or approvals will be given if required and, therefore, the collateral agent may not have the ability to foreclose upon those assets or assume or transfer the right to those assets.

For example, the collateral agent’s ability to exercise its remedies with respect to the Collateral may be subject to regulatory approval, including authorization by the Federal Energy Regulatory Commission under the Federal Power Act and the authorization of the LPSC. Prior to allowing the collateral agent to foreclose on the Collateral, the LPSC may require a finding that the change of control (i) will not adversely affect reliable service at reasonable rates, (ii) will not cause Cleco Power to be made financially unsound and (iii) is in the public interest.

In addition, bankruptcy laws may limit the ability of the collateral agent to realize value from the Collateral. The right of the collateral agent to repossess and dispose of the Collateral upon the occurrence of an event of default under the indenture is likely to be significantly impaired by applicable bankruptcy law if a bankruptcy case were to be commenced by or against us. Under applicable bankruptcy law, secured creditors such as the holders of the Exchange Notes would be prohibited from foreclosing upon or disposing of a debtor’s property without prior bankruptcy court approval.

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 us or Cleco Power. We may therefore incur a significant amount of additional debt, including secured debt secured equally and ratably by the Collateral, as described under “Description of the Exchange Notes—Security.” Cleco Power may also incur additional debt, which could affect its 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.

We may incur additional indebtedness that may share in the liens on the Collateral securing the Exchange Notes, which will dilute the value of the Collateral.

The Collateral also secures (i) the 3.250% Senior Notes and the Term Loan, which represent an aggregate of $465.0 million of indebtedness at December 31, 2016, and (2) our $100.0 million Revolving Credit Facility,

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under which our outstanding borrowings at December 31, 2016 were zero. Under the terms of the indenture governing the Exchange Notes, we also will be permitted in the future to incur additional indebtedness and other obligations that may be secured by additional liens on the Collateral securing the Exchange Notes. Any additional obligations secured by a lien on the Collateral will dilute the value of the Collateral securing the Exchange Notes. See “Description of the Exchange Notes—Security.”

The proceeds from the sale of all such Collateral may not be sufficient to satisfy the amounts outstanding under the Exchange Notes and all other indebtedness and obligations secured by such liens. If such proceeds were not sufficient to repay amounts outstanding under the Exchange Notes, then holders (to the extent not repaid from the proceeds of the sale of the Collateral) would only have an unsecured claim against our remaining assets, if any.

To the extent a security interest in any of the Collateral is created or perfected following the date of the issuance of the Exchange Notes, the security interest would remain at risk of being voided as a preferential transfer by a collateral agent in bankruptcy or being subject to the liens of intervening creditors.

The Exchange Notes will be secured only to the extent of the value of the assets that have been granted as security for the Exchange Notes and, as a result, there may not be sufficient Collateral to pay all or any of the Exchange Notes.

The Collateral has not been appraised in connection with this offering. The value of the Collateral and the amount that may be received upon a sale of the Collateral will depend upon many factors including, among others, the condition of the Collateral and of the electric transmission, distribution and generation and natural gas distribution industries, the ability to sell the Collateral in an orderly sale, the condition of the international, national and local economies, the availability of buyers and similar factors. By its nature, the Collateral is illiquid and may have no readily ascertainable market value. Liquidation of the Collateral will be subject to regulatory approval, including federal approval under the Federal Power Act and the approval of the LPSC.

Additionally, applicable law requires that every aspect of any foreclosure or other disposition of Collateral be “commercially reasonable.” If a court were to determine that any aspect of the collateral agent’s exercise of remedies was not commercially reasonable, the ability of the Trustee and you to recover the difference between the amount realized through such exercise of remedies and the amount owed on the Exchange Notes may be adversely affected and, in the worst case, you could lose all claims for such deficiency amount.

The imposition of certain permitted liens could adversely affect the value of the Collateral.

The Collateral securing the Exchange Notes will be subject to liens permitted under the terms of the indenture governing the Exchange Notes, whether arising on or after the date the Exchange Notes are issued. The existence of any permitted liens could adversely affect the value of the Collateral securing the Exchange Notes, as well as the ability of the collateral agent to realize or foreclose on such Collateral. The Collateral that will secure the Exchange Notes also secures our obligations under our Senior Secured Credit Facilities, the 3.250% Senior Notes, and the Term Loan, and may also secure future indebtedness and other obligations of ours to the extent permitted by the indenture and the Security Documents (as defined herein under “Description of Exchange Notes”). Your rights to the Collateral would be diluted by any increase in the indebtedness secured by this Collateral. To the extent we incur any permitted liens, the liens of holders of the Exchange Notes may not be first priority.

You will have limited rights to enforce remedies under the Security Documents and the Intercreditor, and the Collateral may be released without your consent in certain circumstances.

A collateral agent has been appointed by the holders of the liens on the Collateral, and such collateral agent (directly or through co-agents or sub-agents) is authorized to enforce all liens on the Collateral on behalf of the authorized representatives for the holders of the obligations secured by liens on the Collateral, including holders

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of Exchange Notes. Under the terms of the Security Documents, subject to certain exceptions, for so long as the Senior Secured Credit Facilities remains outstanding, the collateral agent will pursue remedies, pursuant to the direction of the Required Secured Creditors (as defined in the Intercreditor), which may or may not be controlled by holders of the Exchange Notes, and take other action related to the Collateral, including the release thereof. Accordingly, during such time, the Required Secured Creditors will have a right to control all remedies and the taking of other actions related to the Collateral, including the release thereof, without the consent of the other holders and the Trustee under the indenture governing the Exchange Notes.

There are certain circumstances other than repayment or discharge of the Exchange Notes under which certain Collateral securing the Exchange Notes can be released without consent of the Trustee or the holders.

Under certain circumstances, the Collateral securing the Exchange Notes can be released without consent of the Trustee or the holders, including:

• upon the date that we retire all of our indebtedness that is secured by the Collateral (other than the Notes), which is not expected to occur before May 1, 2023, unless prior to such date we repurchase, amend or otherwise retire our indebtedness that is secured by the Collateral (other than the Notes);

• upon a sale or other disposition of such Collateral in a transaction permitted under the Intercreditor, the indenture and the credit agreement governing the Senior Secured Credit Facilities,

• a release of less than a material portion of the Collateral, if the release of such liens on such Collateral has been approved, authorized or ratified by the Required Secured Creditors under the Intercreditor; or

• as to a release of all or any material portion of the Collateral, if written consent to release of that Collateral has been given by the Unanimous Voting Parties (as defined in the Intercreditor) pursuant to the Intercreditor.

Any of these events will eliminate or reduce the aggregate value of the Collateral securing the Exchange Notes.

Your interest in the Collateral may be adversely affected by the failure to perfect security interests.

Your security interests will only be perfected with respect to the Collateral by the filing of financing statements. The limited liability company membership interests in Cleco Power are not certificated and will not be perfected through the possession of these security instruments. To the extent that the security interest in the Collateral is unperfected, the rights of holders with respect to the Collateral will be equal to the rights of our general unsecured creditors in the event of any bankruptcy filed by or against us under applicable U.S. federal bankruptcy laws.

Intervening creditors may have a perfected security interest in the Collateral.

The Collateral is subject to liens permitted under the terms of our credit agreement governing the Revolving Credit Facility and the indenture governing the Exchange Notes whether arising before, on or after the date the Exchange Notes are issued. There is a risk that there may be a creditor whose liens are permitted under our credit agreement governing the Revolving Credit Facility or the indenture governing the Exchange Notes, or an intervening creditor that has a perfected security interest in the Collateral securing the Exchange Notes. If there is such an intervening creditor, the lien of such creditor, whether or not permitted under our credit agreement governing the Revolving Credit Facility or the indenture governing the Exchange Notes, may be entitled to a higher priority than the liens securing the Exchange Notes. The existence of any liens securing obligations owed to intervening creditors, including liens permitted under our credit agreement governing the Revolving Credit Facility or the indenture governing the Exchange Notes and incurred or perfected prior to the liens securing the Exchange Notes, could adversely affect the value of the Collateral securing the Exchange Notes, as well as the ability of the collateral agent to realize or foreclose on such Collateral.

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The Collateral will also be subject to any and all exceptions, defects, encumbrances, liens and other imperfections as may be permitted by the Revolving Credit Facility or the indenture governing the Exchange Notes. The existence of any such exceptions, defects, encumbrances, liens and other imperfections could adversely affect the value of the Collateral that will secure the Exchange Notes, as well as the ability of the collateral agent to realize or foreclose on the Collateral for the benefit of holders.

Rights of holders in the Collateral may be adversely affected by bankruptcy proceedings.

The right and ability of the collateral agent for the holders to repossess and dispose of the Collateral securing the Exchange Notes upon an event of default is likely to be significantly impaired by U.S. federal bankruptcy law if bankruptcy proceedings are commenced by or against us prior to, or possibly even after, the collateral agent has repossessed and disposed of the Collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral agent for the holders, is prohibited from repossessing Collateral from a debtor in a bankruptcy case, or from disposing of Collateral repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use Collateral, and the proceeds, products, rents or profits of the Collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the Collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the Collateral as a result of the stay of repossession or disposition or any use of the Collateral by the debtor during the pendency of the bankruptcy case.

In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the Exchange Notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent could repossess or dispose of the Collateral, or whether or to what extent holders would be compensated for any delay in payment of loss of value of the Collateral through the requirements of “adequate protection.”

Furthermore, in the event the bankruptcy court determines that the value of the Collateral is not sufficient to repay all amounts due on the Exchange Notes, holders would have “undersecured claims” as to the difference. U.S. federal bankruptcy laws do not permit the payment or accrual of interest, costs and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case.

Any future pledge of Collateral might be voidable in bankruptcy.

Any future pledge of Collateral in favor of the collateral agent for the holders, including pursuant to Security Documents delivered after the date of the indenture governing the Exchange Notes, might be voidable by the pledgor (as debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits holders to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or one year before commencement of a bankruptcy proceeding if the creditor that benefited from the guarantee or lien is an “insider” under the U.S. Bankruptcy Code.

Federal and state fraudulent transfer laws may permit a court to void the Exchange Notes, subordinate claims in respect of the Exchange Notes and require holders to return payments received and, if that occurs, you may not receive any payments on the Exchange Notes.

Federal and state fraudulent transfer and conveyance statutes may apply to the issuance of the Exchange Notes. Under U.S. federal bankruptcy law and comparable provisions of state fraudulent transfer or conveyance laws, which may vary from state to state, the delivery of the Exchange Notes could be voided as a fraudulent

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transfer or conveyance if (a) we issued the Exchange Notes or granted securing interests on assets with the intent of hindering, delaying or defrauding creditors or (b) we received less than reasonably equivalent value or fair consideration in return for either issuing the Exchange Notes or granting securing interests on assets and, in the case of (b) only, one of the following is also true at the time thereof:

• we were insolvent or rendered insolvent by reason of the issuance of the Exchange Notes;

• the issuance of the Exchange Notes left us with an unreasonably small amount of capital to carry on the business;

• we intended to, or believed that we would, incur debts beyond our ability to pay such debts as they mature; or

• we were a defendant in an action for money damages, or had a judgment for money damages docketed against us, in either case, after final judgment, the judgment is unsatisfied.

A court would likely find that we did not receive reasonably equivalent value or fair consideration for the Exchange Notes or granted securing interests on assets if we did not substantially benefit directly or indirectly from the issuance of the Exchange Notes or the granting of security interests. As a general matter, value is given for a transfer or an obligation if, in exchange for the transfer or obligation, property is transferred or an antecedent debt is secured or satisfied. A debtor will generally not be considered to have received value in connection with a debt offering if the debtor uses the proceeds of that offering to make a dividend payment or otherwise to retire or redeem equity securities issued by the debtor.

We cannot be certain as to the standards a court would use to determine whether or not we were solvent at the relevant time or, regardless of the standard that a court uses, that the granting of security interests would not be further subordinated to our other debt. Generally, however, an entity would be considered insolvent if, at the time it incurred indebtedness:

• the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

• the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

If a court were to find that the issuance of the Exchange Notes or granting of securing interests was a fraudulent transfer or conveyance, the court could void the payment obligation under the Exchange Notes or such securing interests, or further subordinate the Exchange Notes or such security interests to presently existing and future indebtedness of ours, or require holders to repay any amounts received with respect to such security interests. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the Exchange Notes. Further, the voidance of the Exchange Notes could result in an event of default with respect to our and our subsidiaries’ other debt that could result in acceleration of such debt.

The value of the Collateral may not be sufficient to secure post-petition interest.

In the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding against us, holders will only be entitled to post-petition interest under the U.S. Bankruptcy Code to the extent that the value of their respective security interests in their Collateral is greater than their respective pre-bankruptcy claims. Holders may be deemed to have an unsecured claim to the extent that the fair market value of the Collateral securing the Exchange Notes, together with the other obligations secured by the same lien, is less than the face amount of all obligations secured by the same lien. In such case, holders will not be entitled to post-petition interest under the U.S. Bankruptcy Code. Upon a finding by a bankruptcy court that the Exchange Notes are

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under-collateralized, the claims in the bankruptcy proceeding with respect to the Exchange Notes would be bifurcated between a secured claim and an unsecured claim, and the unsecured claim would not be entitled to the benefits of security in the Collateral. Other consequences of a finding of under-collateralization would be, among other things, a lack of entitlement on the part of the unsecured portion of the Exchange Notes to receive other “adequate protection” under the U.S. Bankruptcy Code. In addition, if any payments of post-petition interest had been made at the time of such a finding of under-collateralization, those payments could be recharacterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to the Exchange Notes. No appraisal of the fair market value of the Collateral has been prepared in connection with the issuance of the Exchange Notes and, therefore, the value of the interests of holders in the Collateral may not equal or exceed the principal amount of the Exchange Notes and may not be sufficient to satisfy our obligations under all or any part of the Exchange Notes.

In addition, under most circumstances, while you share equally and ratably with the other secured parties in all proceeds from any realization on the Collateral, subject to certain exceptions, you will not control the rights and remedies with respect to the Collateral upon an event of default and the exercise of any such rights and remedies following such an event of default will be made by the collateral agent, acting at the direction of the administrative agent or the authorized representative of the largest outstanding debt secured by apari passulien on the Collateral.

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 that results in a repurchase of the Exchange Notes or requires us to repurchase the Exchange Notes, we may not have sufficient financial resources to satisfy all of our obligations under the Exchange Notes. In addition, restrictions under our Senior Secured 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.

Parent has voting ownership of all of the equity of the Company. As a result of its equity ownership, Parent will effectively be able to control the operations of the Company. Parent 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 Parent 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 Parent might conflict with your interests as a holder of the Exchange Notes. Parent 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.

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An active trading market for the Notes may not develop.

There is currently no public market for the Notes, and we do not currently plan to list the Notes on any national exchange. In addition, the liquidity of any trading market in the Notes, and the market price quoted for the 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.

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

Substantially all of our existing indebtedness will mature prior to the maturity date of the Exchange Notes. Therefore, we will be required to repay substantially all of our other creditors before we are required to repay a portion of the interest due on, and 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.

RISKS RELATING TO OUR BUSINESS AND OPERATIONS

Corporate Structure

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 Cleco Power. Cleco Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if Cleco Holdings were a creditor of any subsidiary, its rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by Cleco Holdings. Moreover, Cleco Power, Cleco Holdings’ principal subsidiary, is subject to regulation by the LPSC, which may impose limits on the amount of dividends that Cleco Power may pay Cleco Holdings. The 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.

Hedging and Risk Management Activities

Cleco Power is subject to market risk associated with fuel cost hedges and FTRs.

Annually, Cleco Power receives Auction Revenue Rights, which can be converted to FTRs. FTRs provide a financial hedge to manage the risk of congestion cost in the Day-Ahead Energy Market. FTRs represent rights to congestion credits or charges along a path during a given timeframe for a certain MW quantity. Cleco Power may purchase additional FTRs to further hedge its congestion cost risk.

Cleco Power may enter into fuel cost hedge positions to mitigate the volatility in fuel costs passed through to its retail customers. When these positions close, actual gains or losses are deferred and included in the FAC in the month the physical contract settles. 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. In June 2015, the LPSC approved a long-term natural gas hedging pilot program requiring Cleco Power to establish a proposal for a long-term natural gas procurement program that will be designed to provide gas price stability for a minimum of five years. The proposal is currently scheduled to be submitted to the LPSC in the second half of 2017.

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Cleco Power manages its exposure to energy commodity activities by maintaining risk management policies and establishing and enforcing risk limits and risk management procedures. However, these risk limits and risk management procedures cannot eliminate all risk associated with these activities.

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

In July 2010, Congress enacted the Dodd-Frank Act to reform financial markets. This legislation significantly altered the regulation of over-the-counter (OTC) derivatives, including commodity swaps that could be used by Cleco Power to hedge and mitigate commodities risk. The Dodd-Frank Act increases regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements, and (3) authorizing the establishment of overall volume and position limits. These requirements could cause Cleco Power’s future OTC transactions to be more costly and have an adverse effect on its liquidity due to additional capital requirements. In addition, by standardizing OTC products, these reforms could limit the effectiveness of Cleco Power’s hedging programs because Cleco Power would have less ability to tailor OTC derivatives to match the precise risk it is seeking to protect. The law gives the CFTC authority to exempt end users of energy commodities. Cleco Power would qualify for the end-user exemption which reduces but does not eliminate the applicability of these measures. Management continues to monitor this law and its possible impacts on Cleco.

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’s retail operations and FERC regulates Cleco’s wholesale operations. The construction, planning, and siting of Cleco’s power plants and transmission lines also are subject to the jurisdiction of the LPSC and FERC. Additional regulatory authorities have jurisdiction over some of Cleco’s operations and construction projects including the EPA, the U.S. Bureau of Land Management, the U.S. Fish and Wildlife Services, the DOE, the U.S. Army Corps of Engineers, the U.S. Department of Homeland Security, the Occupational Safety and Health Administration, the U.S. Department of Transportation, the U.S. Department of Agriculture, the U.S. 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.

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

As a result of the Merger, Cleco Holdings and Cleco Power made 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. A report on the status of the Merger Commitments must be filed annually by October 31 for the 12-month period ended June 30.

On April 8, 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

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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. On April 8, 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 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. On October 4, 2016, Cleco received the first set of data requests from the LPSC Staff for each of the above mentioned dockets. Cleco has filed responses to the non-confidential requests and is waiting on the completion of a confidentiality agreement to respond to the confidential requests. Cleco anticipates the completion of this agreement in the second quarter of 2017. 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.

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 power flow congestion on the transmission system. Pricing zones with congested power delivery will typically incur a higher LMP. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power’s pricing zones. Cleco Power purchases FTRs to mitigate the transmission congestion price risks. However, insufficient FTR allocations or increased FTR costs due to negative congestion flows may result in an unexpected increase in energy costs to Cleco Power’s customers. If a disallowance of additional fuel costs associated with congestion 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 Cleco.

LPSC Audits

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

Generally, fuel and purchased power expenses are recovered through the LPSC-established 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 will be performed at least every other year.

Cleco Power currently has FAC filings for 2016 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, 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 July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides for 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. Cleco Power began incurring additional environmental compliance expenses beginning in the second quarter of 2015 for reagents associated with compliance with MATS. These expenses are eligible for recovery through Cleco Power’s EAC and subject to periodic review by the LPSC.

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Cleco Power currently has EAC filings for 2016 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, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Commodity Prices

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

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

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 the Company’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 the Company’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. As interest rates decrease, Cleco’s liabilities increase, potentially requiring additional funding. Adverse changes in assumptions or adverse actual events could cause additional minimum contributions.

Inflation

Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged 1% during the three years ended December 31, 2016. Cleco believes inflation at this level does not materially affect its results of operations or financial condition. However, 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 the 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 its respective ability 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.

Events beyond Cleco’s control, such as volatility and disruption in global capital and credit markets, may create uncertainty that could increase their cost of capital or impair their ability to access the capital markets,

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including the ability to draw on their respective bank credit facilities. Cleco is 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, they may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could have a material adverse 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.

Future Electricity Sales

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

General economic conditions can negatively impact the businesses of Cleco Power’s residential, industrial, and commercial customers resulting in decreased power consumption, which causes a corresponding decrease in base revenue. Reduced production or the shutdown of any of these customers’ facilities could substantially reduce Cleco Power’s base 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 peak 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. Macroeconomic factors resulting in low economic growth or contraction within Cleco’s service territories could also reduce energy demand. 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.

Cleco Power’s Generation, Transmission, and Distribution Facilities

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

The operation of power generation facilities involves many risks, including breakdown or failure of equipment, fuel supply interruption, and performance below expected levels of output or efficiency. Approximately 25% of Cleco Power’s net capacity was constructed before 1980. 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, in the event of such failures, Cleco Power 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 and could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco Power’s generating facilities are fueled primarily by coal, natural gas, petroleum coke, and lignite. The deliverability of these fuel sources may be constrained due to such factors as higher demand, decreased regional supply, production shortages, weather-related disturbances, railroad constraints, waterway levels, labor strikes, or lack of transportation capacity. If the 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. Fuel and

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MISO procured/settled energy expenses, which are recovered from 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, making the right of first access critical with respect to extracting lignite. 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 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 Power could be materially affected.

Cleco Power’s ability to complete construction of 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, but are not limited to, engineering and project execution risk and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as set forth under their contracts, changes in the scope and timing 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 Power 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 Power could incur additional costs including termination payments, face increased risk of potential write-off of the investment in the project, or may not be able to recover such costs. 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.

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 Power 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 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 Power, 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 Power is subject to a significant amount of forced outages, Cleco Power may not possess sufficient planning reserves to serve its needs and could be forced to purchase capacity from the MISO resource adequacy auction. The costs of such capacity may not be recoverable 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 590 MW of capacity in excess of its peak, coincident to MISO’s peak, in 2016.

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Reliability and Infrastructure Protection Standards Compliance

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

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

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

The SPP RE conducts a NERC Reliability Standards audit every three years. Cleco Power’s next audit is scheduled to begin in April 2019. Management is unable to predict the outcome of this 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.

The SPP RE also conducts a NERC Critical Infrastructure Protection audit every three years. Cleco Power’s NERC Critical Infrastructure Protection audit began February 13, 2017. Management is unable to predict the outcome of this 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.

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. For example, the EPA has issued the CPP to reduce CO₂emissions from existing EGUs by 32% from 2005 levels of CO₂ emissions, however, on February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the CPP pending resolution of challenges to the rule. As a result, the rule is not currently in force and its future is uncertain. These changes under the stayed plan would have environmental regulations governing power plant emissions effective beginning 2022, with final emission goals required by 2030, and, if implemented, could render some of Cleco’s EGUs 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 electric generating facilities. 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.

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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 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 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. 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 December 31, 2016, Cleco Power had $3.3 million accrued for ROE reductions, including accrued interest. On February 13, 2017, $1.2 million of refunds relating to the first complaint were submitted to MISO. 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 Power’s business practices are regulated by FERC, and its wholesale rates are subject to FERC’s triennial market power analysis. Cleco could lose the right to sell wholesale generation at market-based rates.

FERC conducts a review of Cleco Power’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 in 2018. In the future, if FERC determines Cleco Power possesses generation market power in excess of certain thresholds, Cleco Power could lose the right to sell wholesale generation at market-based rates, which could result in a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Weather Sensitivity

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

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

Cleco recognizes that certain groups associate severe weather with the concept of global climate change and forecast the possibility that these weather events could have a material impact on future results of operations should they occur more frequently and with greater severity. If there is an actual occurrence of such global climate change, 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 Power’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.

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Litigation

Cleco is subject to litigation related to the Merger.

In connection with the 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. 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 allege, 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 Merger at a price that allegedly undervalues Cleco, and failing to disclose material information about the Merger. The petitions also allege 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. On September 26, 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 to the Third Circuit Court of Appeal on November 9, 2016. A briefing schedule has not yet been set.

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.

Alternative Generation Technology

Changes in technology may have a material adverse effect on the value of Cleco Power’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. Technological advances may reduce the cost of alternative methods of electricity production to a level that is equal to or below that of most central station production. In addition, 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’s generating facilities could be reduced.

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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, real estate, sales and use, and employment-related taxes. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. Changes in federal, state, or local tax laws, adverse tax audit results, or adverse tax rulings on positions taken by Cleco could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Cleco Credit Ratings

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

Neither Cleco 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 or Moody’s were to downgrade Cleco Holdings’ or Cleco Power’s long-term ratings, particularly below investment grade, the value of their debt securities would likely be adversely affected. Downgrades of either Cleco Holdings’ or Cleco Power’s credit ratings would 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.

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 systems, 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 or implementation of new systems, could result in increased costs, the inability to track or collect revenues, 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.

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Despite implementation of security and mitigation measures, all of Cleco’s technology systems are vulnerable to inoperability and/or impaired operations or failures due to cyber and/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 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, and/or harm Cleco’s reputation.

Insurance

Cleco’s insurance coverage may not be sufficient.

Cleco currently has property, casualty, cyber security 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 and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Cleco’s facilities may not be sufficient to restore the loss or damage without a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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

Cleco Power LLC’s Unsecured and Unsubordinated Obligations

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

Some of Cleco Power LLC’s senior notes and its obligations under various loan agreements and refunding agreements with the Rapides Finance Authority, the Louisiana Public Facilities Authority, and other issuers of tax-exempt bonds for the benefit of Cleco Power LLC are unsecured and rank equally with all of Cleco Power LLC’s existing and future unsecured and unsubordinated indebtedness. As of December 31, 2016, Cleco Power LLC had an aggregate of $1.19 billion of unsecured and unsubordinated indebtedness. The unsecured and unsubordinated indebtedness of Cleco Power LLC will be effectively subordinated to, and thus have a junior position to, any secured debt that Cleco Power LLC may have outstanding from time to time (including any mortgage bonds) with respect to the assets securing such debt. Certain agreements entered into by Cleco Power LLC with other lenders that are unsecured provide that if Cleco Power LLC issues secured debt, Cleco Power is obligated to grant these lenders the same security interest in certain assets of Cleco Power LLC. If such a security interest were to arise, it would further subordinate Cleco Power LLC’s unsecured and unsubordinated obligations.

As of December 31, 2016, Cleco Power LLC had no secured indebtedness outstanding. Cleco Power LLC may issue mortgage bonds in the future under any future Indenture of Mortgage, and holders of mortgage bonds

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would have a prior claim on certain Cleco Power LLC material assets upon dissolution, winding up, liquidation, or reorganization. Additionally, Cleco Power LLC’s ability (and the ability of Cleco Power LLC’s creditors, including holders of its senior notes) to participate in the assets of Cleco Power LLC’s subsidiary, Cleco Katrina/Rita, is subject to the prior claims of the subsidiary’s creditors. As of December 31, 2016, Cleco Katrina/Rita had $67.6 million of indebtedness outstanding, net of debt discount.

Health Care Reform

Cleco may experience increased costs arising from health care reform.

The PPACA, enacted in 2010, has had a significant impact on health care providers, insurers, and others associated with the health care industry. Cleco continues to evaluate the impact of this comprehensive law on its business and has made the required changes to its health plan. The current President has signed an Executive Order aimed at scaling back or repealing the PPACA. He has also stated that he will ask Congress to replace the current legislation with new legislation. Congress and state governments may propose other health care initiatives and revisions to the health care and health insurance systems. It is uncertain what legislative programs, if any, will be adopted in the future, or what action Congress or state legislatures may take regarding other health care reform proposals or legislation. Management is unable to estimate the comprehensive effects of the PPACA or any future health care reform and their impact on Cleco’s business, results of operations, financial condition, or cash flows.

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, matching of skill set or complement to 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.

The new Presidential Administration may make substantial changes to environmental, fiscal, and tax policies that could have a material adverse effect on Cleco’s business.

The new Presidential Administration has called for substantial changes to environmental, fiscal, and tax policies, which may include comprehensive tax reform. It is possible that these changes could adversely affect Cleco’s business. Until the changes are enacted, management is unable to determine the impact of the changes on Cleco’s business, results of operations, financial condition, or cash flows.

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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 sale of the Outstanding Notes, for which we received $882.1 million in net proceeds that were used to repay a portion of the amounts due under the Acquisition 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 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 cash 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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CAPITALIZATION

The following table presents our consolidated cash and cash equivalents and capitalization as of December 31, 2016, and reflects the Transactions, including the application of proceeds from the offering and sale of the Outstanding Notes. This table should be read in conjunction with the information contained in “Use of Proceeds” and “Description of Certain Other Indebtedness,” included elsewhere in this prospectus and our consolidated financial statements and related notes included in this prospectus.

You should read this table together with “Prospectus Summary—Summary Consolidated Historical Financial Data,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus and our consolidated financial statements and the related notes thereto included in this prospectus.

The Outstanding Notes that are surrendered in exchange for the Exchange Notes will be retired and canceled and cannot be reissued. As a result, the issuance of the Exchange Notes will not result in any change in our capitalization.

	As of December 31, 2016
	(in thousands)
Cash and cash equivalents	$	23,077
Current portion of long-term debt	$	19,715
Long-term debt (excluding current portion):
Senior Secured Credit Facilities(1):
Revolving Credit Facility(2)		—
Term Loan(3)		300,000
3.250% Senior Notes(3)		165,000
Outstanding Notes(3)		885,000
Unamortized debt issuance costs		(2,261	)
Fair value adjustments		155,776
Cleco Power indebtedness(4)		1,235,056
Total long-term debt (excluding current portion)	$	2,738,571
Member’s Equity	$	2,046,763
Total Capitalization	$	4,805,049

(1) In connection with the Transactions, we entered into the following: (i) new Revolving Credit Facility, which provides for a five-year senior secured revolving credit facility of up to $100.0 million; and (ii) new Acquisition Loan Facility, which was subsequently refinanced (see footnote 3).

(2) As of December 31, 2016, our unused availability under our new Revolving Credit Facility was $100.0 million.

(3) At the closing of the Merger, we borrowed $1,350.0 million under the Acquisition Loan Facility, which we repaid with the net proceeds of the offerings of the Outstanding Notes, Term Loan, and 3.250% Senior Notes.

(4) Reflects the indebtedness of Cleco Power net of $19.7 million in current maturities, $6.3 million of unamortized debt discount and $9.4 million of unamortized debt issuance costs. As of December 31, 2016, Cleco Power had $1,254.8 million in indebtedness outstanding (including current maturities). See “Description of Certain Other Indebtedness—Cleco Power—Debt Securities” for more information. Cleco Power also has a five-year senior unsecured revolving credit facility of up to $300.0 million (the “OpCo Revolver”) and a $2.0 million unsecured letter of credit issued under a separate agreement (the “LC Facility”). As of December 31, 2016, our unused availability under our OpCo Revolver was $300.0 million. The Notes are structurally subordinated to the debt of our subsidiaries, including Cleco Power. See “Description of Certain Other Indebtedness—Cleco Power.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

Cleco is a regional energy company that conducts substantially all of its business operations through its primary subsidiary, Cleco Power. Cleco Power is a regulated electric utility company that owns nine generating units with a total nameplate capacity of 3,310 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi. Prior to March 15, 2014, Cleco also conducted wholesale business operations through its Midstream subsidiary. Midstream owns Evangeline (which owned and operated Coughlin). On March 15, 2014, the Coughlin generating assets were transferred to Cleco Power. Coughlin consists of two generating units with a total nameplate capacity of 775 MW. For more information on the transfer of Coughlin to Cleco Power, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 18—Coughlin Transfer.”

Merger

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 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. For more information on the Merger, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 3—Business Combinations.”

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 meet increasingly stringent regulatory and environmental standards; and the ability to successfully perform in MISO and the related operating challenges and uncertainties, including increased wholesale competition relative to more suppliers. Key initiatives on which Cleco Power is working include continuing construction on the Cenla Transmission Expansion project and the St. Mary Clean Energy Center project; beginning construction on the Terrebonne to Bayou Vista Transmission project and the Coughlin Pipeline project; and maintaining and growing its wholesale and retail business. These initiatives are discussed below.

Layfield/Messick Project

The Layfield/Messick project, or Northwest Louisiana Transmission Expansion project, includes the construction of the new Layfield transmission substation and the construction of additional transmission interconnection facilities near the Dolet Hills Power Station. The project reduces congestion and increases reliability for customers in northwest Louisiana. Construction was completed in December 2016. Cleco Power’s portion of the joint project with SWEPCO cost $29.0 million.

Cenla Transmission Expansion Project

The Cenla Transmission Expansion project includes the construction of transmission lines and a transmission substation within the central Louisiana area. The project is expected to improve reliability to customers by relieving forecasted overloads and mitigating potential load shedding events while providing flexibility to allow routine maintenance outages and serve future growth in the central Louisiana area. The substation construction is complete and has been placed in service. Line construction is in progress. The project is expected to be complete by the end of 2017 with an estimated cost of $32.3 million. As of December 31, 2016, Cleco Power had spent $25.7 million on the project.

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St. Mary Clean Energy Center Project

The St. Mary Clean Energy Center project includes Cleco Power constructing, owning, and operating a 50-MW generating unit to be fueled by waste heat from Cabot Corporation’s carbon black manufacturing plant in Franklin, Louisiana. Construction began in October 2016 with the project expected to be commercially operational by the first quarter of 2018. The project was expected to cost $81.9 million; however, an increase in waste heat output has been confirmed, which will increase the capacity of the unit and the total cost of the project. Cleco has not yet established the total increase in the project’s cost. Upon achieving commercial operations, the project is expected to generate more than 300,000 MWh of zero additional carbon emitting energy each year. As of December 31, 2016, Cleco Power had spent $20.5 million on the project.

Terrebonne to Bayou Vista Transmission Project

The Terrebonne to Bayou Vista Transmission project includes the construction of additional transmission interconnection facilities south of Teche Power Station. The project is expected to increase reliability, reduce congestion, and provide hurricane hardening for customers in southeast Louisiana. A line routing study began in March 2016, and permitting and right-of-way acquisition began in May 2016. Cleco Power’s portion of the joint project with Entergy Louisiana is expected to cost $48.0 million. Construction is expected to be complete by the third quarter of 2018. As of December 31, 2016, Cleco Power had spent $1.4 million on the project.

Coughlin Pipeline Project

The Coughlin Pipeline project includes construction of a pipeline directly connecting the Pine Prairie Energy Center to Cleco’s Coughlin Power Station. The project is expected to increase fuel delivery reliability and mitigate exposure to price increases. Cleco has filed a letter with the LPSC seeking guidance on the appropriate treatment and timing of recovering revenue associated with the project. The project is expected to be operational by the third quarter of 2018 with an estimated cost of $29.4 million.

Other

Cleco Power is working to secure load growth opportunities that include renewal of existing load through 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.

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Comparison of the Years Ended December 31, 2016, and 2015

Cleco Consolidated

Cleco Consolidated Results of Operations

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016- APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015
Operating revenue, net	$	853,005		$	299,870		$	1,209,402
Operating expenses		816,714			279,507			922,063
Operating income	$	36,291		$	20,363		$	287,339
Allowance for equity funds used during construction	$	3,735		$	723		$	3,063
Other income	$	3,350		$	870		$	1,443
Other expense	$	1,385		$	590		$	3,376
Interest charges	$	89,766		$	22,123		$	77,991
Federal and state income tax (benefit) expense	$	(22,822	)	$	3,468		$	77,704
Net (loss) income	$	(24,113	)	$	(3,960	)	$	133,669

Cleco’s net loss attributable to the successor period April 13, 2016, through December 31, 2016, was $24.1 million. There were no significant changes in the underlying trends impacting net loss with the exception of the change in pretax loss primarily related to:

• $174.7 million of merger transaction and commitment costs,

• $34.0 million of interest costs related to debt obtained as a result of the Merger,

• $7.5 million of an offset to operating revenue related to the amortization of the intangible asset recorded for the fair value adjustment of wholesale power supply agreements as a result of the Merger, and

• $6.4 million of amortization of the fair value adjustment made as a result of the Merger to record the stepped-up basis for the Coughlin assets.

The effective income tax rate for the period was 48.6%.

Cleco’s net loss attributable to the predecessor period January 1, 2016, through April 12, 2016, was $4.0 million. There were no significant changes in the underlying trends impacting net loss with the exception of the change in pretax loss primarily related to $34.9 million of merger transaction costs. The effective income tax rate for the period was (704.9%).

Cleco’s net income attributable to the predecessor period for the year ended December 31, 2015, was $133.7 million. There were no significant changes in the underlying trends impacting net income. The effective income tax rate for the period was 36.8%.

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

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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; 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 “Cautionary Note Regarding 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— Hedging and Risk Management Activities,” “—Regulatory Compliance,” “—Transmission Constraints,” “—LPSC Audits,” “—Commodity Prices,” “—Global Economic Environment and Uncertainty; Access to Capital,” “—Future Electricity Sales,” “—Cleco Power’s Generation, Transmission, and Distribution Facilities,” “—MISO,” “—Reliability and Infrastructure Protection Standards Compliance,” “—Environmental Compliance,” “—Cleco Power’s Rates,” “—Retail Electric Service,” “—Wholesale Electric Service,” “—Weather Sensitivity,” “—Litigation,” “—Alternative Generation Technology,” “—Taxes,” “—Cleco Credit Ratings,” “—Technology and Terrorism Threats,” “—Insurance,” “—Cleco Power LLC’s Unsecured and Unsubordinated Obligations,” “—Health Care Reform,” and “—Workforce.”

Cleco Power’s residential customers’ demand for electricity is affected largely by weather. Weather generally is measured in cooling degree-days and heating degree-days. A cooling degree-day is an indication of the likelihood that a consumer will use air conditioning, while a heating degree-day is an indication of the likelihood that a consumer will use heating. An increase in heating degree-days does not produce the same increase in revenue as an increase in cooling degree-days, because alternative heating sources are more available and 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.

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. For the retail industrial class, Cleco Power expects new industrial load to be added in 2017, principally driven by developments 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 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 “—Base,” “Cautionary Note Regarding Forward-Looking Statements,” and “Risk Factors—Future Electricity Sales.”

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

• Imposition of federal and/or state renewable portfolio standards;

• imposition of energy efficiency mandates,

• legislative and regulatory changes,

• increases in environmental regulations and compliance costs,

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• cost of power impacted by the price movement of fuels and the addition of new generation capacity,

• transmission congestion costs,

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

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

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 primarily is affected by the cost of the facilities in service, the time the facilities were placed in service, and the estimated useful life of the facilities. Taxes other than income taxes generally include payroll taxes, franchise taxes, and property taxes. Cleco Power anticipates certain non-fuel cost recovery expenses to be lower in 2017 compared to 2016. These expenses include lower merger expense, lower interest expense, lower generation maintenance expense, and lower distribution operations expense. These decreases are partially offset by higher income tax expense, higher depreciation and amortization expense, higher generation operations expense, higher taxes other than income taxes, higher distribution maintenance expense, and higher amortization of debt issuance costs.

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Cleco Power Results of Operations

	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/ (UNFAVORABLE)
(THOUSANDS)	2016			2015			VARIANCE			CHANGE
Operating revenue
Base	$	660,974		$	670,530		$	(9,556	)		(1.4	)%
Fuel cost recovery		430,255			471,859			(41,604	)		(8.8	)%
Electric customer credits		(1,513	)		(2,173	)		660			30.4	%
Other operations		68,573			67,109			1,464			2.2	%
Affiliate revenue		884			1,142			(258	)		(22.6	)%
Operating revenue, net	$	1,159,173		$	1,208,467		$	(49,294	)		(4.1	)%
Operating expenses
Recoverable fuel and power purchased		430,422			471,864			41,442			8.8	%
Non-recoverable fuel and power purchased		35,684			31,348			(4,336	)		(13.8	)%
Other operations		125,892			128,697			2,805			2.2	%
Maintenance		93,340			87,416			(5,924	)		(6.8	)%
Depreciation and amortization		146,142			147,839			1,697			1.1	%
Taxes other than income taxes		48,287			47,102			(1,185	)		(2.5	)%
Merger commitment costs		151,501			—			(151,501	)		—	%
Gain on sale of asset		(1,095	)		—			1,095			—	%
Total operating expenses		1,030,173			914,266			(115,907	)		(12.7	)%
Operating income	$	129,000		$	294,201		$	(165,201	)		(56.2	)%
Allowance for equity funds used during construction	$	4,458		$	3,063		$	1,395			45.5	%
Federal and state income tax expense	$	18,369		$	79,294		$	60,925			76.8	%
Net income	$	39,128		$	141,350		$	(102,222	)		(72.3	)%

Cleco Power’s net income for 2016 decreased $102.2 million compared to 2015. Contributing factors include:

• higher merger commitment costs,

• lower base revenue,

• higher maintenance expense,

• higher non-recoverable fuel and power purchased, and

• higher taxes other than income taxes.

These factors were partially offset by:

• lower income taxes,

• lower other operations expense,

• lower depreciation and amortization,

• higher other operations revenue,

• higher allowance for equity funds used during construction, and

• higher gain on the sale of an asset.

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The following tables show the components of Cleco Power’s base revenue:

	FOR THE YEAR ENDED DEC. 31,
(MILLION kWh)	2016			2015			FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential		3,646			3,789			(3.8	)%
Commercial		2,708			2,763			(2.0	)%
Industrial		1,978			1,927			2.6	%
Other retail		132			134			(1.5	)%
Total retail		8,464			8,613			(1.7	)%
Sales for resale		3,140			3,353			(6.4	)%
Unbilled		55			(95	)		157.9	%
Total retail and wholesale customer sales		11,659			11,871			(1.8	)%
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016			2015			FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	$	293,461		$	296,846			(1.1	)%
Commercial		192,332			191,202			0.6	%
Industrial		86,668			84,988			2.0	%
Other retail		10,630			10,558			0.7	%
Surcharge		21,418			21,597			(0.8	)%
Total retail	$	604,509		$	605,191			(0.1	)%
Sales for resale		59,103			62,768			(5.8	)%
Unbilled		(2,638	)		2,571			(202.6	)%
Total retail and wholesale customer sales	$	660,974		$	670,530			(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 NOAA to determine cooling and heating degree-days.

	FOR THE YEAR ENDED DEC. 31,
							2016 CHANGE
	2016		2015		NORMAL		PRIOR YEAR			NORMAL
Cooling degree-days		3,309		3,272		2,779		1.1	%		19.1	%
Heating degree-days		1,145		1,271		1,546		(9.9	)%		(25.9	)%

Base

Base revenue decreased $9.6 million in 2016 compared to 2015 primarily due to $6.4 million of lower sales due to usage, including warmer winter weather and lower sales to wholesale customers and $3.2 million driven by lower revenue related to the absence of additional MATS revenue recognized in 2015.

Cleco Power expects to begin providing service to expansions of current customers’ operations, as well as service to new retail customers. These expansions of current customers’ operations and service to new retail customers are expected to contribute additional base revenue of $1.9 million in 2017, an additional $1.8 million in 2018, and an additional $0.1 million in 2019. Cleco Power expects wholesale revenue to decrease by $0.7 million in 2017 primarily due to the restructuring of contracts. Cleco Power expects $0.3 million of additional wholesale revenue in 2018 and an additional $1.5 million of wholesale revenue in 2019. For information on other

43

expectations of future energy sales on Cleco Power, see “—Significant Factors Affecting Cleco Power,” “Cautionary Note Regarding Forward-Looking Statements,” and “Risk Factors—Future Electricity Sales.”

Fuel Cost Recovery/Recoverable Fuel and Power Purchased

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 75% of Cleco Power’s total fuel costs during 2016 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 on the accounting for MISO transactions, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 2—Summary of Significant Accounting Policies—Accounting for MISO Transactions.” For more information on Cleco Power’s fuel audit, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 15—Litigation, Other Commitments and Contingencies, and Disclosure about Guarantees—Litigation—LPSC Audits—Fuel Audit.”

Other Operations Revenue

Other operations revenue increased $1.5 million in 2016 compared to 2015 primarily due to $2.8 million of higher transmission revenue from a wholesale customer and $0.6 million of higher pole attachment rentals. These increases were partially offset by $1.7 million of lower forfeited discounts mostly due to customer rate credits in the third quarter of 2016 as a result of the Merger and $0.2 million of lower miscellaneous revenue.

Non-recoverable Fuel and Power Purchased

Non-recoverable fuel and power purchased increased $4.3 million in 2016 compared to 2015 primarily related to $3.1 million of higher expenses related to MISO transmission costs and $1.3 million of expenses related to fuel accounting software, partially offset by $0.1 million of lower miscellaneous expenses.

Other Operations Expense

Other operations expense decreased $2.8 million in 2016 compared to 2015 primarily due to $5.4 million of lower administrative and general expenses driven by lower salaries and benefits expense and $0.1 million of lower miscellaneous expense. These decreases were partially offset by $1.6 million of higher generation expense and $1.1 million of higher customer service expense primarily related to an increase in the provision for uncollectible accounts.

Maintenance

Maintenance expense increased $5.9 million in 2016 compared to 2015 primarily due to higher generating station outage expenses.

Depreciation and Amortization

Depreciation and amortization expense decreased $1.7 million in 2016 compared to 2015 primarily due to $5.5 million of higher deferrals of production operations and maintenance expenses to a regulatory asset, $1.3 million of higher deferrals of corporate franchise taxes to a regulatory asset, and $0.5 million of lower amortization of the corporate franchise taxes regulatory asset. These decreases were partially offset by $3.1 million of normal recurring additions to fixed assets, $1.6 million of higher amortization of the production operations and maintenance regulatory asset, $0.8 million of higher amortization of storm damages which is based on collections from customers, and $0.1 million of miscellaneous amortizations.

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Taxes Other than Income Taxes

Taxes other than income taxes increased $1.2 million in 2016 compared to 2015 primarily due to higher property taxes.

Merger Commitment Costs

Merger commitment costs increased $151.5 million in 2016 compared to 2015 due to $136.0 million of customer rate credits, a $7.0 million one-time contribution for economic development in Cleco Power’s service territory to be administered by the LED, a $6.0 million accrual of charitable contributions to be disbursed over five years, and $2.5 million of contributions for economic development for Louisiana state and local organizations to be disbursed over five years.

Gain on Sale of Asset

Gain on sale of asset increased $1.1 million in 2016 compared to 2015 due to a gain on the sale of property.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $1.4 million in 2016 compared to 2015 primarily due to higher construction costs related to various projects.

Income Taxes

Federal and state income taxes decreased $60.9 million in 2016 compared to 2015. Tax expense decreased primarily due to $64.5 million for the change in pretax income, excluding AFUDC equity and $2.3 million for adjustments for tax returns filed. These decreases were partially offset by $4.5 million for the flowthrough of state tax benefits, $0.9 million for tax credits, $0.3 million for miscellaneous tax items, and $0.2 million for adjustments for permanent tax differences. The effective income tax rate is 32.0%, which is lower 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.

Comparison of the Years Ended December 31, 2015, and 2014

Cleco Consolidated

Cleco Consolidated Results of Operations

	FOR THE YEAR ENDED DEC. 31,
					FAVORABLE/ (UNFAVORABLE)
(THOUSANDS)	2015		2014		VARIANCE			CHANGE
Operating revenue, net	$	1,209,402	$	1,269,485	$	(60,083	)		(4.7	)%
Operating expenses		922,063		983,453		61,390			6.2	%
Operating income	$	287,339	$	286,032	$	1,307			0.5	%
Allowance for other funds used during construction	$	3,063	$	5,380	$	(2,317	)		(43.1	)%
Other income	$	1,443	$	4,790	$	(3,347	)		(69.9	)%
Other expense	$	3,376	$	2,509	$	(867	)		(34.6	)%
Interest charges	$	77,991	$	73,606	$	(4,385	)		(6.0	)%
Federal and state income tax expense	$	77,704	$	67,116	$	(10,588	)		(15.8	)%
Net income	$	133,669	$	154,739	$	(21,070	)		(13.6	)%

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Operating revenue, net of electric customer credits decreased $60.1 million in 2015 compared to 2014 largely as a result of lower fuel cost recovery and lower base revenue, partially offset by lower electric customer credits and higher other operations revenue at Cleco Power.

Operating expenses decreased $61.4 million in 2015 compared to 2014 primarily due to lower recoverable fuel and power purchased at Cleco Power, lower merger transaction costs incurred at Cleco Holdings, and lower generation maintenance expense at Cleco Power. Partially offsetting these decreases were higher non-recoverable fuel and power purchased due to the expiration of a PPA when Coughlin was transferred to Cleco Power in March 2014, higher other operations expense at Cleco Power, the absence of the gain on the sale of property at Cleco Holdings, higher taxes other than income taxes at Cleco Power, and higher depreciation and amortization expense at Cleco Power.

Allowance for equity funds used during construction decreased $2.3 million in 2015 compared to 2014 primarily due to lower construction costs related to the completion of the MATS project at Cleco Power.

Other income decreased $3.3 million in 2015 compared to 2014 primarily due to the absence of an increase in the cash surrender value of life insurance policies and the absence of the contractual expiration of underlying indemnifications resulting from the disposition of Acadia Unit 2.

Other expense increased $0.9 million in 2015 compared to 2014 primarily due to a decrease in the cash surrender value of life insurance policies due to unfavorable market conditions.

Interest charges increased $4.4 million in 2015 compared to 2014 primarily due to the absence of favorable settlements with taxing authorities and lower allowance for borrowed funds used during construction primarily related to the MATS project. These increases were partially offset by the absence of the customer surcredit and the retirement of long-term debt.

Federal and state income taxes increased $10.6 million in 2015 compared to 2014. Tax expense increased primarily due to $9.3 million for the absence of favorable settlements with taxing authorities, $2.5 million for the flowthrough of state tax benefits, $1.1 million for miscellaneous tax items, and $0.8 million for adjustments for tax returns filed. These increases were partially offset by $3.1 million for the change in pretax income, excluding AFUDC equity. The effective income tax rate was 36.8%, which is higher 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.

The effective tax rate of 36.8% for 2015 was higher than the effective tax rate of 30.3% for 2014 due to the absence of favorable settlements with taxing authorities, tax returns as filed, and the flowthrough of state tax benefits, partially offset by the change in pretax income, excluding AFUDC equity.

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

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Cleco Power

Cleco Power Results of Operations

	FOR THE YEAR ENDED DEC. 31,
							FAVORABLE/ (UNFAVORABLE)
(THOUSANDS)	2015			2014			VARIANCE			CHANGE
Operating revenue
Base	$	670,530		$	683,565		$	(13,035	)		(1.9	)%
Fuel cost recovery		471,859			542,395			(70,536	)		(13.0	)%
Electric customer credits		(2,173	)		(23,530	)		21,357			90.8	%
Other operations		67,109			64,893			2,216			3.4	%
Affiliate revenue		1,142			1,326			(184	)		(13.9	)%
Operating revenue, net	$	1,208,467		$	1,268,649		$	(60,182	)		(4.7	)%
Operating expenses
Recoverable fuel and power purchased		471,864			542,397			70,533			13.0	%
Non-recoverable fuel and power purchased		31,348			27,985			(3,363	)		(12.0	)%
Other operations		128,697			116,664			(12,033	)		(10.3	)%
Maintenance		87,416			96,054			8,638			9.0	%
Depreciation and amortization		147,839			144,026			(3,813	)		(2.6	)%
Taxes other than income taxes		47,102			41,812			(5,290	)		(12.7	)%
Gain on sales of assets		—			(4	)		(4	)		(100.0	)%
Total operating expenses		914,266			968,934			54,668			5.6	%
Operating income	$	294,201		$	299,715		$	(5,514	)		(1.8	)%
Allowance for equity funds used during construction	$	3,063		$	5,380		$	(2,317	)		(43.1	)%
Interest charges	$	76,560		$	74,673		$	(1,887	)		(2.5	)%
Federal and state income tax expense	$	79,294		$	76,974		$	(2,320	)		(3.0	)%
Net income	$	141,350		$	154,316		$	(12,966	)		(8.4	)%

Cleco Power’s net income for 2015 decreased $13.0 million compared to 2014. Contributing factors include:

• lower base revenue,

• higher other operations expense,

• higher taxes other than income taxes,

• higher depreciation and amortization,

• higher non-recoverable fuel and power purchased,

• higher income taxes,

• lower allowance for equity funds used during construction, and

• higher interest charges.

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These were partially offset by lower electric customer credits, lower maintenance expense, and higher other operations revenue.

	FOR THE YEAR ENDED DEC. 31,
(MILLION kWh)	2015			2014		FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential		3,789			3,783		0.2	%
Commercial		2,763			2,689		2.8	%
Industrial		1,927			2,212		(12.9	)%
Other retail		134			130		3.1	%
Total retail		8,613			8,814		(2.3	)%
Sales for resale		3,353			3,412		(1.7	)%
Unbilled		(95	)		171		(155.6	)%
Total retail and wholesale customer sales		11,871			12,397		(4.2	)%

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2015		2014		FAVORABLE/ (UNFAVORABLE)
Electric sales
Residential	$	296,846	$	293,871		1.0	%
Commercial		191,202		188,012		1.7	%
Industrial		84,988		86,823		(2.1	)%
Other retail		10,558		10,215		3.4	%
Storm surcharge		21,597		15,833		36.4	%
Total retail	$	605,191	$	594,754		1.8	%
Sales for resale		62,768		81,371		(22.9	)%
Unbilled		2,571		7,440		(65.4	)%
Total retail and wholesale customer sales	$	670,530	$	683,565		(1.9	)%

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,
							2015 CHANGE
	2015		2014		NORMAL		PRIOR YEAR			NORMAL
Cooling degree-days		3,272		2,780		2,780		17.7	%		17.7	%
Heating degree-days		1,271		1,833		1,546		(30.7	)%		(17.8	)%

Base

Base revenue decreased $13.0 million in 2015 compared to 2014 primarily due to lower net sales to wholesale customers, including the expiration of a wholesale contract in December 2014, and lower rates that began July 1, 2014, related to the FRP extension. These decreases were partially offset by higher revenue related to MATS and higher retail revenue related to usage.

Fuel Cost Recovery/Recoverable Fuel and Power Purchased

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

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pass on to its customers substantially all such charges. Approximately 74% of Cleco Power’s total fuel cost during 2015 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 on the accounting for MISO transactions, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 2—Summary of Significant Accounting Policies—Accounting for MISO Transactions.” For more information on Cleco Power’s fuel audit, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 15—Litigation, Other Commitments and Contingencies, and Disclosure about Guarantees—Litigation—LPSC Audits—Fuel Audit.”

Electric Customer Credits

Electric customer credits decreased $21.4 million in 2015 compared to 2014 primarily due to the absence of $22.3 million of provisions for refunds included in the June 2014 FRP extension and $1.6 million related to lower accruals for site-specific customers. These amounts were partially offset by $2.5 million related to accruals for anticipated refunds related to the transmission ROE dispute. For more information on the FRP extension and the accrual of electric customer credits, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 12—Regulation and Rates.” For more information on the transmission ROE dispute, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 15—Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Litigation—Transmission ROE.”

Other Operations Revenue

Other operations revenue increased $2.2 million in 2015 compared to 2014 primarily due to $3.5 million of higher transmission and distribution revenue, partially offset by $0.4 million of lower forfeited discounts, $0.3 million of lower reconnection fees, $0.3 million due to the absence of a gain associated with the extinguishment of the asbestos ARO, and $0.3 million of lower miscellaneous revenue.

Non-Recoverable Fuel and Power Purchased

Non-recoverable fuel and power purchased increased $3.4 million in 2015 compared to 2014 primarily related to $4.5 million of higher MISO transmission expenses and administrative fees and $0.1 million of higher miscellaneous expenses, partially offset by $0.6 million of lower capacity charges and $0.6 million for a one-time facility credit.

Other Operations Expense

Other operations expense increased $12.0 million in 2015 compared to 2014 primarily due to higher customer service expense, higher administrative and general expenses, driven by higher pension expense, and higher generation expense.

Maintenance

Maintenance expense decreased $8.6 million in 2015 compared to 2014 primarily due to lower generating station outage expenses.

Depreciation and Amortization

Depreciation and amortization expense increased $3.8 million in 2015 compared to 2014 primarily due to $6.0 million of lower deferrals of production operations and maintenance expenses to a regulatory asset, $3.9 million of normal recurring additions to fixed assets, and $3.2 million for the amortization of regulatory assets

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related to the FRP extension. The increase was also due to $1.9 million of amortization related to a regulatory asset for state corporate franchise taxes, $1.2 million for the absence of the deferral of AMI revenue requirements to a regulatory asset, and $1.1 million of higher miscellaneous amortization. These amounts were partially offset by $13.5 million for the absence of amortization of the Evangeline PPA capacity costs.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5.3 million in 2015 compared to 2014 primarily due to the absence of favorable settlements with taxing authorities.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction decreased $2.3 million in 2015 compared to 2014 primarily due to lower construction costs related to the completion of the MATS project.

Interest Charges

Interest charges increased $1.9 million in 2015 compared to 2014 primarily due to $5.0 million related to the absence of favorable settlements with taxing authorities and $0.7 million related to lower allowance for borrowed funds used during construction primarily related to the completion of the MATS project. These increases were partially offset by $2.1 million related to the absence of the customer surcredit, $1.6 million due to the retirement of long-term debt, and $0.1 million of lower miscellaneous interest charges.

Income Taxes

Federal and state income taxes increased $2.3 million in 2015 compared to 2014. Tax expense increased primarily due to $2.5 million for the flowthrough of state tax benefits, $2.2 million for the absence of favorable settlements with taxing authorities, and $0.8 million for miscellaneous tax items. These increases were partially offset by $3.2 for the change in pretax income, excluding AFUDC equity. The effective income tax rate was 35.9%, which is higher 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.

CLECO POWER—NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2016, and the year ended December 31, 2015, see “—Results of Operations—Comparison of the Years Ended December 31, 2016, and 2015—Cleco Power.”

For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2015, and the year ended December 31, 2014, see “—Results of Operations—Comparison of the Years Ended December 31, 2015, and 2014—Cleco Power.”

The narrative analysis referenced above should be read in combination with Cleco Power’s Financial Statements and the Notes contained in this prospectus.

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

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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 Financial Statements—Note 2—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 2016 return on plan assets was 10.90% compared to an expected long-term return of 6.21%. For 2015, the return on plan assets was (2.90)% compared to an expected long-term return of 6.15%. For the calculation of the 2017 periodic expense, Cleco decreased the expected long-term return on plan assets to 6.08%.

Management uses a theoretical bond portfolio in order to calculate the discount rate for the measurement of liabilities. Due to the Merger, the pension plan was remeasured at the Merger date, resulting in a decrease to the discount rate from 4.62% to 4.21%. After the annual review of assumptions, the pension plan discount rate increased from 4.21% to 4.27% for the December 31, 2016, 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 10 years as of December 31, 2016, for Cleco’s plan) when it exceeds certain thresholds. This approach of 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.

In October 2014, the Society of Actuaries released a new set of mortality tables and a new mortality improvement scale which indicated significant increases to life expectancies. As a result, in December 2014, Cleco updated its mortality assumptions using the new base table and an adjusted mortality improvement scale. The updates resulted in an increase of $28.1 million in the pension plan obligation at December 31, 2014. Also, these updated mortality assumptions increased pension expense by approximately $5.3 million in 2015 compared to 2014.

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In October 2015, the Society of Actuaries released another updated mortality improvement scale which indicated lower mortality improvements than previously indicated in the 2014 mortality improvement scale. As a result, in December 2015, Cleco updated its mortality assumptions using the new data released by the Society of Actuaries. The update resulted in a decrease of $7.2 million in the pension plan obligation at December 31, 2015.

In October 2016, the Society of Actuaries released another updated mortality improvement scale which indicated lower mortality improvements than previously indicated in the 2015 mortality improvement scale. As a result, in December 2016, Cleco updated its mortality assumptions using the new data released by the Society of Actuaries. The update resulted in a decrease of $6.8 million in the pension plan obligation at December 31, 2016.

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	$	(34,749	)	$	(3,270	)
		0.5% decrease	$	38,969		$	3,604
Salary scale		0.5% increase	$	8,146		$	1,546
		0.5% decrease	$	(7,384	)	$	(1,397	)
Expected return on assets		0.5% increase	$	—		$	(1,980	)
		0.5% decrease	$	—		$	1,980

Cleco Power did not make any required or discretionary contributions to the pension plan in 2016, 2015, or 2014. Based on current funding assumptions, management estimates that $44.0 million in pension contributions will be required through 2021. 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 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 December 31, 2016, Cleco Power had $544.0 million in regulatory assets. As a result of the Merger, Cleco Holdings recognized regulatory assets. At December 31, 2016, Cleco Holdings had $195.7 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 Financial Statements—Note 2—Summary of Significant Accounting Policies—Regulation,” and “Note 4—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

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current or prior years. Cleco makes assumptions and estimates when it records income taxes, such as its ability to deduct items on its tax returns, the timing of the deduction, and the effect of regulation by the LPSC on income taxes. Cleco’s income tax expense and related assets and liabilities could be affected by changes in its assumptions and estimates and by ultimate resolution of assumptions and estimates with taxing authorities. The actual results may differ from the estimated results based on these assumptions and may have a material effect on Cleco’s results of operations.

For more information on income taxes, see “Financial Statements and Supplemental Data—Notes to the 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—Litigation,” and “Financial Statements and Supplemental Data—Notes to the Financial Statements—Note 15—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. Additionally, on the date of the 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 Merger, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 17—Intangible Assets 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 December 31, 2016, the carrying value of Cleco Power’s long-lived assets was $3.17 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 currently has FAC filings for 2016 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 Financial Statements—Note 15—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, 2016, and 2015—Cleco Power—Cleco Power’s Results of Operations—Fuel Cost Recovery/Recoverable Fuel and Power Purchased.”

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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, 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 December 31, 2016:

	SENIOR UNSECURED DEBT		CORPORATE CREDIT
	MOODY’S	S&P	S&P
Cleco Holdings	Baa3	N/A	BBB-
Cleco Power	A3	BBB+	BBB+

On April 8, 2016, S&P and Moody’s updated the credit ratings for Cleco Holdings and Cleco Power, taking into consideration the anticipated completion of the Merger. S&P credit ratings were maintained at Cleco Power at BBB+ (stable) and downgraded at Cleco Holdings from BBB+ (stable) to BBB- (stable). Moody’s credit ratings were maintained at Cleco Power at A3 (stable) and downgraded at Cleco Holdings from Baa1 (stable) to Baa3 (stable).

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

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 by Moody’s or S&P, Cleco Holdings and/or Cleco Power would be required to pay additional fees and incur higher interest rates for borrowings under their respective credit facilities.

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

Cleco Power participates in the MISO market, which 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. MISO requires Cleco Power to provide credit support which may increase or decrease due to the timing of the settlement schedules. At December 31, 2016, Cleco Power had a $2.0 million letter of credit to MISO pursuant to the credit requirements of FTRs. The letter of credit automatically renews each year. For more information about MISO, see “—Regulatory and Other Matters—Transmission Rates of Cleco Power.”

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Global and U.S. 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 the Company has not experienced restrictions in the financial markets, its ability to access the capital markets may be restricted at a time when the Company would like, or need, to do so. Any restrictions could have a material impact on the Company’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 the Company’s lenders or customers, causing them to fail to meet their obligations to the Company or to delay payment of such obligations. The lower interest rates to which the Company has been exposed have been beneficial to debt issuances; however, these rates have negatively affected interest income for the Company’s short-term investments.

Fair Value Measurements

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values. Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance. Cleco and Cleco Power are required to disclose the fair value of certain assets and liabilities by one of three levels. Other financial assets and liabilities, such as long-term debt, are reported at their carrying values at their date of issuance on the consolidated balance sheets with their fair values 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 Financial Statements—Note 6—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 company purposes. Cleco and Cleco Power’s restricted cash and cash equivalents consisted of:

Cleco
	SUCCESSOR		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current
Cleco Katrina/Rita’s storm recovery bonds	$	9,213	$	9,263
Cleco Power’s charitable contributions		1,200		—
Cleco Power’s rate credit escrow		12,671		—
Total current		23,084		9,263
Non-current
Diversified Lands’ mitigation escrow		21		21
Cleco Power’s future storm restoration costs		17,379		16,174
Cleco Power’s charitable contributions		4,179		—
Cleco Power’s rate credit escrow		1,831		—
Total non-current		23,410		16,195
Total restricted cash and cash equivalents	$	46,494	$	25,458

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Cleco Power
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current
Cleco Katrina/Rita’s storm recovery bonds	$	9,213	$	9,263
Charitable contributions		1,200		—
Rate credit escrow		12,671		—
Total current		23,084		9,263
Non-current
Future storm restoration costs		17,379		16,174
Charitable contributions		4,179		—
Rate credit escrow		1,831		—
Total non-current		23,389		16,174
Total restricted cash and cash equivalents	$	46,473	$	25,437

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. The change from December 31, 2015, to 2016 was due to Cleco Katrina/Rita collecting $21.2 million net of administration fees, partially offset by bond and interest payments. In March and September 2016, Cleco Katrina/Rita used $8.5 million and $8.3 million, respectively, for scheduled storm recovery bond principal payments and $2.3 million and $2.1 million, respectively, for related interest payments.

Included in the Merger Commitments were $6.0 million of charitable contributions to be disbursed over five years and $136.0 million of rate credits to eligible customers. On April 25, 2016, in accordance with the Merger Commitments, Cleco Power established the charitable contribution fund and deposited the rate credit funds into an escrow account. On April 28, 2016, the LPSC voted to issue the rate credits equally to customers with service as of June 30, 2016, beginning in July 2016. As of December 31, 2016, $0.6 million of the charitable contributions and $121.5 million of the rate credits had been remitted from restricted cash.

Debt

Cleco Consolidated

Cleco had no short-term debt outstanding at December 31, 2016, or 2015.

At December 31, 2016, Cleco’s long-term debt outstanding was $2.76 billion, of which $19.7 million was due within one year. The long-term debt due within one year at December 31, 2016, represents $17.9 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments.

In connection with the completion of the Merger, on April 13, 2016, Cleco Holdings entered into a $1.35 billion Acquisition Loan Facility. The Acquisition Loan Facility had a three-year term and a rate of LIBOR plus 1.75% or ABR plus 0.75%. In May and June 2016, Cleco Holdings refinanced the Acquisition Loan Facility with a series of other long-term financings described below.

On May 17, 2016, Cleco Holdings completed the private sale of $535.0 million of 3.743% senior notes due May 1, 2026, and $350.0 million of 4.973% senior notes due May 1, 2046. On May 24, 2016, Cleco Holdings completed the private sale of $165.0 million of 3.250% senior notes due May 1, 2023. On June 28, 2016, Cleco Holdings entered into a $300.0 million variable rate bank term loan due June 28, 2021. Amounts outstanding under the bank term loan bear interest, at Cleco’s option, at a base rate plus 0.625% or LIBOR plus 1.625%. At December 31, 2016, the all-in rate was 2.265%, which was based on the LIBOR rate. The proceeds from the issuance and sale of these notes and term loan were used to repay the $1.35 billion Acquisition Loan Facility. Debt issuance costs of $17.7 million were expensed to merger costs in connection with the repayment of the Acquisition Loan Facility.

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Cash and cash equivalents available at December 31, 2016, were $23.1 million combined with $400.0 million available credit facility capacity ($100.0 million from Cleco Holdings and $300.0 million from Cleco Power) for total liquidity of $423.1 million.

At December 31, 2016, 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 Financial Statements—Note 6—Fair Value Accounting.”

For the successor period December 31, 2016, Cleco had a working capital surplus of $174.9 million. There were no significant changes in the underlying trends impacting working capital for the successor period with the exceptions of a $14.4 million increase in provisions for the Merger Commitments, a $13.9 million increase in restricted cash and cash equivalents primarily due to the funding of customer rate credits as a result of the Merger Commitments, and a $8.5 million regulatory asset related to fair value adjustments of long-term debt as a result of the Merger.

For the predecessor period December 31, 2015, Cleco had a working capital surplus of $242.3 million. There were no significant changes in the underlying trends impacting working capital for the predecessor period.

For the successor period December 31, 2016, Cleco’s Consolidated Balance Sheets reflected $4.30 billion of total liabilities. There were no significant changes in the underlying trends impacting total liabilities for the successor period with the exception of the $1.35 billion of long-term debt previously discussed, $155.8 million for the difference between the carrying value and the fair value of long-term debt recorded as a result of the Merger, and a $14.4 million increase in provisions for the Merger Commitments.

For the predecessor period December 31, 2015, Cleco’s Consolidated Balance Sheets reflected $2.65 billion of total liabilities. There were no significant changes in the underlying trends impacting total liabilities for the predecessor period.

Cleco Holdings (Holding Company Level)

Cleco Holdings had no short-term debt outstanding at December 31, 2016, or 2015.

At December 31, 2016, Cleco Holding’s long-term debt outstanding was $1.34 billion, of which none was due within one year.

In connection with the completion of the Merger, on April 13, 2016, Cleco Holdings entered into a $1.35 billion Acquisition Loan Facility. In May and June 2016, Cleco Holdings refinanced the Acquisition Loan Facility with a series of other long-term financings described below.

On May 17, 2016, Cleco Holdings completed the private sale of $535.0 million of 3.743% senior notes due May 1, 2026, and $350.0 million of 4.973% senior notes due May 1, 2046. On May 24, 2016, Cleco Holdings completed the private sale of $165.0 million of 3.250% senior notes due May 1, 2023. On June 28, 2016, Cleco Holdings entered into a $300.0 million variable rate bank term loan due June 28, 2021. The proceeds from the issuance and sale of these notes and term loan were used to repay the $1.35 billion Acquisition Loan Facility. Debt issuance costs of $17.7 million were expensed to merger costs in connection with the repayment of the Acquisition Loan Facility.

On April 13, 2016, in connection with the completion of the Merger, Cleco Holdings replaced its existing $250.0 million credit facility with a $100.0 million credit facility. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021. This facility provides for working capital and other needs. At December 31, 2016, Cleco Holdings had no draws outstanding under its $100.0 million credit facility.

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Cleco Holdings and Cleco Power have uncommitted lines of credit with a bank that allow up to $10.0 million each in short-term borrowings, but no more than $10.0 million in aggregate, to support their working capital needs.

Cash and cash equivalents available at Cleco Holdings at December 31, 2016, were $1.4 million, combined with $100.0 million credit facility capacity for a total liquidity of $101.4 million.

Cleco Power

There was no short-term debt outstanding at Cleco Power at December 31, 2016, or 2015.

At December 31, 2016, Cleco Power’s long-term debt outstanding was $1.25 billion, of which $19.7 million was due within one year. The long-term debt due within one year at December 31, 2016, represents $17.9 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments. For Cleco Power, long-term debt increased $1.3 million from December 31, 2015, primarily due to the issuance of $330.0 million senior notes in December 2016, debt discount amortizations of $0.5 million, and $0.2 million in debt expense amortization. These increases were partially offset by a $250.0 million repayment of senior notes in December 2016, a $60.0 million repayment of Solid Waste Disposal Facility Bonds in November 2016, $16.8 million of scheduled Cleco Katrina/Rita storm recovery bond principal payments made in March and September 2016, and a $2.6 million decrease in capital lease obligations.

On April 13, 2016, in connection with the completion of the Merger, Cleco Power replaced its existing $300.0 million credit facility with a new $300.0 million credit facility. This facility provides for working capital and other financing needs. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021.

On November 1, 2016, Cleco Power redeemed at par $60.0 million of 4.70% Solid Waste Disposal Facility bonds due November 2036. As part of the redemption, Cleco Power paid $1.4 million of accrued interest on the redeemed bonds.

On December 20, 2016, Cleco Power completed the private sale of $130.0 million of 3.47% senior notes due December 16, 2026, and $200.0 million of 3.57% senior notes due December 16, 2028. The proceeds from the issuance and sale of these notes were used to replace cash used to redeem the above mentioned Solid Waste Disposal Facility bonds, to redeem $250.0 million of 6.65% senior notes due 2018 prior to maturity and pay make-whole payments of approximately $19.0 million in connection with such redemption, and for general company purposes.

At December 31, 2016, and 2015, Cleco Power had no borrowings outstanding under its $300.0 million credit facility. At December 31, 2016, Cleco Power had a $2.0 million letter of credit to MISO pursuant to the credit requirements of FTRs. This credit facility is covered under a standing letter of credit outside of Cleco Power’s credit facility; therefore, it does not reduce the borrowing capacity of Cleco Power’s new credit facility.

Cleco Holdings and Cleco Power have uncommitted lines of credit with a bank that allow up to $10.0 million each in short-term borrowings, but no more than $10.0 million in aggregate, to support their working capital needs.

Cash and cash equivalents available at December 31, 2016, were $21.5 million combined with $300.0 million credit facility capacity for total liquidity of $321.5 million.

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At December 31, 2016, and 2015, Cleco Power had a working capital surplus of $149.1 million and $184.9 million, respectively. The $35.8 million decrease in working capital is primarily due to:

• a $44.2 million decrease in unrestricted cash and cash equivalents,

• a $26.4 million decrease in fuel inventory primarily due to decreases in solid fuels inventory due to higher than normal levels in 2015, an adjustment related to a fuel survey, and lower lignite deliveries,

• a $16.9 million increase in accounts payable (excluding FTR purchases) primarily related to the timing of property taxes and vendor payments, and

• a $14.4 million increase in the provision for the Merger Commitments.

These decreases in working capital were partially offset by:

• a $29.5 million net increase in net current tax assets and related interest charges primarily due to the creation of the net operating loss carryforward

• a $13.8 million increase in restricted cash and cash equivalents,

• a $13.5 million increase in customer accounts receivable due to timing of receipts from wholesale customers and an increase in retail customer receivables, and

• an $11.4 million increase in accumulated deferred fuel primarily due to a fuel surcharge.

At December 31, 2016, Cleco Power’s Consolidated Balance Sheets reflected $2.73 billion of total liabilities compared to $2.68 billion at December 31, 2015. The $51.3 million increase in total liabilities during 2016 was primarily due to increases in provision for the Merger Commitments, accounts payable, accumulated deferred federal and state income taxes, postretirement benefit obligations, offset by a decrease in taxes payable. During 2016, the provision for the Merger Commitments increased $14.4 million. Accounts payable increased $13.6 million as a result of the timing of property tax payments and vendor payments. Net accumulated deferred federal and state income taxes increased $25.1 million as a result of the creation of the net operating loss carryforward in 2016 versus the utilization of a net operating loss carryforward in 2015. Postretirement benefit obligations also increased $7.0 million primarily due to lower discount rates, partially offset by greater than expected return on plan assets and updated mortality tables. These increases were partially offset by a decrease in taxes payable of $17.0 million due to a decrease in pretax income.

Credit Facilities

At December 31, 2016, Cleco had two separate revolving credit facilities, one for Cleco Holdings and one for Cleco Power, with a maximum aggregate capacity of $400.0 million.

At December 31, 2015, Cleco Holdings had a $250.0 million credit facility. On April 13, 2016, in connection with the completion of the Merger, Cleco Holdings replaced the existing credit facility with a $100.0 million credit facility. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021. At December 31, 2016, Cleco Holdings was in compliance with the covenants of its credit facility. 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 December 31, 2016, Cleco Holdings had no borrowings outstanding under its $100.0 million credit facility. If Cleco Holdings’ credit ratings were to be downgraded one level by either agency, Cleco Holdings would be required to pay higher fees and additional interest of 0.075% and 0.50%, respectively, under the pricing levels for its credit facility.

At December 31, 2015, Cleco Power had a $300.0 million credit facility. On April 13, 2016, in connection with the completion of the Merger, Cleco Power replaced its existing credit facility. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021. At December 31, 2016, Cleco Power was in compliance with the covenants of its credit facility. The borrowing

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costs under the facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%. At December 31, 2016, Cleco Power had no borrowings outstanding under its $300.0 million credit facility. If Cleco Power’s credit ratings were to be downgraded one level by either agency, Cleco Power would be required to pay higher fees and additional interest of 0.05% and 0.125%, respectively, under the pricing levels of its credit facility. A $2.0 million letter of credit issued to MISO is covered under a standing letter of credit outside of Cleco Power’s credit facility; therefore, it does not reduce the borrowing capacity of Cleco Power’s new credit facility. The letter of credit issued to MISO is pursuant to the credit requirements of FTRs. The letter of credit automatically renews each year.

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 Limitations

The Merger Commitments provide for limitations on the amount of distributions that may be paid from Cleco Holdings to Cleco Group or Cleco Partners, depending on Cleco Holdings’ debt to EBITDA ratio and its corporate credit ratings. Additionally, in accordance with the Merger Commitments, Cleco Power is subjected 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. The Merger Commitments also prohibit Cleco from incurring additional long-term debt, excluding non-recourse debt, unless certain financial ratios are achieved. At December 31, 2016 Cleco Holdings and Cleco Power exceeded the limitations that would limit the amount of distributions available. For more information on additional merger commitments, see “Risk Factors—Holding Company.”

Cleco Cash Flows

Net Operating Cash Flow

Net cash provided by operating activities for the successor period April 13, 2016, through December 31, 2016, was $51.3 million. There were no significant changes in the underlying trends impacting cash provided by operating activities with the exception of the following:

• lower collections from customers of $121.5 million due to Merger credits issued in 2016, and

• $23.7 million related to payments for merger transaction costs.

Net cash provided by operating activities for the predecessor period January 1, 2016, through April 12, 2016, was $129.8 million. There were no significant changes in the underlying trends impacting cash provided by operating activities.

Net cash provided by operating activities for the predecessor period January 1, 2015, through December 31, 2015, increased $25.8 million from the predecessor period January 1, 2014, through December 31, 2014, due to the following items:

• lower net fuel and power purchases of $21.5 million primarily due to the absence of a plant outage, the loss of a wholesale customer, timing of collections, and lower per unit gas prices,

• lower payments to gas vendors of $18.4 million primarily due to lower per unit prices,

• lower payments for generating station outage expenses of $15.9 million, and

• lower income tax payments of $13.9 million.

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These increases in net operating cash were partially offset by higher payments to vendors of $49.9 million primarily related to the timing of property tax payments and other vendor payments.

For information on Cleco’s investing and financing activities for the predecessor and successor periods, see “Financial Statements and Supplementary Data—Cleco—Consolidated Statements of Cash Flows.”

Cleco Power Cash Flows

Net Operating Cash Flow

Net cash provided by operating activities was $215.8 million during 2016, $366.5 million during 2015, and $347.1 million during 2014. Net cash provided by operating activities during 2016 decreased $150.7 million from 2015 primarily due to the following items:

• lower collections from customers of $121.5 million due to Merger credits issued in 2016,

• higher payments for affiliate settlements of $34.0 million, and

• lower net fuel and power purchase collections of $17.1 million primarily due to timing of recovery.

These decreases in net operating cash were partially offset by:

• lower payments to vendors of $28.9 million primarily related to the timing of property tax payments and other vendor payments and

• lower payments for fuel inventory of $26.8 million primarily due to lower lignite deliveries and lower petroleum coke purchases.

Net cash provided by operating activities during 2015 increased $19.4 million from 2014 primarily due to the following items:

• lower net fuel and power purchases of $21.5 million primarily due to the absence of a plant outage, the loss of a wholesale customer, timing of collections, and lower per unit gas prices,

• lower payments to gas vendors of $18.4 million primarily due to lower per unit prices, and

• lower payments for generating station outage expenses of $15.9 million.

These increases in net operating cash were partially offset by higher payments to vendors of $46.2 million primarily related to the timing of property tax payments and other vendor payments.

For information on Cleco Power’s investing and financing activities, see “Financial Statements and Supplementary Data—Cleco Power—Consolidated Statements of Cash Flows.”

Capital Expenditures

Cleco’s capital expenditures are primarily incurred in its major first-tier subsidiary, Cleco Power. 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.

During the years ended December 31, 2016, 2015, and 2014, Cleco Power had capital expenditures, excluding AFUDC, of $181.7 million, $153.3 million, and $201.2 million, respectively. In 2016, 2015, and 2014, 100% of Cleco Power’s capital expenditure requirements were funded internally.

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For the successor period April 13, 2016, through December 31, 2016, other subsidiaries had capital expenditures, excluding AFUDC, of $0.7 million. Other subsidiaries had capital expenditures, excluding AFUDC, of less than $0.1 million, $0.5 million, and $1.0 million during the predecessor periods January 1, 2016, through April 12, 2016, January 1, 2015, through December 31, 2015, and January 1, 2014, through December 31, 2014, respectively.

In 2017 and for the five-year period ending 2021, Cleco Power expects to internally fund 100% of its capital expenditure requirements. However, Cleco Power may choose to issue debt in order to achieve a capital structure with a debt ratio of 49%. All computations of internally funded capital expenditures exclude AFUDC.

Cleco and Cleco Power’s estimated capital expenditures and debt maturities for 2017 and for the five-year period ending 2021 are presented in the following tables. All amounts exclude AFUDC.

Cleco
PROJECT (THOUSANDS)	2017		%			2017-2021		%
Environmental	$	4,000		1	%	$	33,000		3	%
New business		27,000		10	%		138,000		11	%
Transmission reliability		26,000		10	%		170,000		14	%
Fuel optimization		75,000		28	%		172,000		14	%
General(1)		136,000		51	%		706,000		58	%
Total capital expenditures	$	268,000		100	%	$	1,219,000		100	%
Debt payments		18,000					369,000
Total capital expenditures and debt payments	$	286,000				$	1,588,000

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

Cleco Power
PROJECT (THOUSANDS)	2017		%			2017-2021		%
Environmental	$	4,000		2	%	$	33,000		3	%
New business		27,000		10	%		138,000		11	%
Transmission reliability		26,000		10	%		170,000		14	%
Fuel optimization		75,000		28	%		172,000		14	%
General(1)		134,000		50	%		698,000		58	%
Total capital expenditures	$	266,000		100	%	$	1,211,000		100	%
Debt payments		18,000					69,000
Total capital expenditures and debt payments	$	284,000				$	1,280,000

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

Capital expenditures for other subsidiaries in 2017 are estimated to total $2.0 million. For the five-year period ending 2021, capital expenditures for other subsidiaries are estimated to total $8.0 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 are Cleco’s primary source 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.

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Common Stock Repurchase Program

Prior to the completion of the Merger, Cleco Corporation had a common stock repurchase program that authorized management to repurchase shares of common stock. Upon completion of the Merger on April 13, 2016, the common stock repurchase program was terminated. For more information, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 8—Common Stock—Common Stock Repurchase Program.” For more information about the Merger, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 3—Business Combinations.”

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, 2016, and represent only the projected future payments that Cleco was contractually obligated to make as of December 31, 2016.

			PAYMENTS DUE BY PERIOD
CONTRACTUAL OBLIGATIONS (THOUSANDS)	TOTAL		LESS THAN ONE YEAR		1-3 YEARS		3-5 YEARS		MORE THAN 5 YEARS
Cleco Holdings
Long-term debt obligations(1)	$	1,811,854	$	43,173	$	86,346	$	86,347	$	1,595,988
Operating lease obligations(3)		628		315		313		—		—
Purchase obligations(4)		32,540		13,177		12,113		6,146		1,104
Other long-term liabilities(5)		11,985		3,199		2,336		2,696		3,754
Pension and other benefits obligations(6)		206,651		8,323		16,841		16,971		164,516
Total Cleco Holdings	$	2,063,658	$	68,187	$	117,949	$	112,160	$	1,765,362
Cleco Power
Long-term debt obligations(1)	$	2,289,693	$	87,000	$	396,809	$	107,426	$	1,698,458
Capital lease obligations(2)		2,483		2,483		—		—		—
Operating lease obligations(3)		20,765		6,505		5,762		5,197		3,301
Purchase obligations(4)		281,353		174,718		103,883		2,165		587
Other long-term liabilities(5)		97,320		16,348		33,348		32,265		15,359
Total Cleco Power	$	2,691,614	$	287,054	$	539,802	$	147,053	$	1,717,705
Total long-term debt obligations(1)	$	4,101,547	$	130,173	$	483,155	$	193,773	$	3,294,446
Total capital lease obligations(2)	$	2,483	$	2,483	$	—	$	—	$	—
Total operating lease obligations(3)	$	21,393	$	6,820	$	6,075	$	5,197	$	3,301
Total purchase obligations(4)	$	313,893	$	187,895	$	115,996	$	8,311	$	1,691
Total other long-term liabilities(5)	$	109,305	$	19,547	$	35,684	$	34,961	$	19,113
Total pension and other benefits obligations(6)	$	206,651	$	8,323	$	16,841	$	16,971	$	164,516
Total	$	4,755,272	$	355,241	$	657,751	$	259,213	$	3,483,067

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(1) Long-term debt existing as of December 31, 2016, is debt that has a final maturity of January 1, 2018, or later (current maturities of long-term debt are due within one-year). Cleco’s anticipated interest payments related to long-term debt also are included in this category. Scheduled maturities of debt total $17.9 million for 2017 and $2.60 billion for the years thereafter. For more information regarding Cleco’s long-term debt, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 7—Debt” and “—Debt” above.

(2) Capital leases are maintained in the ordinary course of Cleco’s business activities, including leases for barges. For more information regarding these leases, see “Financial Statement and Supplementary Data—Notes to the Financial Statements—Note 15—Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Other Commitments—Fuel Transportation Agreement.”

(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, office equipment, tower rentals, and vehicles 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 Financial Statements—Note 14—Operating Leases.”

(4) Significant purchase obligations for Cleco are:

Fuel Contracts: To supply a portion of the fuel requirements for Cleco Power’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, fuel and purchased power expenses are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to customers substantially all such charges. For more information regarding fuel contracts, see “Business—Operations—Cleco Power—Fuel and Purchased Power.”

PPAs: Cleco Power has entered into agreements with energy suppliers for purchased power to meet system load and energy requirements, replace generation from Cleco Power owned units under maintenance and during outages, and meet operating reserve obligations.

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 franchise payments, deferred compensation, facilities use, and various operating and maintenance agreements.

(6) Pension and other benefits obligations consist of obligations for SERP and other postretirement obligations. For more information regarding Cleco’s pension plan, see “Financial Statements and Supplementary Data—Notes to the 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 Financial Statements—Note 15—Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—“Off-Balance Sheet Commitments and Guarantees.”

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Regulatory and Other Matters

Inflation

Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged 1% during the three years ended December 31, 2016. Cleco believes inflation at this level does not materially affect its results of operations or financial condition. However, 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

For information on environmental matters, see “Business—Environmental Matters.”

Retail Rates of Cleco Power

Retail rates (comprised of base revenue, the FAC revenue, and the EAC revenue) regulated by the LPSC accounted for approximately 85% of Cleco Power’s 2016 and 2015 revenue.

Fuel Rates

Generally, the cost of fuel used for electric generation and the cost of power purchased for utility customers 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 will be performed at least every other year. On February 3, 2016, the LPSC initiated an audit of Cleco Power’s fuel and purchased power expenses for the period January 2014 through December 2015. The total amount of fuel expense included in this audit was $582.6 million. On January 19, 2017, the LPSC Staff issued its audit report which recommended no disallowance of fuel costs. Management expects the report to be approved by the LPSC in the second quarter of 2017. Cleco Power currently has FAC filings for 2016 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.

Environmental Rates

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides for 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. Cleco Power began incurring additional environmental compliance expenses in the second quarter of 2015 for reagents associated with compliance with MATS. These expenses are eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC. For more information on MATS, see “Business—Environmental Matters—Air Quality.”

On February 3, 2016, the LPSC initiated an audit of Cleco Power’s environmental costs for the period November 2010 through December 2015. The total amount of environmental costs included in this audit was $81.2 million. On December 1, 2016, the LPSC Staff issued its audit report which recommended a disallowance of environmental costs of less than $0.1 million. The report was approved by the LPSC on February 17, 2017. Cleco Power currently has EAC filings for 2016 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.

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Base Rates

Cleco Power’s annual retail earnings are subject to the terms of an FRP established by the LPSC. Prior to July 1, 2014, Cleco Power’s FRP allowed a target ROE of 10.7%, while providing the opportunity to earn up to 11.3%. Additionally, 60.0% of retail earnings between 11.3% and 12.3% and all retail earnings over 12.3% were required to be refunded to customers. In April 2013, Cleco Power filed an application with the LPSC to extend its current FRP and to seek rate recovery of the Coughlin transfer. In June 2014, the LPSC approved Cleco Power’s FRP extension, finalized the rate treatment of Coughlin, and issued the implementing order. Effective July 1, 2014, under the terms of the FRP extension, Cleco Power’s retail rates were adjusted based on 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 is ultimately subject to LPSC approval. The capital structure assumes an equity ratio of 51%. The FRP extension includes a mechanism that allows for recovery in base rates, the revenue requirements related to excess amounts of surcredits refunded for storm costs and uncertain tax positions, MISO transition and administration charges, Louisiana state corporate franchise taxes, incremental production operations and maintenance costs, LPSC renewable project costs, and certain capacity costs. It also includes recovery of deferred costs for the previous LPSC fuel audit, biomass pilot project costs, and costs related to filing the FRP extension. The FRP extension also includes a mechanism allowing for recovery of incremental capacity costs above the level included in base rates and allows Cleco Power to request recovery of additional capital project costs during its four-year term. Cleco Power was scheduled to file an application with the LPSC for a new FRP by June 30, 2017. However, as part of the merger approval process, Cleco Power agreed not to file an application for a new FRP or request an increase in base rates until June 30, 2019, with anticipated new rates being effective on July 1, 2020.

On April 8, 2016, the LPSC issued Docket No. R-34026 to investigate 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 customers. Cleco Power filed a motion to intervene in this proceeding along with other Louisiana utilities. On April 8, 2016, the LPSC also issued Docket No. R-34029 to investigate tax structure issues for all LPSC-jurisdictional utilities to consider whether only the state and federal taxes included in a utility’s retail rate 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. On October 4, 2016, Cleco received the first set of data requests from the LPSC Staff for each of the above mentioned dockets. Cleco has filed responses to the non-confidential requests and is waiting on the completion of a confidentiality agreement to respond to the confidential requests. Cleco anticipates the completion of this agreement in the second quarter of 2017. 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 the Company.

For information concerning amounts accrued and refunded by Cleco Power as a result of the FRP and information on the LPSC Staff’s FRP reviews, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 12—Regulation and Rates.”

Energy Efficiency

In August 2009, the LPSC opened a docket to study the promotion of energy efficiency by jurisdictional electric and natural gas utilities. In September 2013, the LPSC issued a General Order adopting rules promoting energy efficiency programs. Cleco Power subsequently filed its formal intent with the LPSC to participate in the Phase I—Quick Start portion of the LPSC’s energy efficiency initiative, which runs November 1, 2014, through July 31, 2017. During Phase I, Cleco Power designed several energy efficiency programs and began offering these programs to customers on November 1, 2014. In November 2014, Cleco Power began recovering approximately $3.3 million annually of estimated costs for the program through an approved rate tariff.

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Wholesale Rates of Cleco Power

The rates Cleco Power 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 is to be filed with FERC every three years or upon the occurrence of a change in status as defined by FERC regulation. In February 2014, FERC issued an order to accept Cleco’s substitute market power analysis and grant the power marketing entities the authority to continue to charge market-based rates for wholesale power. Cleco filed its triennial market power analysis with FERC in January 2015. On March 1, 2016, FERC issued an order finding Cleco’s submittal satisfies its requirements for market-based rate authority regarding both horizontal and vertical market power. Cleco’s next triennial market power analysis is expected to be filed in 2018.

Transmission Rates of Cleco Power

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 SPP made separate filings containing different metrics to meet specific 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 the Company.

In June 2013, the LPSC unanimously approved Cleco Power’s MISO change of control request to transfer functional control of certain transmission assets to MISO. MISO operates a fully functioning RTO market with two major market processes: the Day-Ahead Energy and Operating Reserves Market and the Real-Time Energy and Operating Reserves Market. These markets use market-based mechanisms to manage transmission congestion across the MISO market area. In December 2013, Cleco Power integrated its generation dispatch and transmission operations with MISO. The LPSC authorized Cleco Power to defer and collect the retail portion of its MISO integration costs from the LPSC jurisdictional customers through the FRP. Cleco Power deferred $3.7 million of integration costs and began recovering these costs over a four-year period beginning July 1, 2014.

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 current 12.38% ROE used in MISO’s transmission rates to a proposed 6.68%. The first complaint is for the period November 2013 through February 2015. In December 2015, an ALJ issued an initial decision recommending a 10.32% ROE. On September 29, 2016, FERC issued a Final Order confirming the ALJ’s recommendation of a 10.32% ROE.

In February 2015, the second ROE complaint was filed for the period February 2015 through May 2016. In June 2016, an ALJ issued an initial decision in the second rate case docket recommending a 9.70% base ROE. A binding FERC order on the second ROE complaint is expected in the second quarter of 2017.

In November 2014, the MISO transmission owners committee, in 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. The collection of the adder is delayed until the resolution of the ROE complaint proceedings.

As of December 31, 2016, Cleco Power had $3.3 million accrued for a reduction to the ROE, including accrued interest. On February 13, 2017, $1.2 million of refunds relating to the first complaint were submitted to MISO. Management believes a reduction in the ROE, as well as any additional refund, will not have a material adverse effect on the results of operations, financial condition, or cash flows of the Company.

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For more information about the risks associated with Cleco Power’s participation in MISO, see “Risk Factors—MISO.”

Transmission and Generation Projects

Cleco Power is involved in several transmission projects, including the Layfield/Messick project, the Cenla Transmission Expansion project, and the Terrebonne to Bayou Vista Transmission project. Cleco Power is also currently involved in the St. Mary’s Clean Energy Center project, which is a proposed waste heat generating unit. For information on these projects, please read “—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 integrated its generation dispatch and transmission operations with MISO in December 2013. For more information about Cleco Power’s integration into MISO, see “—Transmission Rates of Cleco Power.”

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 would oversee and regulate the mandatory reliability standards.

The SPP RE conducts a NERC Reliability Standard audit every three years. A NERC Reliability Standard audit was conducted in April 2016. There were three possible violations associated with the April audit. The SPP RE dismissed one possible violation. Cleco Power completed the mitigation plans for the other two possible violations and submitted the information to the SPP RE. The SPP RE and NERC have approved the mitigation plans, and the information has been submitted to FERC. The SPP RE did not pursue any enforcement action in connection with the issues of noncompliance found during the 2016 audit. Furthermore, the SPP RE determined the issues posed a minimal risk to the reliability of the bulk power system; therefore, the issues were eligible for disposition as compliance exceptions. NERC and FERC did not object to the handling of the noncompliance issues as compliance exceptions. No fines will be levied against Cleco Power. Cleco Power’s next audit is scheduled to begin in April 2019. Management is unable to predict the outcome of this 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 the Company.

The SPP RE also conducts a NERC Critical Infrastructure Protection audit every three years. Cleco Power’s NERC Critical Infrastructure Protection audit began on February 13, 2017. Management is unable to predict the outcome of this 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 the Company.

For a discussion of risks associated with FERC’s regulation of Cleco Power’s transmission system, see “Risk Factors—Reliability and Infrastructure Protection Standards Compliance.”

Retail Electric Markets

Currently, the LPSC does not provide exclusive service territories for electric utilities under its jurisdiction. Instead, retail service is obtained through a long-term nonexclusive franchise. The LPSC uses a “300-foot rule” for determining the supplier for new customers. The “300-foot rule” requires a customer to take service from the

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electric utility that is within 300 feet of the respective customer. If the customer is beyond 300 feet from any existing utility service, they may choose their electric supplier. The “300-foot rule” is currently under review by the LPSC in Docket No. R-32763. Management is unable to predict the time of completion and cannot determine the impact any potential rulemaking may have on the results of operations, financial condition, 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.

Lignite Deferral

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 began receiving fuel cost savings through the year 2011 while actual mining costs incurred above a certain percentage of the benchmark price were deferred, and can be recovered from retail customers through the FAC only when the actual mining costs are 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 December 2007, the LPSC approved a settlement agreement between Cleco Power, SWEPCO, and the LPSC Staff authorizing Cleco Power to recover the existing deferred mining cost balance, including interest, over 11.5 years. In connection with its approval of the Oxbow Lignite Mine acquisition, in 2009, the LPSC agreed to discontinue benchmarking and the corresponding potential to defer future lignite mining costs while preserving the recovery of the legacy deferred fuel balance previously authorized. At December 31, 2016, and 2015, Cleco Power had $6.4 million and $8.9 million, respectively, in deferred costs remaining uncollected.

IRP

In accordance with the General Order in LPSC Docket No. R-30021, Cleco Power filed a request with the LPSC to initiate an IRP process in October 2013. The IRP process included the conduct of stakeholder meetings and consideration of feedback provided by stakeholders. Cleco Power filed its IRP with the LPSC in September 2015. Stakeholders filed comments in November 2015. The LPSC Staff filed its comments in December 2015, which included a recommendation that the LPSC accept Cleco Power’s IRP as filed. In April 2016, the LPSC approved Cleco Power’s IRP report, which fostered a collaborative working process for the development of Cleco Power’s long-term resource plan covering the planning period of 2015 through 2034. Cleco Power anticipates filing the next IRP with the LPSC in 2019.

Service Quality Program (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. On February 1, 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 is required to file a monitoring report annually, beginning in April 2017.

Franchises

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

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Recent Authoritative Guidance

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

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BUSINESS

GENERAL

Cleco Holdings’ predecessor was incorporated on October 30, 1998, under the laws of the state of Louisiana. Cleco Holdings is a public utility holding company which holds investments in several subsidiaries, including Cleco Power. Substantially all of its operations are 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.

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 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. For more information on the Merger, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 3—Business Combinations.”

Cleco Power’s predecessor was incorporated on January 2, 1935, under the laws of the state of Louisiana. Cleco Power was organized on December 12, 2000. Cleco Power is an electric utility engaged principally in the generation, transmission, distribution, and sale of electricity within Louisiana. In December 2013, Cleco Power integrated its generation dispatch and transmission operations with MISO. Cleco Power is regulated by the LPSC and FERC, along with other governmental authorities. The rates Cleco Power can charge its retail customers are determined by the LPSC, and its transmission tariffs are regulated by FERC. The rates Cleco Power charges its wholesale customers are subject to FERC’s triennial market power analysis. Cleco Power serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi. Cleco Power’s operations are described below. 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 of Cleco Power.”

Midstream, which was organized on September 1, 1998, under the laws of the state of Louisiana, is a merchant energy subsidiary that prior to March 15, 2014, owned and operated a merchant power plant (Coughlin). Prior to April 29, 2011, Midstream also owned an indirect interest in a merchant power plant (Acadia). During 2009, Cleco Power and Entergy Louisiana executed definitive agreements whereby Cleco Power and Entergy Louisiana would each acquire one 580-MW unit of the Acadia Power Station. The transaction with Cleco Power was completed in February 2010, and the transaction with Entergy Louisiana was completed in April 2011. Midstream owns Evangeline (which owned and operated Coughlin). In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of Coughlin from Evangeline to Cleco Power. The transfer was completed on March 15, 2014. Coughlin consists of two generating units with a total nameplate capacity of 775 MW. For more information on the transfer of Coughlin to Cleco Power, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 18—Coughlin Transfer.”

At December 31, 2016, Cleco had 1,203 employees. At December 31, 2016, Cleco Power had 1,022 employees.

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OPERATIONS

Cleco Power

Segment Financial Information

Summary financial results of the Cleco Power segment for years 2016, 2015, and 2014 are presented in the following table:

(THOUSANDS)	2016			2015			2014
Revenue
Electric operations	$	1,091,229		$	1,142,389		$	1,225,960
Other operations		68,573			67,109			64,893
Electric customer credits		(1,513	)		(2,173	)		(23,530	)
Affiliate revenue		884			1,142			1,326
Operating revenue, net	$	1,159,173		$	1,208,467		$	1,268,649
Depreciation and amortization	$	146,142		$	147,839		$	144,026
Interest charges	$	76,446		$	76,560		$	74,673
Interest income	$	860		$	725		$	1,707
Federal and state income tax expense	$	18,369		$	79,294		$	76,974
Net income	$	39,128		$	141,350		$	154,316
Additions to property, plant, and equipment	$	186,143		$	156,357		$	206,607
Equity investment in investee	$	18,672		$	16,822		$	14,532
Goodwill	$	1,490,797		$	—		$	—
Segment assets	$	5,758,245		$	4,233,337		$	4,232,942

For more information on Cleco Power’s results of operations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Comparison of the Years Ended December 31, 2016, and 2015—Cleco Power.”

Certain Factors Affecting Cleco Power

As an electric utility, Cleco Power is affected, to varying degrees, 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, 2016, and 2015—Cleco Power—Significant Factors Affecting Cleco Power.”

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Power Generation

As of December 31, 2016, Cleco Power’s aggregate net electric generating capacity was 3,168 MW. This amount reflects the maximum production capacity these units can sustain over a specified period of time. In September 2016, Teche Unit 1, a 23-MW natural gas generating unit, was retired. The following table sets forth certain information with respect to Cleco Power’s generating facilities:

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					421				natural gas		steam
Rodemacher Unit 2		1982		157		(3	)		148		(3)		coal		steam
Madison Unit 3		2010		641					628				petroleum coke/coal		steam
Acadia Unit 1		2002		580					556				natural gas		combined cycle
Coughlin Unit 6		2000		264					246				natural gas		combined cycle
Coughlin Unit 7		2000		511					481				natural gas		combined cycle
Teche Unit 3		1971		359					333				natural gas		steam
Teche Unit 4		2011		33					35				natural gas		combustion
Dolet Hills Power Station		1986		325		(4	)		320		(4)		lignite		steam
Total generating capability				3,310					3,168

(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 during May, June, July, and August 2016. 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, 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
2016		12,759		103.6
2015		12,564		100.2
2014		9,858		74.9
2013		9,736		83.8
2012		9,143		81.3

In December 2013, Cleco Power integrated its generation dispatch and transmission operations 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 of Cleco Power.”

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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 the 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—LPSC Audits” and “—Transmission Constraints.”

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				BIOMASS				PETROLEUM COKE
YEAR	COST PER MWh		PERCENT OF GENERATION		COST PER MWh		PERCENT OF GENERATION		COST PER MWh		PERCENT OF GENERATION		COST PER MWh		PERCENT OF GENERATION		COST PER MWh		PERCENT OF GENERATION		WEIGHTED AVERAGE COST PER MWh
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
2014	$	44.79		14.6	$	27.34		15.6	$	37.00		35.0	$	—		—	$	21.52		34.8	$	31.19
2013	$	42.44		15.6	$	29.42		18.2	$	34.60		34.4	$	—		—	$	21.54		31.8	$	30.72
2012	$	36.36		25.2	$	33.03		17.0	$	27.81		45.8	$	17.74		*	$	23.54		12.0	$	30.37

* Not meaningful

Power Purchases

In December 2013, Cleco Power integrated its generation dispatch and transmission operations with MISO. Consequently, MISO now makes economic and routine dispatch decisions regarding Cleco Power’s generating units. Since joining MISO, power purchases have been 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 will have a higher LMP. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power’s pricing zone. 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.”

Coal, Petroleum Coke, and Lignite Supply

Cleco Power uses coal for generation at Rodemacher Unit 2. During 2016, Cleco Power contracted with Peabody Coal Sales LLC and Arch Coal Sales to provide Cleco Power’s coal needs at Rodemacher Unit 2. A portion of Rodemacher Unit 2’s coal supply was provided from two Peabody Coal Sales LLC agreements that expired in December 2016, and the remaining supply was provided from an Arch Coal Sales agreement that expires in June 2017. The coal supply agreements were fixed-price contracts. The remainder of Cleco Power’s coal needs for 2017 will be met with spot purchases. With respect to transportation of coal, Cleco Power’s agreement with Union Pacific Railroad Company for transportation of coal from Wyoming’s Powder River Basin to Rodemacher Unit 2 expired on December 31, 2016. A new transportation agreement with Union Pacific Railroad began on January 1, 2017, for a term of 3 years. Cleco Power leases 231 railcars to transport its coal under two long-term leases, one expiring in March 2017, under which management is evaluating future options, and the other expiring in March 2021.

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 December 31, 2016, Cleco Power’s coal inventory at Rodemacher Unit 2 was approximately 76,000 tons (approximately a 32-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 2016, Cleco received its petroleum coke supply from refineries located along the lower Mississippi River with some spot cargo purchases being delivered from upper Mississippi refineries. Cleco purchased slightly more than one million tons of petroleum coke during 2016, all of which were either an evergreen extension of a previous agreement or a newly negotiated agreement for one year ending December 31, 2016. All existing contracts have been extended and newly negotiated contracts have been completed for petroleum coke supply in 2017. Petroleum coke spot purchases are typically short-term in nature, ranging from one- to six-month terms. Each of the agreements is either a fixed price spot purchase or priced per the Jacobs Consultancy Petroleum Coke Quarterly Monthly Price Index or the “PACE” Monthly Index.

During 2016, Cleco purchased approximately 268,000 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 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 Services is Cleco Power’s exclusive transportation coordinator and provider. The amended and restated logistics agreement dated December 28, 2012, with Savage Services continues through August 31, 2017. The term of this agreement will automatically renew for successive periods of two years each unless written notice is provided by either party at least four months prior to the expiration of the term in effect. The amended agreement contains a provision for early termination with a three-month prior written notice upon the occurrence of specified cancellation events. Cleco is evaluating future options related to its fuel transportation agreement with Savage Services. At December 31, 2016, Cleco Power’s petroleum coke inventory at Madison Unit 3 was approximately 257,000 tons and Cleco Power’s Illinois Basin coal inventory at Madison Unit 3 was approximately 95,000 tons. The total fuel inventory was 352,000 tons (approximately a 70-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 74 million tons of estimated recoverable lignite reserves also located in northwestern Louisiana. Cleco Power and SWEPCO have entered into a long-term agreement with DHLC for the mining and delivery of lignite reserves at both mines, the operations of which are conducted by SWEPCO. The Amended Lignite Mining Agreement requires Cleco Power and SWEPCO to purchase the lignite mined and delivered by DHLC at cost plus a specified management fee. The term of this contract runs until all economically mineable lignite has been mined. The reserves from these mines are expected to be sufficient to fuel the Dolet Hills Power Station until at least 2036. At December 31, 2016, Cleco Power’s investment in Oxbow was $18.7 million. For information regarding deferred mining costs and obligations associated with this mining agreement see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 4—Regulatory Assets and Liabilities—Mining Costs,” Note 15—“Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Off-Balance Sheet Commitments and Guarantees,” and “—Long-Term Purchase Obligations.” For more information on Oxbow, see “Financial Statements and Supplementary Data—Notes to the 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. At December 31, 2016, Cleco Power’s lignite inventory at Dolet Hills was approximately 251,000 tons (approximately a 40-day supply).

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Natural Gas Supply

During 2016, Cleco Power purchased 30.3 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:

NATURAL GAS SUPPLIER	2016 PURCHASES (MMBtu)		AVERAGE AMOUNT PURCHASED PER DAY (MMBtu)		PERCENT OF TOTAL NATURAL GAS USED
Tenaska Marketing Ventures		6,758,498		18,516		22.3	%
Shell Energy North America		5,746,061		15,743		19.0	%
Range Resources-Appalachia, LLC		4,207,939		11,529		13.9	%
Enstor Energy Services		2,979,468		8,163		9.8	%
Iberdrola Renewables		2,864,000		7,847		9.5	%
South Jersey Resources Group		2,689,871		7,370		8.9	%
Anadarko Energy Service Company		1,164,700		3,191		3.8	%
Others		3,860,298		10,576		12.8	%
Total		30,270,835		82,935		100.0	%

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

Natural gas was available without interruption throughout 2016. 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 2016, 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 2017. 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, gas storage will continue to be used. 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 December 31, 2016, Cleco Power had 1.7 million MMBtu of gas in storage. Currently, Cleco Power anticipates that its diverse supply options, gas storage, and alternative fuel capability, combined with its solid-fuel generation resources, are adequate to meet its generation needs during any temporary interruption of natural gas supplies.

Sales

Cleco Power’s 2016 and 2015 system peak demands, which occurred on August 2, 2016, and August 10, 2015, were 2,490 MW and 2,700 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. In 2016, Cleco Power experienced warmer than normal summer weather conditions and warmer than normal winter weather conditions. In 2015, Cleco Power experienced warmer than normal summer weather conditions and warmer than normal winter weather conditions. For information on the effects of future energy sales on Cleco Power’s results of operations, financial position, and cash flows, see “Risk Factors—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 Financial Statements—Note 20—Miscellaneous Financial Information (Unaudited).”

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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 2016, Cleco Power’s reserve margin was 23.8%, which was above MISO’s unforced planning reserve margin benchmark of 7.6.%. During 2015, Cleco Power’s reserve margin was 21.3%, which was above MISO’s unforced planning reserve margin benchmark of 7.1%. Cleco Power expects to meet or exceed MISO’s unforced planning reserve margin benchmark of 7.8% in 2017.

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—Layfield/Messick Project,” “—Cenla Transmission Expansion Project,” “—St. Mary Clean Energy Project,” “—Terrebonne to Bayou Vista Transmission Project,” and “—Coughlin Pipeline Project.”

Customers

No single customer accounted for 10% or more of Cleco or Cleco Power’s consolidated revenue in 2016, 2015, or 2014. In 2014, Cleco Power added a significant wholesale customer that accounted for 9% of Cleco and Cleco Power’s consolidated revenue in 2016, 2015, and the months that it was a customer in 2014. For more information regarding Cleco’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’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. Also, 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. The rates Cleco Power charges its wholesale customers are subject to FERC’s triennial market power analysis.

Cleco Power’s annual retail earnings are subject to the terms of an FRP established by the LPSC. Prior to July 1, 2014, Cleco Power’s FRP allowed a target ROE of 10.7%, while providing the opportunity to earn up to 11.3%. Additionally, 60.0% of retail earnings between 11.3% and 12.3% and all retail earnings over 12.3% were required to be refunded to customers. In April 2013, Cleco Power filed an application with the LPSC to extend its current FRP and to seek rate recovery of the Coughlin transfer. In June 2014, the LPSC approved Cleco Power’s FRP extension, finalized the rate treatment of Coughlin, and issued the implementing order. Effective July 1, 2014, under the terms of the FRP extension, Cleco Power’s retail rates were adjusted based on 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 is ultimately subject to LPSC approval. The capital structure assumes an equity ratio of 51%. The FRP extension includes a mechanism that allows for recovery in base rates, the revenue requirements related to excess amounts of surcredits refunded for

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storm costs and uncertain tax positions, MISO transition and administration charges, Louisiana state corporate franchise taxes, incremental production operations and maintenance costs, LPSC renewable project costs, and certain capacity costs. It also includes recovery of deferred costs for the previous LPSC fuel audit, biomass pilot project costs, and costs related to filing the FRP extension. The FRP extension also includes a mechanism allowing for recovery of incremental capacity costs above the level included in base rates and allows Cleco Power to request recovery of additional capital project costs during its four-year term. Cleco Power was scheduled to file an application with the LPSC for a new FRP by June 30, 2017. However, as part of the merger approval process, Cleco Power agreed not to file an application for a new FRP or request an increase in base rates until June 30, 2019, with anticipated new rates being effective on July 1, 2020.

Generally, the cost of fuel used for electric generation and the cost of power purchased for utility customers 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 will be performed at least every other year. On February 3, 2016, the LPSC initiated an audit of Cleco Power’s fuel and purchased power expenses for the period January 2014 through December 2015. The total amount of fuel expense included in this audit was $582.6 million. On January 19, 2017, the LPSC Staff issued its audit report which recommended no disallowance of fuel costs. Management expects the report to be approved by the LPSC in the second quarter of 2017. Cleco Power currently has FAC filings for 2016 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.

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides for 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. Cleco Power began incurring additional environmental compliance expenses in the second quarter of 2015 for reagents associated with compliance with MATS. These expenses are eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC. For more information on MATS, see “Environmental Matters—Air Quality.”

On February 3, 2016, the LPSC initiated an audit of Cleco Power’s environmental costs for the period November 2010 through December 2015. The total amount of environmental costs included in this audit was $81.2 million. On December 1, 2016, the LPSC Staff issued its audit report which recommended a disallowance of environmental costs of less than $0.1 million. The report was approved by the LPSC on February 17, 2017. Cleco Power currently has EAC filings for 2016 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.

On April 8, 2016, the LPSC issued Docket No. R-34026 to investigate 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 customers. Cleco Power filed a motion to intervene in this proceeding along with other Louisiana utilities. On April 8, 2016, the LPSC also issued Docket No. R-34029 to investigate tax structure issues for all LPSC-jurisdictional utilities to consider whether only the state and federal taxes included in a utility’s retail rate 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. On October 4, 2016, Cleco received the first set of data requests from the LPSC Staff for each of the above mentioned dockets. Cleco has filed responses to the non-confidential requests and is waiting on the completion of a confidentiality agreement to respond to the confidential requests. Cleco anticipates the completion of this agreement in the second quarter of 2017. 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 the Company.

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For more information on Cleco Power’s retail and wholesale rates, including Cleco Power’s FRP, see “Risk Factors—LPSC Audits,” “—Cleco Power’s Rates,” “—Retail Electric Service,” and “—Wholesale 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,” and—“Wholesale Rates of Cleco Power.”

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 August 2020.

Franchise Renewals

Cleco Power renewed the following franchise agreements during 2015 and 2016:

DATE	CITY/TOWN/VILLAGE	TERM	NUMBER OF CUSTOMERS
March 2015	Zwolle	30 years	914
May 2015	Merryville	30 years	454
June 2015	Eunice	33 years	5,190
July 2015	Converse	30 years	233
July 2015	Madisonville	34 years	598
August 2015	Pleasant Hill	30 years	382
September 2015	Noble	30 years	108
September 2015	Plaucheville	30 years	147
May 2016	Elizabeth	10 years*	219
July 2016	McNary	30 years	89

* Effective date May 2018, expiring May 2028

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.”

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Legislative and Regulatory Changes and Matters

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

• the ability of electric utilities to recover stranded costs,

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

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

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

• mandatory transmission reliability standards,

• FERC rulemakings encouraging migration of utility operations to RTOs,

• 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,

• FERC’s increased ability to impose financial penalties, and

• the Dodd-Frank Act.

Management is unable, at this time, to predict the outcome of such issues or the effects thereof on the results of operations, financial condition, or cash flows of the Company.

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 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, perhaps significantly, the results of operations, financial condition, or cash flows of the Company. Cleco Power’s capital expenditures, including AFUDC, related to environmental compliance were $6.4 million during 2016 and are estimated to be $4.5 million in 2017.

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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 certain 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. SIP must include several components, including requirements for the installation of Best Available Retrofit Technology (BART) for eligible EGUs in Louisiana. The LDEQ now must determine what the BART requirements will be for BART-eligible EGUs for the control of SO₂ and NO_x. Until the LDEQ determines what BART requirements are for Cleco units and completes its update of 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 the Company. 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. As of December 31, 2016, Cleco had sufficient allowances for operations in 2016 and expects to have sufficient allowances for 2017 operations under the Acid Rain Program.

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

In July 2011, the EPA finalized a rule titled “Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” known as CSAPR that would require significant reductions in SO₂ and NO_x emissions from EGUs in 28 states, including Louisiana. Under CSAPR, the EPA set total emissions limits for each state, allowing limited interstate trading (and unlimited intrastate trading) of emission allowances among power plants to comply with these limits beginning May 1, 2012. Specifically for Louisiana, CSAPR limited NO_x emissions for the ozone season, which consisted of the months of May through September. After several years of litigation over the rule, in October 2014, the D.C. Circuit Court of Appeals granted the EPA’s request that the court lift the stay on CSAPR. On January 1, 2015, the EPA implemented CSAPR on an interim basis. In May 2015, Cleco began complying with the rule’s requirements for limiting NO_x emissions during annual ozone seasons.

In December 2015, the EPA published the proposed CSAPR update for the 2008 ozone NAAQS in the Federal Register. The EPA finalized the rule on October 26, 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 requires implementation beginning with the 2017 ozone season. Management does not believe the final rule will have a material impact on the results of operations, financial condition, or cash flows of the Company.

In February 2012, the EPA finalized the MATS ruling that requires affected EGUs to meet strict emission limits on new and existing coal- and liquid oil-fired EGUs for mercury, acid gases, and non-mercury metallic pollutants. Cleco Power units impacted by the rule included Rodemacher Unit 2, Madison Unit 3, and Dolet Hills. MATS controls equipment was installed and Cleco Power’s three EGUs affected by the MATS rule were compliant by the April 16, 2015, deadline. In February 2016, the LPSC approved Cleco Power’s request for authorization to recover the revenue requirements associated with the MATS equipment. As of December 31, 2016, Cleco Power had spent $106.2 million on the project. Cleco Power’s final project cost is expected to be $108.0 million, with the remaining costs being related to post-construction refinements. On March 31, 2016, the Sierra Club filed a petition for judicial review in the 19th Judicial District Court, State of Louisiana, requesting

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that the LPSC’s approval of MATS be vacated. Deadlines have not been set by the 19th Judicial District Court. Cleco believes the LPSC’s approval was neither arbitrary nor capricious and, as such, believes the Sierra Club’s request to be without merit. In June 2015, the U.S. Supreme Court remanded the MATS rule to the D.C. Circuit Court of Appeals. The Supreme Court held that the EPA had not demonstrated that the promulgation of the MATS rule was “appropriate and necessary” due to the EPA’s failure to consider costs. 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 the rule. On April 15, 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 24, 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.

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

In the absence of federal legislation, the EPA adopted a series of rules under the CAA that, taken together, regulate GHG emissions from both mobile and stationary sources. As a result, since July 2011, new major stationary sources of GHG emissions and major modifications of existing stationary sources have been required to obtain a permit for their GHG emissions. In its May 2010, Prevention of Significant Deterioration (PSD) and Title V GHG “Tailoring Rule,” the EPA set the threshold for new major sources and major modifications of existing sources of GHG emissions and CO₂ equivalents at 100,000 tons per year and 75,000 tons per year, respectively. The U.S. Supreme Court partially invalidated the Tailoring Rule in June 2014, holding that the EPA does not have the authority to regulate GHG emissions from all sources, but only from sources that would otherwise be subject to PSD permitting based on exceeding the emissions limits for other pollutants. Cleco does not anticipate a modification at any of its existing sources that would trigger PSD and an associated Best Available Control Technology demonstration for GHG.

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. The rule is currently under review by electric utilities and state regulators. On February 9, 2016, the U.S. Supreme Court issued a stay of the CPP, which will stay in place until the D.C. Circuit Court of Appeals rules on the merits, followed by a U.S. Supreme Court ruling. Oral arguments were heard by the D.C. Circuit Court of Appeals on September 27, 2016, with a final decision expected by mid-year 2017. If the U.S. Supreme Court grants a writ application, a decision is not expected until early 2018. Until the U.S. Supreme Court issues a ruling and the State of Louisiana releases an implementation plan, management cannot predict what the final standards will entail for Cleco or what controls the EPA and the state of Louisiana may require in a final state implementation plan. 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.

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 proposed CO₂ emission limits.

The enactment of federal or state renewable portfolio standards (RPS) mandating the use of renewable and alternative fuel sources such as wind, solar, biomass, and geothermal could result in certain changes in Cleco’s

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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.

As part of its periodic re-evaluation of the protectiveness of the NAAQS, the EPA has adopted rules that strengthen the NAAQS for specific criteria pollutants including ozone, NO₂, and SO₂. In 2008, the EPA issued a NAAQS for ozone of 75 ppb. The EPA designated the five-parish area around Baton Rouge as a non-attainment area for ozone under the 2008 NAAQS, which required that Louisiana establish a state implementation plan to bring those areas back into attainment by 2015. The state plan for implementing the 2008 NAAQS did not impact Cleco’s generating units.

In October 2015, the EPA released a final rule to strengthen the 2008 eight-hour ozone standard by decreasing the current value of 75 ppb to a value of 70 ppb. However, since the state of Louisiana has not released an implementation plan, Cleco cannot predict what the compliance requirements may be or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of the Company.

A revised primary NAAQS for NO₂ promulgated by the EPA took effect in April 2010. The EPA established a new one-hour standard at a level of 100 ppb to supplement the existing annual standard. In January 2012, the EPA determined that no area in the country was violating the standard. However, the LDEQ expects to operate new monitors at two portions of highways in the Baton Rouge and New Orleans areas. The EPA may redesignate areas based on new data it receives from states. Due to the fact that fossil fuel-fired EGUs are a significant source of NO₂ emissions in the country, a non-attainment designation could result in utilities such as Cleco being required to substantially reduce its 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 designated St. Bernard Parish as a non-attainment area. 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 currently without adequate data will be deferred until adequate data has been developed. In November 2015, the LDEQ notified the EPA that DeSoto Parish was in compliance with the NAAQS SO₂requirement and recommended a designation of attainment. In February 2016, the EPA responded indicating that it intends to classify a portion of DeSoto Parish as non-attainment. The EPA accepted information and comments from the LDEQ. The public was also provided an opportunity to submit comments. Cleco provided comments to the EPA on March 30, 2016. The EPA’s final designation published in the Federal Register on July 12, 2016, designated DeSoto Parish to be nonclassifiable/attainment. As a result, there is no impact to Cleco’s generating units.

In the past, Cleco Power received notices from the EPA requesting information relating to the Brame Energy Center and the Dolet Hills Power Station. The purpose of the data requests was to determine whether Cleco Power complied with the New Source Review permitting program and NSPS requirements under the CAA in connection with capital expenditures, modifications, or operational changes made at these facilities. Cleco Power has completed its responses to the initial data requests. Cleco Power is unable to predict whether the EPA will take further action as a result of the information provided.

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Water Quality

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

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 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 September 2015, the EPA released the revised steam electric effluent limitation guidelines. The rule is focused on reducing the discharge of metals in wastewater from generating facilities to surface 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. Management is currently evaluating the effect of the final rule and is not able to predict if the new rule will have a material impact on the results of operations, financial condition, or cash flows of the Company.

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. 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. Management is currently evaluating the effect of the final rule requirements and is not able to predict if the rule will have a material impact on the results of operations, financial condition, or cash flows of the Company.

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. All costs of the CCR rule are expected to be recovered from 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

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uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. Cleco Power 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 Power will update the ARO balance 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 the Company. At December 31, 2016, management’s analysis confirmed that no additional adjustments were needed to update Cleco Power’s ARO balance.

On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act), including the WIIN Act’s provisions regarding CCRs was signed into law. The 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 Act and made a decision on implementing a state-based option, Cleco cannot determine the effects of the Act on the Company.

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 (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.

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 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. Cleco Power is not a party in any lawsuits related to EMFs.

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PROPERTIES

CLECO HOLDINGS

Electric Transmission Substations

As of December 31, 2016, Cleco Holdings, through two wholly owned subsidiaries, owned one transmission substation in Louisiana and one transmission substation in Mississippi.

CLECO POWER

All of Cleco Power’s electric generating stations and all other 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 information on Cleco Power’s generating facilities, see “Business—Operations—Cleco Power—Power Generation.”

Electric Generating Stations

As of December 31, 2016, Cleco Power either owned or had an ownership interest in five steam electric generating stations, three combined cycle units, and one gas turbine with a combined nameplate capacity of 3,310 MW, and a combined electric net generating capacity of 3,168 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 2016, 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 December 31, 2016, Cleco Power owned 84 active transmission substations and 219 active distribution substations.

Electric Lines

As of December 31, 2016, Cleco Power’s transmission system consisted of 67 circuit miles of 500-kiloVolt (kV) lines; 549 circuit miles of 230-kV lines; 672 circuit miles of 138 kV lines; and 29 circuit miles of 69-kV lines. Cleco Power’s distribution system consisted of 3,623 circuit miles of 34.5-kV lines and 8,312 circuit miles of other lines.

General Properties

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

Title

Cleco Power’s electric generating plants and certain other principal properties are owned in fee simple. Electric transmission and distribution lines are located either on private rights-of-way or along streets or highways by public consent.

Substantially all of Cleco Power’s property, plant, and equipment are subject to a lien of Cleco Power’s Indenture of Mortgage, which does not impair the use of such properties in the operation of its business. As of December 31, 2016, 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.

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LEGAL PROCEEDINGS

CLECO

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

CLECO POWER

For information on legal proceedings affecting Cleco Power, see “Business—Environmental Matters—Air Quality” and “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 15—Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Litigation.”

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

RISK OVERVIEW

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

Cleco evaluates derivatives and hedging activities to determine whether market risk-sensitive instruments and positions are required to be marked-to-market. When positions close, actual gains or losses are included in the FAC and reflected on customers’ bills as a component of the FAC.

Cleco’s exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and commodity prices of power, FTRs, and natural gas. Management’s views on market risk are not necessarily indicative of actual results, nor do they represent the maximum possible gains or losses. The views do represent, within the parameters disclosed, what management estimates may happen.

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

Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows. 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 U.S. 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. On April 8, 2016, S&P and Moody’s updated the credit ratings for Cleco Holdings and Cleco Power, taking into consideration the anticipated completion of the Merger. S&P credit ratings were maintained at Cleco Power at BBB+ (stable) and downgraded at Cleco Holdings to BBB- (stable). Moody’s credit ratings were maintained at Cleco Power at A3 (stable) and downgraded at Cleco Holdings to Baa3 (stable). If Cleco Holdings or Cleco Power’s credit ratings were to be downgraded by S&P and Moody’s, Cleco Holdings and/or Cleco Power would be required to pay additional fees and incur higher interest rates for borrowings under their respective credit facilities.

Interest Rate Risks

Cleco monitors its mix of fixed- and variable-rate debt obligations in light of changing market conditions and from time to time may alter that mix, for example, refinancing balances outstanding under its variable-rate credit facility with fixed-rate debt. For details, see “Notes to the Unaudited Consolidated Financial Statements—Note 7—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.

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At December 31, 2016, Cleco had no short-term variable-rate debt outstanding. Cleco Holdings had no borrowings outstanding under its $100.0 million credit facility. The borrowing costs under Cleco Holdings’ new credit facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%.

At December 31, 2016, Cleco had a $300.0 million long-term variable rate bank term loan outstanding. Amounts outstanding under the bank term loan bear interest at LIBOR plus 1.625%. At December 31, 2016, the all-in rate was 2.265%. Each 1% increase in the all-in interest rate applicable to such debt would result in a decrease in Cleco’s pretax earnings of $3.0 million.

Commodity Price Risks

Management believes Cleco has controls in place to minimize the risks involved in its financial and energy commodity activities. Independent controls over energy commodity functions consist of a middle office (risk management), a back office (accounting), and regulatory compliance staff. All forward commodity positions have established risk limits and are monitored through a daily market report that identifies the VaR, current market conditions, and concentration of energy market positions.

Cleco Power provides fuel for generation and purchases power to meet the power demands of customers. Cleco Power may enter into positions to mitigate the volatility in customer fuel costs, as encouraged by various LPSC orders. These positions would be marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability and a component of the energy risk management assets or liabilities. When these positions close, actual gains or losses would be included in the FAC and reflected in customers’ bills as a component of the fuel charge. There were no open natural gas positions at December 31, 2016. In June 2015, the LPSC approved a long-term natural gas hedging pilot program that requires Cleco Power to establish a proposal for a program that will be designed to provide gas price stability for a minimum of five years. This proposal is currently scheduled to be submitted to the LPSC during the second half of 2017.

Cleco Power purchases the majority of its FTRs in annual auctions facilitated by MISO during the second quarter of each year and may also purchase additional FTRs in monthly auctions facilitated by MISO. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Cleco Power’s customer load. FTRs are not designated as hedging instruments for accounting purposes. Cleco Power initially records FTRs at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period based on the most recent MISO FTR auction prices. Unrealized gains or losses on FTRs held by Cleco Power are included in Accumulated deferred fuel on Cleco and Cleco Power’s Consolidated Balance Sheets. Realized gains or losses on settled FTRs are recorded in Fuel used for electric generation on Cleco Power’s Consolidated Statements of Income. At December 31, 2016, Cleco and Cleco Power’s Consolidated Balance Sheets reflected open FTR positions of $7.9 million in Energy risk management assets and $0.2 million in Energy risk management liabilities. For more information on FTRs, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 6—Fair Value Accounting—Commodity Contracts.”

CLECO POWER

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

Cleco Power may enter into various fixed- and variable-rate debt obligations. For details, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 7—Debt.” Please refer to “—Interest Rate Risks” for a discussion of how Cleco Power monitors its mix of fixed- and variable-rate debt obligations and the manner of calculating changes in fair market value and interest expense of its debt obligations.

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At December 31, 2016, Cleco Power had no short- or long-term variable-rate debt.

At December 31, 2016, Cleco Power had no borrowings outstanding under its $300.0 million credit facility. The borrowing costs under the Cleco Power credit facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%.

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

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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

None.

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MANAGEMENT

Our Executive Officers

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 February 22, 2017, are as follows. Executive officers are appointed annually to serve for the ensuing year or until their successors have been appointed. Darren J. Olagues, the former Chief Executive Officer and President of Cleco Holdings and Cleco Power, resigned from the Company effective February 8, 2017.

NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Peggy B. Scott Cleco Holdings	Chairman and Interim Chief Executive Officer since February 2017; Executive Vice President, Chief Financial Officer/Treasurer, and Chief Strategy Officer, Blue Cross Blue Shield of Louisiana from August 2005 to July 2015. (Age 65; <1 year of service)
William G. Fontenot Cleco Power Cleco Holdings Cleco Power	Interim Chief Executive Officer since February 2017. Chief Operating Officer since April 2016; Senior Vice President—Utility Operations from March 2012 to April 2016; Group Vice President from March 2010 to March 2012. (Age 54; 30 years of service)
Terry L. Taylor Cleco Holdings Cleco Power	Chief Financial Officer since April 2016; Controller and Chief Accounting Officer from November 2011 to April 2016; Assistant Controller from August 2006 to November 2011. (Age 62; 16 years of service)
Julia E. Callis Cleco Holdings Cleco Power	Chief Compliance Officer and General Counsel since April 2016; Associate General Counsel and Corporate Secretary from November 2011 to April 2016; Senior Attorney from August 2007 to November 2011. (Age 48; 9 years of service)
Anthony L. Bunting Cleco Holdings Cleco Power	Chief Administrative Officer since April 2016; Vice President—Transmission & Distribution Operations from March 2012 to April 2016; Vice President—Customer Services and Energy Delivery from October 2004 to March 2012. (Age 57; 25 years of service)
Jeffrey M. Baudier Cleco Holdings Cleco Power	Chief Marketing & Development Officer since July 2016; Partner—Phelps Dunbar LLP from January 2013 to June 2016; President & Chief Executive Officer—Petra Nova LLC of NRG Energy from January 2011 to December 2012. (Age 48; <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; Manager Accounting Services from December 2007 to March 2014. (Age 52; 16 years of service)

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NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Robert R. LaBorde, Jr. Cleco Holdings Cleco Power	Vice President Generation Operations & Environmental Services since April 2016; Vice President—Strategic Planning, Development and Environmental Policy from November 2011 to November 2012; General Manager—Environmental Services from August 2006 to November 2011. Vice President—Generation Operations from November 2012 to April 2016. (Age 49; 25 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; Manager Transmission Protection, Apparatus & Metering from January 2005 to March 2013. (Age 53; 29 years of service)
Gregory A. Coco Cleco Holdings Cleco Power	Vice President Transmission & Distribution Operations since April 2016; General Manager Brame Energy Center from March 2013 to April 2016; General Manager Generation Engineering & Construction from March 2012 to March 2013; General Manager Transmission Services from October 2002 to March 2012. (Age 57; 35 years 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; General Manager Power Plant Engineering & Construction from June 2004 to March 2012. (Age 56; 35 years of service)
J. Robert Cleghorn Cleco Holdings Cleco Power	Vice President Regulatory Strategy since April 2016; General Manager Regulatory Strategy & Planning from March 2012 to April 2016; General Manager Regulatory Strategy from June 2005 to March 2012. (Age 58; 29 years of service)
Justin S. Hilton Cleco Holdings Cleco Power	Vice President MISO Operations since April 2016; General Manager Transmission Strategy from March 2012 to April 2016; General Manager Retail Operations from November 2004 to March 2012. (Age 47; 27 years of service)
Shirley J. Turner Cleco Holdings Cleco Power	Vice President Customer Experience since April 2016; General Manager Customer Experience Management from March 2012 to April 2016; Manager Customer Services from January 2005 to March 2012. (Age 63; 41 years of service)
Eric A. Schouest Cleco Holdings Cleco Power	Vice President Marketing South since August 2016; General Manager Governmental Affairs/Regulatory Sales from February 2013 to August 2016; General Manager Eastern District from November 2004 to February 2013. (Age 51; 15 years of service)

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NAME OF EXECUTIVE	POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Marty A. Smith Cleco Holdings Cleco Power	Vice President Marketing North since January 2017; General Manager Corporate Safety from April 2016 to January 2017; General Manager Distribution Engineering & Real Estate from February 2013 to April 2016; General Manager Northern District from March 2012 to February 2013; General Manager Central District from January 2009 to March 2012. (Age 55; 25 years of service)
Marcus A. Augustine Cleco Holdings Cleco Power	Corporate Secretary & Senior Attorney since April 2016; Senior Attorney from January 2015 to April 2016; Attorney from September 2012 to January 2015; Associate—Sidley Austin LLP from January 2011 to September 2012. (Age 36; 4 years of service)

Members of our Board of Managers

As of February 22, 2017, the Boards of Managers of Cleco Group and Cleco Holdings is comprised of 12 managers, as set forth below. Cleco Power’s Board of Managers is comprised of 13 managers, including the same 12 managers that comprise the Boards of Managers of Cleco Group and Cleco Holdings, plus one additional manager, Melissa Stark. The managers’ ages, dates of election, employment history, and committee assignments as of February 22, 2017, are also set forth below.

David Agnew is employed by MIRA and acts as MIRA’s liaison with federal, state and local governments in the United States. Mr. Agnew is 51 years old and became a member of the Boards of Managers in 2016. He is the chair of the Governance and Public Affairs Committee. Prior to joining MIRA, Mr. Agnew served at the White House, where he was Deputy Assistant to the President and Director of Intergovernmental Affairs. In this role, Mr. Agnew oversaw the Obama Administration’s relationship with state, city, county and tribal elected officials across the country. Mr. Agnew previously served as Deputy Director of the office and was the President’s liaison to America’s mayors and county officials.

Before working in the White House, Mr. Agnew was a businessman and community leader in Charleston, South Carolina. He has served as a top deputy to Charleston Mayor Joseph P. Riley, Jr., a Special Assistant in the Office of U.S. Secretary of Labor Robert Reich, and as a management consultant at PricewaterhouseCoopers LLP. Mr. Agnew has been active in public affairs and urban policy throughout his career, and has served in leadership roles for numerous non-profit organizations, including the Trust for Public Land, the Charleston Parks Conservancy, and the College of Charleston Riley Center. He also currently serves on the Board of Winrock International, a global development non-profit.

Mr. Agnew received his Master’s degree in Public Policy from Harvard University’s Kennedy School of Government. He is a Harry S. Truman Scholar, a European Union Visiting Fellow and a Liberty Fellow.

Andrew Chapman joined MIRA in 2006 and currently acts as Head of Asset Management for Macquarie Infrastructure Partners I, II and III and asset director for utility companies Puget Energy (Puget) and Aquarion Water Company (Aquarion). Mr. Chapman is 61 years old and became a member of the Boards of Managers in 2016. He is the chair of the Business Planning and Budget Review Committee and a member of the Leadership Development and Compensation Committee, the Governance and Public Affairs Committee and the Audit Committee. Mr. Chapman serves on the board of Puget and is the chairman of Aquarion’s board.

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.

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

Richard Dinneny is the Senior Portfolio Manager, Infrastructure and Renewable Resources for bcIMC, where he has responsibility for all aspects of investing in infrastructure transactions. He is 54 years old and became a member of the Boards of Managers in 2016. Mr. Dinneny is the chair of the Audit Committee and a member of the Business Planning and Budget Review Committee. Mr. Dinneny has reviewed and completed a number of infrastructure and utility investments. He currently serves as a director of Vier Gas Services GmbH & Co. KG, Essen, the owner of Open Grid Europe, and an alternate director on the board of Puget.

Mr. Dinneny earned his Masters of Business Administration from York University in Toronto and was awarded the Chartered Financial Analyst designation in 1998.

Mark Fay is a Managing Director for MIRA, where he is primarily responsible for the portfolio management and strategy of the MIP series of infrastructure funds operating within the United States and Canada. He is 35 years old and became a member of the Boards of Managers in 2016. Mr. Fay is the chair of the Asset Management Committee and a member of the Business Planning and Budget Review Committee.

Mr. Fay joined the Macquarie Group in 2003, working in the Risk Management division. In 2005, he transferred to MIRA, where he was part of the team that acquired a major ownership interest in a leading Australian retirement home business, and subsequently became the asset manager and then led the successful divestiture of the business. From 2008 until 2012, Mr. Fay worked for Illyria, an Australian-based media investment group, as an investment manager primarily focused on the sourcing and execution of new investments.

Mr. Fay holds a Bachelor of Commerce from Monash University, where he majored in Finance with minors in Accounting and Economics.

Richard “Rick” Gallot, Jr. is the President of Grambling State University. He is 50 years old and became a member of the Boards of Managers in 2016. Mr. Gallot is a member of the Leadership Development and Compensation Committee and the Governance and Public Affairs Committee.

Mr. Gallot recently served as a Louisiana state senator for District 29, where he held the position of vice-chairman 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.

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 57 years old and became a member of the Boards of Managers 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, chairman of Driving Louisiana Forward, chairman of the Central Louisiana Chamber of Commerce, and vice chairman of Central Louisiana Economic Development Alliance. He has also served on the boards of The Rapides Foundation and Rapides Healthcare System.

Recep Kendircioglu is a Managing Director at John Hancock Financial Services in the Power and Infrastructure Group. He is 41 years old and became a member of the Boards of Managers in 2016. Mr. Kendircioglu is a member of the Asset Management Committee.

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Mr. Kendircioglu joined John Hancock in 2007, where he is responsible for the origination and execution of debt and equity investments in the infrastructure and utility sectors.

Mr. Kendircioglu holds a Masters in Business Administration from Rice University. He is a Chartered Financial Analyst, a certified Financial Risk Manager and a member of the Boston Security Analysts Society.

Christopher Leslie is the CEO of MIP, the manager of MIRA’s U.S.-based private infrastructure funds, Macquarie Infrastructure Partners I, II and III, which collectively manage more than $7 billion in U.S. and Canadian infrastructure investments. Mr. Leslie is 52 years old and became a member of the Boards of Managers 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.

Peggy Scott is the interim CEO of Cleco Group and Cleco Holdings since February 8, 2017. Prior to joining Cleco Group and Cleco Holdings, Ms. Scott served as the Executive Vice President and Chief Operating Officer of Blue Cross Blue Shield of Louisiana (BCBS). She is 65 years old and became a member of the Boards of Managers in 2016. Ms. Scott is the chair of Cleco’s Boards of Managers and also serves as a member of the Governance and Public Affairs Committee.

Ms. Scott joined BCBS in 2005 as Executive Vice President, Chief Financial Officer/Treasurer, and Chief Strategy Officer. She became the Executive Vice President and Chief Operations Officer in 2008. Ms. Scott was the first woman in the U.S. to receive the IMA/Robert Half National Financial Executive of the Year award. She was the first Louisiana resident to be named to the American Institute of CPA’s Business and Industry Hall of Fame in 2007. In April 2014, Ms. Scott was inducted in Louisiana State University’s E.J. Ourso College of Business’s Hall of Distinction.

Ms. Scott received her executive Masters of Business Administration from Tulane University.

Melissa Stark currently serves as the managing principal and owner of Co Issuer Corporate Staffing, LLC (CICS) which she established in 2003 to provide independent directors and officers for special purpose entities. She is 54 years old and was appointed 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 Company Agreement. Ms. Stark concurrently serves 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) and 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 and has held a number of financial analyst positions.

Steven Turner is a Portfolio Manager within the Infrastructure & Renewable Resources Department at bclMC, where he is responsible for sourcing, executing, and managing infrastructure investments. He is 44 years old and became a member of the Boards of Managers in 2016. Mr. Turner is a member of the Business Planning and Budget Review Committee and Asset Management Committee.

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

Mr. Turner has over 10 years of experience in equity capital markets. Prior to joining bcIMC, 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.

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Mr. Turner has a B.S. 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 and is a Chartered Financial Analyst charter holder.

Bruce Wainer is the CEO of Wainer Enterprises, a family-owned commercial development company on Louisiana’s Northshore and in New Orleans. He is 57 years old and became a member of the Boards of Managers in 2016. He is a member of the Business Planning and Budget Review Committee and Asset Management Committee. He is the developer of some of the most successful commercial developments in the New Orleans area and 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.

Lincoln Webb is the Senior Vice President of Infrastructure & Renewable Resources at bcIMC, where he is responsible for the overall management of the firm’s infrastructure and renewable resource investments and setting strategic direction for the group. He is 45 years old and became a member of the Boards of Managers in 2016. Mr. Webb is a member of the Leadership Development and Compensation Committee. Currently, Mr. Webb serves as a director on the boards of Open Grid Europe GmbH and is a member of the Audit committee at Corix Infrastructure. He has served as a director on the boards of Puget Energy in Washington, DBCT Ports of Australia, Aquarion Water of Connecticut, Thames Water in London and Transelec S.A., Chile’s largest transmission utility.

He holds a Masters of Business Administration in International Business from the University of Victoria, a Masters of City Planning from the Department of Architecture at the University of Manitoba, and is a Chartered Financial Analyst charter holder.

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EXECUTIVE COMPENSATION

Leadership Development and Compensation Committee Interlocks and Insider Participation

The members of the Leadership Development and Compensation Committee (Committee) of the Boards of Managers (Board) of Cleco Power and Cleco Holdings (referred to in this section as the Company) who served during 2016 are named in the Report of the Leadership Development and Compensation Committee. No members of the Committee were officers or employees of the Company or any of its subsidiaries during 2016, were formerly Company officers or had any relationship otherwise requiring disclosure. Effective with the completion of the Merger, the Board was appointed, and the Committee was appointed May 10, 2016.

Compensation Discussion and Analysis (CD&A)

This section provides information about the compensation program in place for the Company’s named executive officers after the Merger and 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. For a detailed discussion of compensation for the named executive officers prior to the Merger, see “Pre-Merger Compensation Discussion and Analysis” below.

Executive Summary

2016 Business Highlights

In 2016 the Company successfully completed the regulatory approvals for the Merger. Following the Merger, the Company reestablished the organization as well as its governing structure while achieving solid operating and financial performance. Below are some of our accomplishments for the year:

• Key Strategic Initiatives Related to the Merger

• Completed the valuation of the investment in the Company

• Refinanced the Acquisition Loan Facility of $1.35 billion

• Established credit ratings at Cleco Holdings and Cleco Power

• Effective Utility Operations

• Secured $20.8 million investment for additional tree trimming including a regulatory approval and recovery mechanism

• Successfully negotiated a five-year extension of the Acadia Joint Owner Agreement with Entergy Louisiana

• Key Capital Investments

• Completed the St. Mary Clean Energy Center Operating and Lease Agreement and initiated construction of the project

• Completed the Cenla Donahue transmission substation which is part of the Cenla Transmission Expansion Project

• Completed the Layfield/Messick Project

• Received MISO approval to construct the $48.0 million Terrebonne to Bayou Vista Transmission Project

• Constructive Regulatory Outcomes

• Filed a letter seeking guidance on the appropriate treatment and timing of recovering revenue associated with the Coughlin Pipeline Project

• Successfully completed fuel and environmental audits

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Compensation Philosophy

The Committee has discussed the following key compensation principles and philosophy:

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

• 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, but individual positioning may vary above or below the median depending on each executive’s experience, performance, and contribution to the Company. For 2016, we believe that we accomplished our philosophy through the following compensation and benefit components:

2016 Pay Element	Description
Base Salary	•    Fixed pay element •    Delivered in cash
Annual Cash Incentive (PFP Plan)	•    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, and generation fleet availability
Retention Bonus	•    Performance-based annual incentive plan that pays out in cash in the two years following the close of the Merger •    Metrics are consistent with those included in the PFP Plan
Long-Term Incentives	•    Prior to the completion of the Merger, there was an annual equity grant delivered in the form of performance shares
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 a 401(k) Savings Plan with a Company match for those employees hired before August 1, 2007, as well as a 401(k) Savings Plan with an enhanced benefit for those employees hired on or after August 1, 2007; same as those provided to all employees
Executive Benefits	•    Supplemental Executive Retirement Plan (closed to new participants in 2014) •    Nonqualified Deferred Compensation Plan
Perquisites	•    Limited to executive physicals, spousal/companion travel, and relocation assistance

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Roles and Responsibilities

Leadership Development and Compensation Committee

The Committee, which consists of one Louisiana independent Board Manager and three investor Board Managers, is responsible for developing and overseeing the Company’s executive compensation program. The Committee met five times during 2016, including three telephone meetings. The CEO and Chief Administrative Officer attend the Committee’s meetings on behalf of management but do not participate in the Committee’s executive sessions.

The Committee’s responsibilities, which are more fully described in the Committee’s 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 recommending to the Board adjustments in the CEO’s compensation and benefits;

• annually reporting and recommending to the Board pay adjustments for the non-CEO executive officers (including new hires), which includes base salary and incentive plan targets;

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

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

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

The Compensation Consultant

After the Merger, the Committee engaged Pay Governance to consult on matters concerning executive officers’ compensation and benefits. All executive compensation adjustments and award calculations for 2016 were reviewed by Pay Governance on behalf of the Committee. Pay Governance acted at the direction of the 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 Manager compensation program;

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

• attending the Committee meetings.

Before engaging Pay Governance, the Committee reviewed the firm’s qualifications as well as its independence and the potential for conflicts of interest. The Committee concluded that Pay Governance is

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independent and its services to the Committee do not create any conflicts of interest. The Committee has the sole authority to approve Pay Governance’s compensation, determine the nature and scope of its services, and determine the agreement. Pay Governance does not perform any other services for or receive any other fees from the Company.

President and CEO

The President and CEO makes recommendations to the Committee regarding base salary adjustments, cash incentives, and long-term incentive awards. The CEO participates in meetings of the Committee to discuss executive compensation, including measures and performance targets but is subsequently excused to allow the independent members of the Committee to meet in executive session.

The Committee has delegated limited authority to the CEO to extend employment offers to officers at the level of vice president or lower. The CEO may make such offers without prior approval of the Board provided no compensation component falls outside the Committee’s approved policy limits as described below in “Decisions Made in 2016 with Regard to Each Compensation and Benefit Component.” No such employment offers were made under this delegation of authority during 2016.

Evaluation and Design of the Compensation and Benefit Programs

The 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 Committee examines our executive officers’ compensation against comparable positions using publicly available proxy data for a group of 16 industry peers (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.”

The Peer Group, approved by the Committee in October 2016, had several revisions from our 2015 Peer Group. Companies removed from the Peer Group were Calpine, AGL Resources, Pinnacle West Capital, Alliant Energy, and Vectren. Companies added to the Peer Group were Westar Energy, UIL Holdings, Otter Tail Corporation, Empire District Electric Company, and MGE Energy. The 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 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.

2016 Peer Group Companies
ALLETE, Inc.	IDACORP, Inc.	Portland General Electric Company
Avista Corporation	MGE Energy Inc.	TECO Energy, Inc.
Black Hills Corporation	NorthWestern Corporation	UIL Holdings Corporation
El Paso Electric Company	OGE Energy Corp.	Westar Energy, Inc.
The Empire District Electric Company	Otter Tail Corporation
Great Plains Energy Incorporated	PNM Resources, Inc.

In setting executive compensation levels in 2016, the 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 Committee to consider in determining pay levels.

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Decisions Made in 2016 with Regard to Each Compensation and Benefit Component

Base Salary

We strive 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 base pay.

In 2016, base salary increases for the post-merger named executive officers averaged 18.1% due to promotions and pay adjustments. Due to the departure of several named executive officers, overall 2016 base salaries for post-merger named executive officers decreased compared to pre-merger named executive officers. For more information, see Summary Compensation Table below.

Base salaries for the named executive officers in 2016 are shown in the table below:

Name	2016 Base Salary		2016 % Change
Mr. Olagues	$	550,000		36.9	%
Ms. Taylor	$	230,000		17.5	%
Mr. Bunting	$	230,000		6.3	%
Mr. Fontenot	$	290,000		12.6	%
Mr. Crump	$	257,500		0	%
Average % Change				18.1	%

Annual Cash Incentive

We maintain the PFP Plan, an annual, performance-based cash incentive plan. The PFP Plan applies to all regular, full-time employees, and it includes weighting for corporate and individual performance goals. Our executive officers have 100% of their PFP Plan targets weighted on corporate goals, since they have more influence over corporate-level results. As mentioned, the Committee targets PFP Plan 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 PFP Plan opportunities for the named executive officers in 2016:

Name	Target as % of Base Salary
Mr. Olagues		80	%
Ms. Taylor		50	%
Mr. Bunting		50	%
Mr. Fontenot		50	%
Mr. Crump		50	%

The 2016 PFP Plan award for the named executive officers was based entirely on the corporate performance measures described below. The 2016 PFP Plan corporate performance measures consisted of the four metrics listed below (weighting):

• EBITDA (70%)

• System Average Interruption Duration Index or SAIDI (7.5%)

• Equivalent Availability Factor or EAF (7.5%)

• Safety (15%)

In establishing the 2016 PFP Plan corporate metrics, the Committee believed it was most important to reward senior executives for the overall financial performance of the Company, and therefore weighted EBITDA

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most heavily at 70%. In addition, to continually focus the executives and the entire organization on the importance of safety, system reliability, and generation fleet availability, 30% of the bonus opportunity attributable to the corporate measures was contingent on safety and operational performance. The Quality Performance Factor in the 2015 PFP Plan was removed.

The CEO recommended the PFP Plan financial performance and other measures to the Committee following the close of the Merger. Based on the historical performance relative to target and the relative historical performance versus the Comparator Group, the Committee reviews, revises as appropriate, and approves the PFP Plan measures for the upcoming year.

Details Related to Corporate Performance Metrics Established to Determine 2016 PFP Plan Award Levels

Metric # 1: EBITDA—For 2016, the following EBITDA matrix was developed to determine performance and payout ranges related to EBITDA performance. This measure represents 70% of the overall PFP Plan award for the corporate measures. The final percentage of the financial target award is interpolated based on the performance level.

EBITDA MATRIX (70%)

Performance Level	% of Financial Target Award Paid
At or below $410.4 million		0	%
$443.7 million		100	%
At or above $477.0 million		200	%
2016 Result—$442.9 million		98	%

Metric # 2:SAIDI—The average amount of time a customer’s service is interrupted during the year. SAIDI is measured in hours per customer per year and based on a ten-year rolling average of Cleco Power’s performance. This metric represents 7.5% of the overall PFP Plan award for the corporate measures.

SAIDI MATRIX (7.5%)

Performance Level	Hours Per Customer Per Year		% of SAIDI Target Award Paid
		>2.66		0	%
Threshold		2.66 to 2.59		50	%
Target		2.58 to 2.51		100	%
		2.50 to 2.43		150	%
Maximum		<2.43		200	%
2016 Result		2.58 Hours		100	%

Metric # 3: EAF—Measures the percentage of time that a generation unit is available to generate electricity after all types of outages are taken into account. EAF is measured as a percentage based on a three-year MISO equivalent forced outage rate, demand, and Cleco Power’s planned maintenance for the year. This metric represents 7.5% of the overall PFP Plan award for the corporate measures.

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EAF MATRIX (7.5%)

Performance Level	% Generation Fleet Availability			% of EAF Target Award Paid
		<79.95	%		0	%
Threshold		79.95% to 81.99	%		50	%
Target		82.00% to 84.08	%		100	%
		84.09% to 86.18	%		150	%
Maximum		>86.18	%		200	%
2016 Result		82.85	%		100	%

Metric # 4: Safety Injury Incident Rate (IIR)—For 2016, the Company changed the safety measure from the number of injuries and the number of vehicle accidents to a single injury incident rate. It is a measure of the relative level of injuries and illnesses according to the hours worked and the number of employees. The target for this measure represents a 10% improvement over the three-year average of the Company’s injury incident rate.

SAFETY—INJURY INCIDENT RATE (15%)

Performance Level	Performance Relative to 2014		% of Safety - Injuries Target Award Paid
		>0.663		0	%
Threshold		0.663 to 0.598		50	%
Target		0.597 to 0.565		100	%
		0.564 to 0.531		150	%
Maximum		<0.531		200	%
2016 Result		0.941		0	%

Total Payout: The Committee determined that a total PFP Plan payout at 83.6% of target for the corporate measures was reasonable based on the Company’s performance in 2016. The resulting total PFP Plan corporate payout for 2016 was calculated as follows:

	% of Target			x	Award Level			=	% of Payout
EBITDA		70.0	%			98	%			68.6	%
SAIDI		7.5	%			100	%			7.5	%
EAF		7.5	%			100	%			7.5	%
Safety IIR		15.0	%			0	%			0	%
Total		100.0	%							83.6	%

The Committee also has the authority to adjust the amount of any individual PFP Plan award with respect to the total award or the corporate or individual component of the award upon recommendation by the CEO. Adjustments for PFP Plan participants, except for the named executive officers, may be made by the CEO at his discretion. Adjustments are based on the annual performance review process. No adjustments were made to the 2016 PFP Plan awards for the named executive officers.

Retention Bonus

For those executives who were participants in the previous equity-based LTIP, the Board approved a cash award, a portion of which will be paid in 2017 and a portion of which will be paid in 2018, that is designed to fill the gap created by the missed earning opportunity on the outstanding LTIP cycles at the time of the Merger. These cash awards are intended to be paid out in the same proportion as the payout on the short-term incentive

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for 2016 and 2017, respectively; however, the Committee retains the ability to modify the payouts to ensure alignment with investor expectations. For performance results of the Retention Bonus metrics, see “Details Related to Corporate Performance Metrics Established to Determine 2016 PFP Plan Award Level.”

Long-Term Compensation

The Committee has designed a new cash-based LTIP which is expected to be adopted in 2017.

Retirement Plans—Nonqualified Deferred Compensation Plan

The Company maintains a Deferred Compensation Plan so that Board Managers, executive officers, and certain key employees may defer receipt and taxation of certain forms of compensation. Board Managers 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 2016.

Retirement Plans—SERP

The Company maintains a SERP for the benefit of the executive officers who are designated as participants by the 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 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) Savings 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, 2016.

In 2011, the 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 the calculation as of December 31, 2017. Additionally, they have agreed to use target rather than actual awards under the annual incentive plan for years 2016 and 2017 for the average incentive award portion of the SERP calculation.

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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 the Merger for all participants who commenced participation in SERP prior to October 28, 2011, or the 24-month period following the Merger 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. For additional details regarding the effect of the Merger on SERP, see “Interests of Our Directors and Executive Officers in the Merger” beginning on page 52 of the definitive proxy statement dated January 13, 2015.

Change in Employment Status and Change in Control Events

The Company has no employment agreements but 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.

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.

In October 2014, the Compensation Committee of the Cleco Corporation Board of Directors (the Compensation Committee), with the approval of the full Cleco Corporation Board of Directors, approved an amendment to the Executive Severance Plan to provide that an officer cannot trigger “Good Reason” under the Executive Severance Plan based on the fact Cleco Corporation is no longer publicly traded. In December 2014, the Compensation Committee, with the approval of the full Cleco Corporation Board of Directors, approved additional amendments to the Executive Severance Plan expanding the definition of “Committee,” removing the authority of the Compensation Committee to continue making determinations of “Good Reason,” and clarifying that a potential acquirer of Cleco Corporation cannot terminate the Executive Severance Plan during a change in control period without the consent of the “Covered Executive.” In July 2015, the Compensation Committee, with the approval of the full Cleco Corporation Board of Directors, approved an amendment to the Executive Severance Plan to expand the definition of waiver, release, and covenants to include covenants prohibiting competition and to revise the definition of participants who are eligible to receive benefits to mean those who have satisfied the conditions included in the waiver, release, and covenants agreement.

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 PFP Plan 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 we pay real estate agent and certain other closing fees should the officer or key employee sell his/her primary residence or that we purchase the executive officer’s or key employee’s primary residence at the

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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 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. Perquisite expenses related to business and spousal/companion travel for the executive officers are reviewed by internal audit and any exceptions are reported to the Audit Committee.

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; defined benefit pension plan (for those hired prior to August 1, 2007); and the 401(k) Savings Plan with a Company match for those employees hired before August 1, 2007, as well as a 401(k) Savings Plan with an enhanced benefit for those employees hired on or after August 1, 2007.

Other Tools and Analyses to Support Compensation Decisions

Tally Sheets

At least annually, the 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 Committee’s outside independent consultant as to the use and amount of each compensation and benefit component versus the applicable Peer Group.

• 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 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.

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Risk Assessment

The 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 Committee believes that the following actions and/or measures help achieve this goal:

• the Committee reviews the design of the executive compensation program to ensure an appropriate balance between business risk and resulting compensation;

• the 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 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.

Board Compensation

The Governance and Public Affairs Committee may engage the Committee’s independent consultant from time to time to conduct market competitive reviews of the Board Manager’s compensation program. Details of Board Manager compensation are shown in the “Board Manager Compensation” table.

IRC Section 409A

Internal Revenue Code (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.

Pre-Merger Compensation Discussion and Analysis

Compensation and Governance Practices

The Compensation Committee regularly reviewed the Company’s compensation practices and policies to ensure that they promoted the interests of the Company’s investors and customers. The Company’s pre-Merger governance practices included:

• Clawback Policy: The formal recoupment policy, applicable to officer incentive compensation awards, authorized the Compensation Committee to recover officer incentive payouts if those payouts were based on financial performance results that were subsequently revised or restated to levels that would have produced lower incentive plan payouts. The recoupment policy was intended to reduce potential risks associated with our incentive plans, and thus more closely aligned the long-term interests of the named executive officers and the shareholders.

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• Stock Ownership Guidelines: The officer stock executive ownership requirements strengthened the alignment of the financial interests of the executive officers with those of shareholders and provided an additional basis for sharing in the Company’s success or failure as measured by overall shareholder returns. For 2016, 10 out of 11 of our executive officers had achieved their established ownership levels based on the requirements, and the other executive officer was on track to meet the required ownership level.

• Performance-based Incentive Programs: The Company’s total compensation program did not provide for guaranteed bonuses and had multiple performance measures. Annual cash incentive components focused on both the actual results and the quality of those results. The annual cash incentive plan for employees and executives contained both economic and qualitative components. The incentive plan also focused on system reliability, generation fleet availability, safety results, and individual performance through the PFP Plan.

• Anti-hedging Policy: The “anti-hedging” policy in the Company’s insider trading policy stated that all directors, officers, and employees were prohibited from hedging the economic interest in the Cleco Corporation shares they held.

• No Excise Tax Gross-ups: No change in control arrangement included an IRC Section 280G excise tax gross-up provision.

• Use of Independent Consultants: The Compensation Committee had a formalized process to ensure the independence of the executive compensation consultant plus other advisors and reviewed and affirmed the independence of advisors annually.

The Executive Compensation Process

The Compensation Committee

The Compensation Committee of the Board of Directors of Cleco Corporation met twice prior to the close of the Merger. The CEO and Senior Vice President of Corporate Services and IT attended the Compensation Committee’s meetings on behalf of management but did not participate in the Committee’s executive sessions. The Compensation Committee’s responsibilities, which were more fully described in the Compensation Committee’s charter, included:

• establishing and overseeing the Company’s executive compensation and benefit programs;

• determining if the Company’s executive compensation and benefit programs were 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 recommending to the board of directors adjustments in the CEO’s compensation and benefits;

• annually reporting and recommending to the Board pay adjustments for the non-CEO executive officers (including new hires), which include base salary and incentive plan targets; and

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

The Compensation Consultant and Role of the CEO

In 2010, the Compensation Committee engaged Frederic W. Cook & Co., Inc. (Cook & Co.) to consult on matters concerning executive officers’ compensation and benefits. Cook & Co. acted at the direction of the

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Compensation Committee and was independent of management. The Compensation Committee determined Cook & Co.’s ongoing engagement activities, and Cook & Co. endeavored to keep the Compensation Committee informed of executive officers’ compensation trends and regulatory compliance developments. The Compensation Committee assessed the independence of Cook & Co. pursuant to SEC rules and concluded that its work did not raise any conflict of interest that would prevent Cook & Co. from independently representing the Compensation Committee.

The CEO participated in meetings of the Compensation Committee to discuss executive compensation, including measures and performance targets, but was subsequently excused to allow the independent members of the Compensation Committee to meet in executive session.

Shareholder Advisory Vote

At the Company’s last annual meeting held in 2014, shareholders strongly supported (approximately 97% of votes cast at the annual meeting voted for) our “say-on-pay” proposal. This “say-on-pay” vote was not binding on the Company, the Compensation Committee or the Board; however, the Directors and the Compensation Committee reviewed the voting results and considered them, along with any specific insight gained from the Cleco Corporation shareholders, when they made decisions regarding executive compensation.

Evaluation and Design of Our Compensation and Benefit Programs

Market Data and Comparator Group

The Compensation Committee examined the named executive officers’ compensation against comparable positions using publicly available proxy data for a group of 16 industry peers and utility industry survey data to help design and benchmark the named executive officer compensation. The Proxy Peer Group, approved by the Compensation Committee in July 2014, was used to track comparable performance of our long-term incentive plan.

The general criteria examined in developing the Proxy Peer Group include:

• Operational fit: companies in the same industry with similar business operations and energy portfolio (e.g., companies that derive a majority of their revenues from a state regulated utility and have no large scale nuclear operations);

• Financial scope: companies of similar size and scale. Size was measured on a number of criteria relevant to this industry (e.g., market capitalization, enterprise value, assets, and revenues). Most of the peer companies were within one to three times the size of Cleco Corporation’s market capitalization, which was the principle measure of scale in this industry. Revenues, used most frequently in general industry, may have not lent itself as the most appropriate measure of scale in the utilities industry due to significant volatility in annual revenues. In limited circumstances, the small number of direct competitors in our industry may have required the inclusion of one or more companies that were outside of this range if they were a direct competitor for business or talent. Cleco Corporation’s market capitalization was positioned at or near the median against the Proxy Peer Group;

• Competitors for talent: companies with whom the Company competed for executive talent or those that employed similar labor or talent pools; and

• Competitors for investor capital.

2016 Pre-Merger Peer Group Companies
AGL Resources Inc.	El Paso Electric Company	PNM Resources, Inc.
ALLETE, Inc.	Great Plains Energy Incorporated	Portland General Electric Company
Alliant Energy Corporation	IDACORP, Inc.	TECO Energy, Inc.
Avista Corporation	NorthWestern Corporation	Vectren Corporation
Black Hills Corporation	OGE Energy Corp.
Calpine Corporation	Pinnacle West Capital Corporation

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Decisions Made in 2016 with Regard to Each Compensation and Benefit Component

Base Salary

The Compensation Committee worked to set base salary levels for the executive officers as a group, including the named executive officers, at a level approximating +/-15% of our Comparator Group market median for base pay. In 2016 prior to the Merger, there were no base salary increases for our named executive officers.

Name	2016 Base Salary Pre-Merger
Mr. Olagues	$	401,700
Ms. Taylor	$	195,700
Mr. Bunting	$	216,300
Mr. Fontenot	$	257,500
Mr. Crump	$	257,500
Mr. Williamson	$	745,000
Mr. Miller	$	309,000
Ms. Miller	$	298,700
Mr. Hoefling	$	298,700

Annual Cash Incentive

In anticipation of the Merger, the Compensation Committee did not establish 2016 PFP Plan targets. Named executive officers who left following the Merger were not granted awards under the 2016 PFP Plan.

Equity Incentives

Upon closing of the Merger on April 13, 2016, unvested performance-based equity grants for the three-year performance cycle beginning January 1, 2014, vested at target based on a price per share equal to $55.37. For the three-year performance period beginning January 1, 2015, unvested performance-based equity grants vested at target based on a price per share equal to $55.37, and the equity grant target shares were prorated based upon the number of days lapsed in the 2015 cycle.

Outstanding time-based equity awards also vested based on a price per share equal to $55.37 upon closing of the Merger. The Compensation Committee did not approve performance-based restricted stock, time-based restricted stock, or stock options to named executive officers during 2016. The Company has not granted any stock appreciation rights under the terms of the LTIP since its adoption.

For additional details regarding the effect of the Merger on equity incentives, see “Interests of Our Directors and Executive Officers in the Merger” beginning on page 52 of the definitive proxy statement dated January 13, 2015.

LTIP Award

In anticipation of the Merger’s closing, no equity grants were made by the Compensation Committee for the three-year performance cycle beginning January 1, 2016, and the LTIP terminated at the close of the Merger.

Retirement Plans—Nonqualified Deferred Compensation Plan and SERP

The Deferred Compensation Plan and SERP were part of the executive retirement benefits prior to the Merger and are explained in detail in the sections titled “Retirement Plans—Nonqualified Deferred Compensation Plan” and “Retirement Plans—SERP” above.

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In connection with the Merger, payment of deferred compensation plan balances that accrued after December 31, 2004, were accelerated by means of an election made pursuant to the terms of the Company’s compensation plans triggered by a change in control involving the Cleco Corporation. One former director, Mr. William H. Walker, made such an election and an accelerated payment of any deferred compensation plan balance accrued after December 31, 2004 was made in the form of a single lump sum payment following the effective date of the Merger.

Change in Employment Status and Change in Control Event Benefits

During 2011, in conjunction with his being hired as CEO, Cleco Corporation entered into an employment agreement with Mr. Bruce A. Williamson. That agreement was fulfilled at the close of the Merger. The Change in Control benefits are described in the section “The Cleco Corporation Executive Severance Plan.”

Perquisites and Other Benefits

The perquisites and other benefits made available to named executive officers prior to the Merger are consistent with those offered currently. See the section titled “Perquisites and Other Benefits” for a more detailed explanation.

IRC Section 162(m)

IRC Section 162(m) limits to $1,000,000 the amount Cleco Corporation could deduct in a tax year for compensation paid to the CEO and each of the three other most highly compensated executive officers (other than the CFO). Performance-based compensation paid under a plan approved by Cleco Corporation shareholders that satisfied certain other conditions may have been excluded from the calculation of the limit.

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 Corporation shareholders, whether or not the compensation was performance-based within the meaning of IRC Section 162(m) or otherwise fully deductible. The LTIP was approved by Cleco Corporation shareholders, permitting grants and awards made under that plan to be treated as performance-based. Generally, options, performance-based restricted stock and performance-based CEUs were intended to satisfy the performance-based requirements of IRC Section 162(m) and were intended to be fully deductible. Amounts paid under the PFP Plan counted toward the $1,000,000 limit.

The Compensation Committee

The individuals listed below were the members of Cleco Corporation’s Compensation Committee throughout 2015 and up until the effective date of the Merger on April 13, 2016.

Compensation Committee of Cleco Corporation (2015 through April 13, 2016):

Logan W. Kruger, Chair

Peter M. Scott III

William H. Walker

William L. Marks

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Executive Officers’ Compensation

Summary Compensation Table

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3)		All Other Compensation ($)		Total ($)
A	B		C		D		E		F		G		H		I		J
Darren J. Olagues,(1)		2016	$	502,658	$	0	$	0	$	0	$	0	$	829,173	$	790,256	$	2,122,087
President and CEO		2015	$	400,800	$	0	$	368,904	$	0	$	222,745	$	14,921	$	39,223	$	1,046,593
		2014	$	389,423	$	0	$	509,068	$	0	$	278,850	$	1,205,650	$	42,809	$	2,425,800
Terry L. Taylor,(2)		2016	$	219,051	$	0	$	0	$	0	$	129,353	$	202,970	$	219,872	$	771,246
Chief Financial Officer
Anthony L. Bunting,(2)		2016	$	225,627	$	0	$	0	$	0	$	137,127	$	698,496	$	240,627	$	1,301,877
Chief Administrative Officer
William G. Fontenot,(2)		2016	$	279,625	$	0	$	0	$	0	$	186,907	$	308,118	$	351,738	$	1,126,388
Chief Operating Officer
Keith D. Crump,(2)		2016	$	257,500	$	0	$	0	$	0	$	213,827	$	160,794	$	355,395	$	987,516
Chief Commercial Officer
FORMER EXECUTIVE OFFICERS:
Bruce A. Williamson,		2016	$	240,692	$	0	$	0	$	0	$	0	$	3,275,840	$	7,618,463	$	11,134,995
Former President & CEO		2015	$	745,000	$	0	$	1,461,526	$	0	$	636,975	$	0	$	256,805	$	3,100,306
		2014	$	743,846	$	0	$	2,077,315	$	0	$	819,500	$	2,709,379	$	260,481	$	6,610,521
Thomas R. Miller,		2016	$	99,831	$	0	$	0	$	0	$	44,324	$	0	$	1,111,716	$	1,255,871
Former SVP—CFO & Treasurer		2015	$	308,308	$	0	$	193,481	$	0	$	131,802	$	117,859	$	16,730	$	768,180
		2014	$	299,231	$	0	$	267,005	$	0	$	165,000	$	1,372,794	$	11,872	$	2,115,902
July P. Miller,		2016	$	109,140	$	0	$	0	$	0	$	42,846	$	792,422	$	833,644	$	1,778,052
Former SVP—Corporate Services & Information Technology		2015	$	298,301	$	0	$	187,051	$	0	$	127,409	$	36,402	$	34,145	$	683,308
		2014	$	289,423	$	0	$	258,109	$	0	$	159,500	$	859,654	$	26,209	$	1,592,895
Wade A. Hoefling,		2016	$	96,503	$	0	$	0	$	0	$	42,846	$	187,861	$	1,023,959	$	1,351,169
Former SVP—General Counsel & Director Regulatory Compliance		2015	$	298,301	$	0	$	187,051	$	0	$	127,409	$	53,154	$	33,821	$	699,736
		2014	$	289,615	$	0	$	258,109	$	0	$	159,500	$	887,456	$	35,432	$	1,630,112

(1) Mr. Olagues resigned from the Company effective February 8, 2017. As of the date of this report, no severance arrangements have been entered into in connection with his departure. Any severance arrangement, which could include payment of a non-equity incentive plan bonus for 2016, will be disclosed in a subsequent filing.

(2) Ms. Taylor, Mr. Bunting, Mr. Crump, and Mr. Fontenot were promoted to Chief officer positions following the merger and were not classified as named executives previously.

(3) Amounts in this column include the change in pension value year over year. For 2016, this amount includes the change in pension value from 2015 to 2016. Negative changes in the pension value year over year are reported as $0.

General

The Summary Compensation Table sets forth individual compensation information for the CEO, the CFO, and the three 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, 2016, December 31, 2015 and

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December 31, 2014 (the “named executives” or “named executive officers”). The table also includes former officers, who would have been named executives had they not left the Company in connection with the Merger. 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 G, “Non-Equity Incentive Plan Compensation;” and Column I, “All Other Compensation” represent cash compensation earned by the named executive in 2016, 2015 or 2014.

• Awards shown in Column E, “Stock Awards” and Column F, “Option Awards” represent non-cash compensation items which may or may not result in an actual award being received by the named executive, depending on the nature and timing of the grant and until certain performance objectives are achieved.

• The amounts shown in Column H, “Change in Pension Value and Nonqualified Deferred Compensation Earnings,” represent changes in the actuarial value of accrued benefits during 2016, 2015 and 2014 under the Pension Plan and SERP. Actuarial value computations are based on assumptions discussed in “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 9—Pension Plan and Employee Benefits.” The 2016 changes shown in Column H are due 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 “Decisions Made in 2016 with Regard to Each Compensation and Benefit Component—Base Salary” in the CD&A. 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 2016, 2015 and 2014 base pay made by Ms. Miller 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 Leadership Development and Compensation Committee typically on an annual basis, and if approved, usually are implemented in January. Base salary changes made in 2016 for our named executives and the reasons for those changes are discussed in “Decisions Made in 2016 with Regard to Each Compensation and Benefit Component—Base Salary” in the CD&A.

Bonus

Column D, “Bonus” includes non-plan-based, discretionary incentives earned during 2016, 2015, or 2014. No such awards were earned in 2016, 2015, or 2014 by the named executive officers.

Stock Awards

Column E reflects grants and awards of Cleco Corporation common stock made to the named executive officers. Such grants and awards include annual performance-based restricted stock, as well as time-based service award grants. There were no stock grants or awards made in 2016. For 2015, Column E includes the grant date fair value calculated under GAAP for the three-year performance cycle beginning January 1, 2015 and ending December 31, 2017. For 2014, Column E includes the grant date fair value calculated under GAAP for the performance-based award covering the three-year performance cycle beginning January 1, 2014 and ending December 31, 2016.

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The dollar value of the LTIP grants in Column E is based on the grant date fair value as required by FASB, and does not represent cash compensation received by the named executives during 2015 or 2014. The value was determined by the Company’s actuary (Willis Towers Watson) and reflected a “fair value” estimate using a Monte Carlo simulation over the requisite performance cycle based on Cleco Corporation’s historical stock price volatility and dividend yield data compared to each company in the Proxy Peer Group. For the three performance-based cycles applicable to Column E, the grant date fair value of Cleco common stock was $45.60 for the 2015 to 2017 cycle and $54.58 for the 2014 to 2016 cycle.

Option Awards

Column F, “Option Awards” reflects the grant date fair value for grants made to executive officers in 2016. No stock options were granted to our named executive officers during 2016, 2015 or 2014.

Non-Equity Incentive Plan Compensation

Column G, “Non-Equity Incentive Plan Compensation” contains cash awards earned during 2016 and paid in March 2017; earned during 2015 and paid in December 2015 and/or March 2016; and earned during 2014 and paid in December 2014 and/or March 2015 under the PFP Plan. Deferral of annual cash incentive payments made by Mr. Fontenot and Mr. Hoefling pursuant to the Deferred Compensation Plan also is included in Column G and is further detailed in the “Nonqualified Deferred Compensation” table.

Change in Pension Value and Nonqualified Deferred Compensation Earnings

The values in Column H represent the aggregate increase in the actuarial present value of benefits earned by each named executive officer during 2016, 2015 and 2014 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 2016, 2015, and 2014; 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, 2015 to December 31, 2016; from December 31, 2014 to December 31, 2015; and from December 31, 2013 to December 31, 2014 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 H 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 Leadership Development and Compensation Committee in conjunction with their annual tally sheet analysis. An explanation of why the Company uses SERP and its relationship to other compensation elements can be found in SERP.

Column H 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 2016, 2015 and 2014.

All Other Compensation

Payments made to or on behalf of our named executive officers in Column I, “All Other Compensation,” include the following:

• Contributions by Cleco under the 401(k) Savings Plan on behalf of the named executive officers;

• Term life insurance premiums paid for the benefit of the named executive officers;

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• For 2016, the cash payout of restricted shares settled at the closing in accordance with the terms of the Merger agreement;

• For 2016, 2015, and 2014, accumulated dividends paid for the LTIP three-year performance cycles ended December 31, 2015, December 31, 2014, and December 31, 2013, respectively, as well as dividends paid on restricted shares settled at the closing of the Merger;

• For 2016, for former executives, cash payout of vacation and floating holiday balances upon termination;

• For Mr. Williamson, the purchase of his secondary home in accordance with his employment agreement following the close of the Merger;

• For Messrs. Miller and Hoefling, the purchase of their primary homes in accordance with the Executive Severance Plan;

• For 2016, for former executives, cash severance payments; 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 I items for 2016 for each named executive officers is as follows:

	Mr. Olagues		Ms. Taylor		Mr. Bunting		Mr. Fontenot		Mr. Crump		Mr. Williamson		Mr. Miller		Ms. Miller		Mr. Hoefling
Cleco Contributions to 401(k) Savings Plan	$	9,233	$	8,748	$	9,762	$	10,600	$	8,451	$	15,900	$	7,587	$	5,280	$	4,890
Taxable Group Term Life Insurance		158		1,382		830		350		830		277		277		277		0
Merger Payout of Restricted Shares		708,127		188,258		208,025		309,574		309,574		3,697,387		371,422		359,074		359,074
Accumulated Dividends Paid on LTIP		72,738		18,582		20,801		30,287		36,540		363,784		30,721		41,269		35,732
Vacation Payout at Termination		0		0		0		0		0		55,402		19,812		19,915		16,854
Home Purchase		0		0		0		0		0		374,668		276,413		0		147,146
Severance Pay		0		0		0		0		0		2,970,000		357,676		389,506		391,340
FICA Tax on SERP		0		2,902		1,209		927		0		141,045		47,808		18,323		68,923
Total Other Compensation	$	790,256	$	219,872	$	240,627	$	351,738	$	355,395	$	7,618,463	$	1,111,716	$	833,644	$	1,023,959

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Grants of Plan-Based Awards

Name	Grant Date	Estimated Future Payments Under Non-Equity Incentive Plan Awards (PFP Plan)(2)						Estimated Future Payments Under Equity Incentive Plan Awards (LTIP)						All Other Stock Awards: Number of Shares of Stock or Units (#)		All Other Option Awards: Number of Securities Underlying Options (#)
		Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)
A	B	C		D		E		F		G		H		I		J
Mr. Olagues(1)		$	0	$	621,105	$	1,242,210	$	0	$	0	$	0	$	0	$	0
Ms. Taylor(1)		$	0	$	166,424	$	332,848	$	0	$	0	$	0	$	0	$	0
Mr. Bunting(1)		$	0	$	172,622	$	345,244	$	0	$	0	$	0	$	0	$	0
Mr. Fontenot(1)		$	0	$	228,761	$	457,522	$	0	$	0	$	0	$	0	$	0
Mr. Crump(1)		$	0	$	213,827	$	427,654	$	0	$	0	$	0	$	0	$	0
Mr. Williamson		$	0	$	745,000	$	1,490,000	$	0	$	0	$	0	$	0	$	0
Mr. Miller		$	0	$	154,500	$	309,000	$	0	$	0	$	0	$	0	$	0
Ms. Miller		$	0	$	149,350	$	298,700	$	0	$	0	$	0	$	0	$	0
Mr. Hoefling		$	0	$	149,350	$	298,700	$	0	$	0	$	0	$	0	$	0

(1) Targets based on salary following mid-year promotions related to the Merger.

(2) For current named executives, includes target awards for the Retention Bonus Plan.

General

The target values for each of the Company’s incentive plans—PFP Plan and LTIP—are determined as part of the Leadership Development and Compensation Committee’s review of executive officer compensation. The Leadership Development and 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 “The Executive Compensation Process” in the CD&A. Targets for both the PFP Plan 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 (PFP Plan)

See “Decisions Made in 2016 with Regard to Each Compensation and Benefit Component—Annual Cash Incentive” in the CD&A for a discussion of our 2016 PFP Plan award calculations.

Estimated Future Payments under Equity Incentive Plan Awards (LTIP)

There were no awards made under the LTIP in 2016.

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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. Olagues	Cleco Corporation Pension Plan		9	$	294,930	$	0
	Cleco Corporation SERP		9	$	3,362,775	$	0
Ms. Taylor	Cleco Corporation Pension Plan		16	$	1,029,315	$	0
	Cleco Corporation SERP		16	$	1,804,179	$	0
Mr. Bunting	Cleco Corporation Pension Plan		24	$	1,280,677	$	0
	Cleco Corporation SERP		24	$	1,865,252	$	0
Mr. Fontenot	Cleco Corporation Pension Plan		30	$	1,346,143	$	0
	Cleco Corporation SERP		30	$	1,617,632	$	0
Mr. Crump	Cleco Corporation Pension Plan		27	$	1,292,427	$	0
	Cleco Corporation SERP		27	$	1,702,314	$	0
Mr. Williamson	Cleco Corporation Pension Plan		4	$	0	$	0
	Cleco Corporation SERP		4	$	14,373,547	$	545,052
Mr. Miller	Cleco Corporation Pension Plan		3	$	0	$	0
	Cleco Corporation SERP		3	$	2,508,964	$	105,455
Ms. Miller	Cleco Corporation Pension Plan		31	$	1,766,209	$	68,758
	Cleco Corporation SERP		31	$	2,801,716	$	108,954
Mr. Hoefling	Cleco Corporation Pension Plan		9	$	520,148	$	23,997
	Cleco Corporation SERP		9	$	3,760,159	$	173,474

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. Williamson and Mr. Miller, each of the named executive officers is fully vested in the Pension Plan. Mr. Williamson and Mr. Miller, both having been hired after August 1, 2007, were not eligible to participate in the Pension Plan and were included in an enhanced 401(k) Savings Plan for those employees hired on or after August 1, 2007.

Vesting in SERP requires ten years of service. As a condition of his employment, Mr. Williamson was subject to a shorter vesting period in SERP, vesting in four years. Under the terms of SERP, automatic vesting occurs upon a Change in Control if a participating executive is involuntarily terminated from the Company. Mr. Miller and Mr. Hoefling received accelerated vesting upon their separation from the Company. Mr. Williamson and Ms. Miller were fully vested in SERP at the time of their separations. Mr. Olagues is the only named executive officer who is not fully vested in 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, 2016. These calculations were made using the projected unit credit method for valuation purposes and a discount rate of 4.27%. Other material assumptions relating to the valuation include use of the RP-2006 Employee and Healthy Annuitant gender distinct mortality tables projected generationally using Scale MP-2016, assumed retirement at age 65 and retirement payments in the form of joint and 100% survivor with 10 years certain payment, with the exception of Mr. Miller and Mr. Hoefling whose benefits are payable as a 10-year certain and life annuity.

The sum of the change in actuarial value of the Pension Plan during 2016 and the change in value of SERP is included in Column H, “Change in Pension Value and Nonqualified Deferred Compensation Earnings,” in the Summary Compensation Table. Negative changes, if any, are reported as zero.

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Pension Plan

The Cleco Corporation Pension Plan, restated effective August 1, 2015, is a defined benefit plan funded entirely by employer contributions. Effective August 1, 2007, the Pension Plan was closed to new participants. Employees hired on or after August 1, 2007 are eligible to participate in an enhanced 401(k) Savings Plan. With the exception of Mr. Williamson and Mr. Miller, each of our named executives was hired prior to August 1, 2007.

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) Savings 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 2016, the amount of earnings was further limited to $265,000 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 2016, 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 $210,000 in 2016. 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 PFP Plan 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 our 401(k) Savings Plan and/or is eligible to receive retirement-type payments from former employers and

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subsequent employers, if applicable. Messrs. Olagues, Williamson, Miller, and Hoefling will receive reduced payments from SERP because of retirement-type payments to be received from former employers.

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 PFP 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 PFP 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 three current participants including Mr. Olagues. With regard to other current SERP participants, including 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, 2016. Amounts shown for former executives reflect actual payments.

	Estimated Payments at Age 55 (or actual attained age if greater than 55)
	Pension		SERP		Total
Mr. Olagues	$	27,120	$	217,200	$	244,320
Ms. Taylor	$	59,448	$	118,044	$	177,492
Mr. Bunting	$	76,884	$	88,776	$	165,660
Mr. Fontenot	$	90,084	$	60,012	$	150,096
Mr. Crump(1)	$	78,935	$	132,677	$	211,612
Mr. Williamson(2)	$	0	$	817,577	$	817,577
Mr. Miller(2)	$	0	$	158,183	$	158,183
Ms. Miller(2)	$	103,137	$	163,432	$	266,569
Mr. Hoefling(2)	$	35,995	$	260,211	$	296,206

(1) Mr. Crump retired from the Company on December 31, 2016. The amounts reflected in the table represent actual payments to him beginning January 1, 2017.

(2) Payments for former executive named executive officers represent actual payments beginning May 1, 2016.

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Nonqualified Deferred Compensation

Name	Executive officer contributions in 2016 ($)(1)		Company contributions in 2016 ($)		Aggregate earnings in 2016 ($)(2)		Aggregate withdrawals/ distributions in 2016 ($)		Aggregate balance at December 31, 2016 ($)(3)
A	B		C		D		E		F
Mr. Olagues	$	0	$	0	$	0	$	0	$	0
Ms. Taylor	$	0	$	0	$	0	$	0	$	0
Mr. Bunting	$	0	$	0	$	0	$	0	$	0
Mr. Fontenot	$	9,151	$	9,151	$	72,766	$	0	$	807,525
Mr. Crump	$	0	$	0	$	0	$	0	$	0
Mr. Williamson	$	0	$	0	$	0	$	0	$	0
Mr. Miller	$	0	$	0	$	0	$	0	$	0
Ms. Miller	$	1,731	$	1,731	$	6,676	$	12,391	$	115,713
Mr. Hoefling	$	41,450	$	41,450	$	109,644	$	0	$	1,337,997

(1) The amounts in Column B represent deferrals of salary and non-equity incentive compensation payments made to the named executive officers during 2016 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 and Ms. Miller elected to participate in the Deferred Compensation Plan during 2016. Deferrals made by Mr. Hoefling relate to a 2015 election to defer receipt of his 2015 PFP bonus which was partially paid in 2015 and partially paid in 2016. All deferral elections for 2016 were made prior to the beginning of 2016 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 performance of notional investment alternatives, which are similar to the investments available under the 401(k) Savings 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, 2016: termination by the executive; disability; death; retirement; constructive termination; termination by the Company for cause; and termination in connection with a change in

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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) Savings 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 PFP Plan, LTIP, and SERP.

At its October 2011 meeting, the Compensation Committee approved the Executive Severance Plan to provide severance benefits to executive officers. In October and December 2014 and July 2015, the Compensation Committee approved amendments to the Executive Severance Plan. At December 31, 2016, all of the named executive officers, other than the former 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 PFP Plan 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 PFP Plan 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.

Retirement

In the event of early or normal retirement, the executive officer is eligible to receive a prorated share of the current year’s PFP Plan award and a prorated award for each LTIP performance cycle in which he/she

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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 PFP Plan 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) 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 or reckless violation of the material provisions of Cleco’s Code of Conduct; or (vii) willful or reckless 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 terms of the Williamson Agreement or 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” was defined in the LTIP. One or more of the following triggering events constitute a Change in Control:

• An event involving the Company of a nature that the Company would be required to report in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Exchange Act;

• Any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), other than the Company or any “person” who is a director or officer 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), directly or indirectly, of securities of the Company representing 20% or more of the combined voting power of the Company’s then outstanding securities;

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• During any period of 24 consecutive months, individuals who at the beginning of such period constitute the board of directors cease for any reason to constitute at least a majority thereof, unless the election of each director who was not a director at the beginning of such period shall have been approved in advance by directors representing at least 80% of the directors then in office who were directors at the beginning of such period;

• The Company shall be party to a merger or consolidation with another corporation and, as a result of such transaction, less than 80% of the then outstanding voting securities of the surviving or resulting corporation shall be owned in the aggregate by the former shareholders of the Company other than “affiliates” (as such term is defined in Rule 405 promulgated under the Securities Act of 1933, as amended) of any party to such transaction, as the same shall have existed immediately before such transaction;

• 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 shareholders 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 are sold, leased or otherwise disposed of in one or a series of related transactions to a person, other than the Company or another 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 (commonly referred to as a “double-trigger” design).

Termination must be involuntary and by the Company without cause or initiated by the executive on account of “Good Reason.” The term “Good Reason” means that the named executive officer (i) suffers a significant reduction in base compensation or a significant reduction in other benefits; (ii) experiences a significant reduction in authority, job duties and responsibilities; (iii) is required to be away from his/her office significantly more in order to perform his/her job duties; or (iv) experiences a change in job location of more than 60 miles. “Good Reason” may not be initiated by the executive based on the fact that the Company is no longer publicly traded. No event or condition will constitute “Good Reason” unless (a) the named executive officer gives the Company written notice of his/her objection to such event or condition within 60 days after he/she first learns of it, (b) such event or condition is not promptly corrected by the Company, but in no event later than 30 days after receipt of such notice, and (c) the executive resigns his/her employment with the Company not more than 60 days following the expiration of the 30-day period described in subparagraph (b). 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 “double-trigger” 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.

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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, 2016. 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 PFP Plan and LTIP for disability, death, retirement and constructive termination are uncertain until the completion of the performance period/cycle. In the case of the PFP Plan, the performance period is the current fiscal year. The estimated payment for the home purchase and relocation is a projection of the expense 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 relocate the named executive officer.

Pursuant to Item 401(j) of Regulation S-K, the separation events disclosed herein are assumed to occur in the past, as of December 31, 2016.

Mr. Olagues

Value of Payment/Benefit	Termination by Executive		Disability		Death		Retirement		Constructive Termination		Termination for Cause		Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	550,000	$	0	$	1,605,086
Annual Cash Bonus		0		467,631		467,631		467,631		467,631		0		0
Cash Payment in Lieu of Outplacement Services		0		0		0		0		50,000		0		0
Present Value of Incremental SERP Payments		0		6,548,700		4,336,163		0		0		0		3,380,296
SERP Supplemental Death Benefit		0		0		1,332,044		0		0		0		0
Purchase of Principal Residence/Relocation		0		0		0		0		0		0		83,500
COBRA Medical Coverage		0		0		0		0		18,213		0		24,285
Total Incremental Value	$	0	$	7,016,331	$	6,135,838	$	467,631	$	1,085,844	$	0	$	5,093,167

Ms. Taylor

Value of Payment/Benefit	Termination by Executive		Disability		Death		Retirement		Constructive Termination		Termination for Cause			Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	230,000	$	0		$	610,722
Annual Cash Bonus		0		122,603		122,603		122,603		122,603		0			0
Cash Payment in Lieu of Outplacement Services		0		0		0		0		25,000		0			0
Present Value of Incremental SERP Payments(1)		0		199,551		779,097		0		0		(1,962,417	)		415,070
SERP Supplemental Death Benefit		0		0		525,722		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		12,031		0			16,042
Total Incremental Value	$	0	$	322,154	$	1,427,422	$	122,603	$	389,634	$	(1,962,417	)	$	1,125,334

(1) As of December 31, 2016, Ms. Taylor was vested in SERP payments, which would be forfeited upon termination for cause.

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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	$	230,000	$	0		$	637,398
Annual Cash Bonus		0		136,194		136,194		136,194		136,194		0			0
Cash Payment in Lieu of Outplacement Services		0		0		0		0		25,000		0			0
Present Value of Incremental SERP Payments(1)		0		425,990		1,036,506		0		0		(1,660,563	)		484,251
SERP Supplemental Death Benefit		0		0		541,505		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		15,255		0			20,340
Total Incremental Value	$	0	$	562,184	$	1,714,205	$	136,194	$	406,449	$	(1,660,563	)	$	1,225,489

(1) As of December 31, 2016, Mr. Bunting was vested in SERP payments, which would be forfeited upon termination for cause.

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	$	290,000	$	0		$	826,744
Annual Cash Bonus		0		184,884		184,884		184,884		184,884		0			0
Cash Payment in Lieu of Outplacement Services		0		0		0		0		25,000		0			0
Present Value of Incremental SERP Payments(1)		0		1,462,257		1,508,060		0		0		(1,061,426	)		1,211,219
SERP Supplemental Death Benefit		0		0		699,063		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		13,341		0			17,788
Total Incremental Value	$	0	$	1,647,141	$	2,392,007	$	184,884	$	513,225	$	(1,061,426	)	$	2,139,251

(1) As of December 31, 2016, Mr. Fontenot was vested in SERP payments, which would be forfeited upon termination for cause.

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Mr. Crump

Value of Payment/Benefit	Termination by Executive		Disability		Death		Retirement		Constructive Termination		Termination for Cause			Change in Control
Cash Severance	$	0	$	0	$	0	$	0	$	257,500	$	0		$	764,624
Annual Cash Bonus		0		213,827		213,827		213,827		213,827		0			0
Cash Payment in Lieu of Outplacement Services		0		0		0		0		25,000		0			0
Present Value of Incremental SERP Payments(1)		0		510,120		1,130,931		0		0		(2,049,675	)		592,903
SERP Supplemental Death Benefit		0		0		643,750		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		18,213		0			24,285
Total Incremental Value	$	0	$	723,947	$	1,988,508	$	213,827	$	514,540	$	(2,049,675	)	$	1,465,312

(1) As of December 31, 2016, Mr. Crump was vested in SERP payments, which would be forfeited upon termination for cause.

DIRECTOR COMPENSATION

2016 Director Compensation

Name(1)	Fees Earned or Paid in Cash and/ or Stock ($)		Stock Awards ($)(2)		Option Awards ($)(3)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)		All Other Compensation ($)		Total ($)
A	B		C		D		E		F		G		H
Vicky A. Bailey	$	96,429	$	0	$	0	$	0	$	0	$	0	$	96,429
Rick Gallot	$	92,857	$	0	$	0	$	0	$	0	$	0	$	92,857
Randy Gilchrist	$	92,857	$	0	$	0	$	0	$	0	$	0	$	92,857
Elton R. King	$	99,286	$	0	$	0	$	0	$	0	$	2,084	$	101,370
Logan W. Kruger	$	99,286	$	0	$	0	$	0	$	0	$	2,084	$	101,370
William L. Marks	$	102,143	$	0	$	0	$	0	$	0	$	2,084	$	104,227
Peggy Scott	$	135,307	$	0	$	0	$	0	$	0	$	0	$	135,307
Peter M. Scott III	$	100,000	$	0	$	0	$	0	$	0	$	2,084	$	102,084
Melissa Stark	$	3,750	$	0	$	0	$	0	$	0	$	0	$	3,750
Shelley Stewart, Jr.	$	99,286	$	0	$	0	$	0	$	0	$	2,084	$	101,370
Bruce Wainer	$	92,857	$	0	$	0	$	0	$	0	$	0	$	92,857
William H. Walker, Jr.	$	96,429	$	0	$	0	$	0	$	0	$	2,241	$	98,670

(1) Mr. Olagues was also a named executive officer and his compensation is included in the Compensation-Summary Compensation Table. He did not receive any additional compensation for his service on the boards. Messrs. Agnew, Chapman, Dinneny, Fay, Kendircioglu, Leslie, Turner and Webb were appointed to the boards by the Owner Group and do not receive additional compensation for their service on the boards.

(2) There were no stock awards in 2016. There were no shares of Cleco Corporation common stock awarded under the LTIP that were restricted as of December 31, 2016.

(3) No stock options were granted to directors in 2016. There were no option awards held by directors and outstanding as of December 31, 2016.

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General

Column B, “Fees Earned or Paid in Cash and/or Stock;” Column E, “Non-Equity Incentive Plan Compensation;” and Column G, “All Other Compensation” represent cash compensation earned and/or received in 2016.

A non-management director 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 director’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) Savings Plan. Funds may be reallocated between investments at the discretion of the director. 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 director ceases to serve on the board of directors or attains a specified age.

Fees Earned or Paid in Cash and/or Stock

Directors who are Cleco employees or who are appointed to Cleco’s board by the Owner Group receive no additional compensation for serving as a director. In 2016, compensation for non-management and for non-Owner Group appointed directors included annual retainer fees and insurance benefits under a group accidental death and dismemberment plan.

Prior to the Merger date, each non-management director received an annual cash retainer of $75,000 and an additional annual cash fee of $10,000 if the director was a chair of a committee other than the Audit Committee. The chair of the Audit Committee received an additional fee of $12,500. The lead director received an additional cash retainer in the amount of $20,000. As explained under “Stock Awards,” prior to 2016, each non-management director also received an annual award of Cleco Corporation common stock valued at $75,000. Pursuant to the terms of the Merger Agreement, this award was not made in 2016 and, instead, each non-management director received an additional cash payment of $75,000.

After the Merger date, each manager who is not a Cleco employee or appointed by the Owner Group, except Ms. Stark, receives an annual cash retainer of $130,000. Ms. Stark receives an annual cash retainer of $3,750. Each committee chair who is not a Cleco employee or appointed by the Owner Group receives an additional annual retainer of $20,000, and the non-management chair of the boards receives an additional annual retainer of $50,000.

Directors are permitted to defer receipt of their fees under the Company’s Deferred Compensation Plan. Prior to 2014, Mr. Walker made elections to defer his fees. The amounts of dividends credited to his deferred fees account balance in 2016, with respect to Cleco common stock held in the Company’s Deferred Compensation Plan, was $8,420. Messrs. Gallot and Gilchrist elected to defer all or a portion of their fees in 2016.

Cleco reimburses directors for travel and related expenses incurred for attending meetings of Cleco’s board of directors and board committees, including travel costs for spouses/companions.

Stock Awards

Prior to 2016, each non-management director received an annual stock award of Cleco Corporation common stock valued at $75,000, not to exceed 10,000 shares of stock. The grant date of the annual stock award was the date of the January board meeting each year, and the valuation date of the stock was the first trading day of the year. Directors were not required to provide any consideration in exchange for the annual stock award. Pursuant to the terms of the Merger Agreement, this stock award was not made to directors in 2016.

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Option Awards

Amounts in Column D, “Option Awards,” would reflect grants made to the Company’s directors, providing them the opportunity to purchase shares of Cleco Corporation common stock at some future date at the fair market value of the stock on the date of the grant. No stock options were granted to directors in 2016, and Cleco’s common stock was eliminated when the Merged closed in April 2016.

Non-Equity Incentive Plan Compensation

There were no non-equity incentive plan awards to the Company’s directors in 2016.

Change in Pension Value and Nonqualified Deferred Compensation Earnings

Column F 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 2015. Cleco does not provide its directors with a pension plan.

All Other Compensation

Column G, “All Other Compensation,” includes the following:

• Dividends paid on any restricted stock awards granted under the LTIP and not yet vested. Prior to the Merger date, dividends on restricted stock were paid quarterly and at the same rate as dividends on shares of Cleco Corporation common stock. Dividends were paid in cash or reinvested in additional shares, at the election of each director. This column also includes dividends paid on deferred restricted stock awards. Dividends on deferred restricted shares of Cleco Corporation common stock were not paid in cash, but instead were credited as units to the director’s deferred compensation account. The value of dividends credited in 2016 is reflected in the “Deferred Units on Deferred Restricted Stock” column below.

• Expenses incurred for spousal/companion travel on Cleco business.

The values of the two “All Other Compensation” items are summarized in the chart that follows:

Name	Dividends on Restricted Stock		Deferred Units on Deferred Restricted Stock		Spousal/ Companion Travel		Total Other Compensation
Mr. King	$	2,084	$	0	$	0	$	2,084
Mr. Kruger	$	2,084	$	0	$	0	$	2,084
Mr. Marks	$	2,084	$	0	$	0	$	2,084
Mr. Scott	$	2,084	$	0	$	0	$	2,084
Mr. Stewart	$	2,084	$	0	$	0	$	2,084
Mr. Walker	$	0	$	2,084	$	157	$	2,241

Cleco also provides its directors who are not employed by Cleco or appointed by the Owner 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 2016 premium for all coverage (exempt employees, officers and directors) under this plan was $16,573.

Vesting of Cleco Common Stock

Under the terms of the Merger Agreement, each unvested share of restricted stock granted pursuant to any equity incentive plan or arrangement of Cleco Corporation became vested in full and was converted into the right to receive a payment in cash equal to $55.37 per share upon closing of the Merger. As a result of the Merger, the

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following unvested shares of restricted stock granted to members of Cleco Corporation’s board of directors prior to the Merger date became vested in full: Mr. King: 5,211; Mr. Kruger: 5,211; Mr. Marks: 5,211; Mr. Scott: 5,211; and Mr. Stewart: 5,211. Mr. Walker deferred his restricted stock awards, and restrictions on 10,027 deferred restricted units owned by him lapsed as a result of the Merger.

Interests of the Board of Directors

In 2016, no non-management member of Cleco’s board 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 board.

Report of the Leadership Development and Compensation Committee

The Leadership Development and Compensation Committee of the boards of managers (see “Boards of Managers of Cleco” above and “Director Independence and Related Party Transactions” below), includes five managers, one of whom meet 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 August 2016, a copy of which is posted on Cleco’s web site at 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 constituted following the closing of the Merger in April 2016. The Committee is directly responsible for (i) evaluating and establishing Cleco’s compensation and benefits philosophy as it relates to officers and other key employees; (ii) establishing associated compensation and benefit plans and compensation and benefits levels of Cleco’s officers and other key employees; (iii) retaining an independent consultant to advise the Leadership Development and Compensation Committee on executive officers’ compensation and benefit practices in Cleco’s industry and peer group comparisons; (iv) annually evaluating the performance of the CEO in light of Cleco’s goals and objectives; (v) reviewing the CD&A with management and approving its content; and (vi) annually evaluating its own performance.

The Leadership Development and Compensation Committee held five meetings following the closing of the Merger, three of which were telephonic meetings, at which the above listed responsibilities were addressed. During each of its meetings, the Leadership Development and Compensation Committee also met with its third-party consultant independent of management.

Based on the review and discussions referred to above, the Leadership Development and Compensation Committee recommended to the Company’s Boards of Managers that the CD&A (including the “Pre-Merger Compensation Discussion and Analysis”) and related required compensation disclosure tables be included in the Company’s 2016 Form 10-K and filed with the SEC.

The Leadership Development and Compensation Committee of the Boards of Managers of Cleco Group, Cleco Holdings and Cleco Power

Christopher Leslie, Chair

Andrew Chapman

Rick Gallot

Lincoln Webb

Compensation Committee Interlocks and Insider Participation

The members of the Leadership Development and Compensation Committee are set forth above. There are no matters relating to interlocks or insider participation of the Leadership Development and Compensation Committee members that Cleco is required to report.

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PRINCIPAL OWNERS

Security Ownership of Directors and Management and Certain Beneficial Owners

Upon the closing of the Merger on April 13, 2016, all shares of Cleco Corporation common stock were exchanged for consideration of $55.37 per share. Following the closing of the Merger, there are no longer any outstanding shares of Cleco Corporation common stock.

Equity Compensation Plan Information

As a result of the completion of the Merger on April 13, 2016, all compensation plans under which equity securities of Cleco Corporation were authorized for issuance were terminated. For more information on compensation plans using equity securities, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 8—Common Stock.” For more information about the Merger, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 3—Business Combinations.” This information should be read in conjunction with the Consolidated Financial Statements and related Notes thereto.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Related Party Transaction Approval Policy

The board has adopted a written Conflicts of Interest and Related Policies to prohibit certain conduct and to reflect the expectation of the board that its 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 board for a final determination.

Indemnification Agreements

Cleco indemnifies each of the current and former directors, managers, officers and employees of Cleco or our subsidiaries to the fullest extent permitted by applicable law against costs or expenses (including reasonable attorneys’ fees) incurred in connection with claims, whether asserted before or after the Merger, arising out of or related to such person’s service as one of our directors, officers or employees or as a director, officer or employee of one of our subsidiaries. For a period of six years following the Merger, we will maintain in effect the director, officer and employee exculpation, indemnification and advancement of expenses provisions in our and our subsidiaries’ organizational documents.

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THE EXCHANGE OFFER

Purpose and Effect of Exchange Offer

We sold the Outstanding Notes on May 17, 2016 in an unregistered private placement to certain initial purchasers. As part of that 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. This exchange offer satisfies that obligation. We also agreed to perform other obligations under that 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 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;

• 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

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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 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 this 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 $885.0 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 these 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, $885.0 million in aggregate principal amount of the Outstanding Notes were outstanding. Outstanding Notes accepted for exchange 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 for the purposes of receiving the Exchange Notes from us.

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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 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                 , 2017. We may extend this expiration date in our sole discretion, but in no event to a date later than                 , 2017, 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 to the exchange agent. 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 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 2026 Exchange Notes will accrue at the rate of 3.743% per annum on the principal amount and on the 2046 Exchange Notes at a rate of 4.973% per annum on the principal amount, payable semiannually on May 1 and November 1, with the next payment due on May 1, 2017. Interest on the Exchange Notes will accrue from the date of the last periodic payment of interest on such Outstanding Notes.

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Conditions to the Exchange Offer

Despite any other term of the exchange offer, we will not be required to accept for exchange, or 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.

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; 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 may differ from the terms of the exchange offer. Those purchases may require the consent of the lenders under our Senior Secured 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

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• 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; or

• the holder must comply with the guaranteed delivery procedures described below.

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.

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.

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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 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.

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.

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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

The following guaranteed delivery procedures are intended for holders who wish to tender their Outstanding Notes but:

• their Outstanding Notes are not immediately available;

• the holders cannot deliver their Outstanding Notes, the letter of transmittal, or any other required documents to the exchange agent prior to the expiration date; or

• the holders cannot complete the procedure under the respective DTC, Euroclear or Clearstream standard operating procedures for electronic tenders before expiration of the exchange offer.

The conditions that must be met to tender Outstanding Notes through the guaranteed delivery procedures are as follows:

• the tender must be made through an eligible institution;

• before expiration of the exchange offer, the exchange agent must receive from the eligible institution either a properly completed and duly executed notice of guaranteed delivery in the form accompanying this prospectus, by facsimile transmission, mail or hand delivery, or a properly transmitted agent’s message in lieu of notice of guaranteed delivery:

• setting forth the name and address of the holder, the certificate number or numbers of the Outstanding Notes tendered and the principal amount of Outstanding Notes tendered;

• stating that the tender offer is being made by guaranteed delivery;

• guaranteeing that, within three New York Stock Exchange trading days after expiration of the exchange offer, the letter of transmittal, or facsimile of the letter of transmittal, together with the Outstanding Notes tendered or a book-entry confirmation, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the exchange agent must receive the properly completed and executed letter of transmittal, or facsimile of the letter of transmittal, as well as all tendered Outstanding Notes in proper form for transfer or a book-entry confirmation, and any other documents required by the letter of transmittal, within three New York Stock Exchange trading days after expiration of the exchange offer; and

• upon request to the exchange agent, a notice of guaranteed delivery will be sent to holders who wish to tender their Outstanding Notes according to the guaranteed delivery procedures set forth above.

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.

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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 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; or

• 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;

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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

We will issue the Exchange Notes in exchange for Outstanding Notes under 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

• 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 CERTAIN OTHER INDEBTEDNESS

The following is a description of our material indebtedness, other than the Outstanding Notes. The terms of the Outstanding Notes are substantially identical to the terms of the Exchange Notes. See “Description of Exchange Notes.” The following summaries are qualified in their entirety by reference to the credit and security agreements and indentures to which each summary relates, which are included in the registration statement of which this prospectus is a part.

Cleco

Senior Secured Credit Facilities

In connection with the closing of the Merger, we entered into the Senior Secured Credit Facilities comprised of (i) the Revolving Credit Facility and (ii) the Acquisition Loan Facility, which was subsequently refinanced.

The Revolving Credit Facility is secured on a pari passu basis by the Collateral. The Collateral consists principally of 100% of the limited liability company membership interests in Cleco Power LLC and all indebtedness owed by Cleco Power to Issuer from time to time, which interests were secured and perfected on the closing date of the Merger. The borrowings under the Revolving Credit Facility are considered to be long-term because it expires in 2021. The Revolving Credit Facility carries commitment fees which range from .225% to ..400% depending on Cleco’s applicable credit ratings. As of December 31, 2016, our borrowings under the Revolving Credit Facility were zero and the unused availability was $100.0 million.

3.250% Senior Notes

On May 24, 2016, we completed the private sale of $165.0 million in aggregate principal amount of 3.250% Senior Notes.

The 3.250% Senior Notes are our senior secured obligations and rank equally with all of our existing and future senior indebtedness, but, to the extent of the value of the Collateral securing the 3.250% Senior Notes, will be effectively senior to all of our unsecured senior indebtedness. The 3.250% Senior Notes are also senior to all of our existing and future subordinated debt. The 3.250% Senior Notes are structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of our subsidiaries, including Cleco Power.

The 3.250% Senior Notes are secured on a pari passu basis by the Collateral until the Collateral Release Date. From and after the Collateral Release Date, the 3.250% Senior Notes will become unsecured and will rank equally with all of our other unsecured senior indebtedness.

We may redeem the 3.250% Senior Notes, in whole or in part, at any time prior to April 1, 2023, at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus the “make-whole” premium set forth in the indenture governing the 3.250% Senior Notes. We may redeem the 3.250% Senior Notes, in whole or in part, at any time on or after April 1, 2023, at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. If we experience certain change of control events, holders of the 3.250% Senior Notes may require it to repurchase all or part of their 3.250% Senior Notes at 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the repurchase date.

The indenture governing the 3.250% Senior Notes contains restrictive 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.

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The obligations to pay the principal of, premium, if any, and interest on the 3.250% Senior Notes are solely our obligations, and none of our subsidiaries or affiliates will guarantee or provide any credit support for the 3.250% Senior Notes.

Term Loan

On June 28, 2016, we entered the Term Loan, a $300.0 million variable rate bank term loan due June 28, 2021. Amounts outstanding under the Term Loan bear interest, at our option, at a base rate plus 0.625% or LIBOR plus 1.625%. At December 31, 2016, the all-in rate was 2.265%, which was based on the LIBOR rate. Under the Term Loan, we are required to maintain (on a consolidated basis) a percentage of debt to total capitalization at a level that does not exceed 65%. The Term Loan is secured on a pari passu basis by the Collateral.

Cleco Power

The Outstanding Notes are structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of our subsidiaries, including Cleco Power.

OpCo Revolver

In connection with the consummation of the Merger, Cleco Power terminated its amended and restated revolving credit facility and entered into a five-year senior unsecured revolving credit facility of up to $300 million, which we refer to herein as the OpCo Revolver. The borrowings under the OpCo Revolver are considered to be long-term because it expires in 2021. The borrowing costs under the OpCo Revolver are equal to eurodollar rate plus a margin which ranges from 1.00% to 2.00% or prime rate plus a margin which ranges from 0.00% to 1.00%, plus commitment fees ranging from 0.10% to 0.35%, in each case with such margins or fees based on Cleco Power LLC’s credit ratings.

LC Facility

In connection with the termination of Cleco Power’s existing revolving credit facility, Cleco Power entered into a separate arrangement to continue the $2.0 million letter of credit which was previously issued under such facility. We refer to this new arrangement as the LC Facility.

Debt Securities

As of December 31, 2016, Cleco Power had outstanding debt securities as follows:

Series	Due		Amount
			(in thousands)
3.68% Senior Notes		2025	$	75,000
3.47% Senior Notes		2026		130,000
4.33% Senior Notes		2027		50,000
3.57% Senior Notes		2028		200,000
6.50% Senior Notes		2035		295,000
6.00% Senior Notes		2040		250,000
5.12% Senior Notes		2041		100,000
2.00% Series A GO Zone Bonds		2038		50,000
4.25% Series B GO Zone Bonds		2038		50,000
4.41% Katrina/Rita’s Storm Recovery Bonds		2020		1,115
5.61% Katrina/Rita’s Storm Recovery Bonds		2023		67,600
Total Debt Securities			$	1,268,715

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DESCRIPTION OF THE EXCHANGE NOTES

General

The Exchange Notes, which are referred to in this section as the “Notes”, will be issued under the indenture dated as of May 17, 2016, between us and Wells Fargo Bank, N.A., as trustee (the “Trustee”), and the first supplemental indenture and the second supplemental indenture thereto, dated as of May 17, 2016. We refer to the indenture and the first supplemental indenture and the second supplemental indenture, together, as the “Indenture.” The terms of the Notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”). In the discussion that follows, “the Issuer,” “we,” “us” and “our” refer only to Cleco Corporate Holdings LLC, a Louisiana limited liability company (f/k/a Cleco Corporation), and not to OpCo or any subsidiary of ours. References to paying principal on the Notes are to payment at maturity or redemption. Definitions of certain defined terms used in this “Description of the Exchange Notes” section, but not defined below, have the meanings assigned to them under “—Definitions.”

The following description is only a summary of the material provisions of the Indenture and the Notes, does not purport to be complete and is qualified in its entirety by reference to the provisions of the Indenture and the Notes, including the definitions therein of certain terms used below. Because this is a summary, it may not contain all the information that is important to you. We urge you to read the Indenture and the Notes because they, and not this description, will define your rights as Holders of the Notes. You may request copies of the proposed form of the Indenture and the Notes as described under “Where You Can Find More Information.”

Until the Collateral Release Date, the Notes will be our senior secured obligations and will:

• rankpari passuin right of payment to all of our existing and future senior Indebtedness, but to the extent of the value of the Collateral securing the Notes, will be effectively senior to all of our unsecured senior Indebtedness (as of the date hereof, our obligations under the 3.250% Senior Notes and the Term Loan constitute our only other outstanding senior secured Indebtedness);

• be senior in right of payment to any of our future subordinated Indebtedness; and

• be structurally subordinated to all existing and future Indebtedness and other liabilities (including trade payables) of our subsidiaries, including Cleco Power LLC, a Louisiana limited liability company (“OpCo”).

Except as described below under “—Material Covenants—Limitations on Liens,” the indenture does not limit our ability to incur other Indebtedness or to issue other securities, including other series of debt securities.

The Notes will be denominated in U.S. dollars and principal and interest will be paid in U.S. dollars. We will issue the Notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof. The Notes will not be subject to any conversion, amortization or sinking fund. You will not have the right to require us to redeem or repurchase the Notes at your option.

The obligations to pay the principal of, premium, if any, and interest on the Notes are solely our obligations, and the Notes will not be guaranteed by, or otherwise be obligations of (and credit support will not be provided for such obligations by), our parent company, any of its direct or indirect subsidiaries (other than us), the members of the consortium that indirectly own our parent company, or any of our affiliates.

Because we are a holding company, our rights and the rights of our creditors, including Holders of the Notes, in respect of claims on the assets of OpCo upon any liquidation or administration will be structurally subordinated to, and therefore will be subject to the prior claims of, OpCo’s creditors (including trade creditors of and Holders of debt issued by OpCo). As of December 31, 2016, OpCo had total long-term debt and current liabilities of approximately $1,456.1 million. In addition, OpCo also has a $300.0 million revolving credit facility that may be drawn by OpCo from time to time. All OpCo’s existing liabilities, including all amounts outstanding under its revolving credit facility, will be structurally senior to the Notes.

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Our ability to pay interest on the Notes will be dependent upon the receipt of dividends and other distributions from OpCo. The availability of distributions from OpCo is subject to the satisfaction of various covenants and conditions contained in OpCo’s existing and future financing documents.

Principal, Maturity and Interest

The Notes initially will be issued in an aggregate principal amount of $885 million, all rankingpari passuwith one another, consisting of:

• $535 million in aggregate principal amount of 3.743% Senior Secured Notes due 2026 (the “2026 Notes”); and

• $350 million in aggregate principal amount of 4.973% Senior Secured Notes due 2046 (the “2046 Notes”).

Interest on the 2026 Notes will accrue at a rate of 3.743% per annum. Interest on the 2046 Notes will accrue at a rate of 4.973% per annum.

Principal of the 2026 Notes will be payable at maturity on May 1, 2026. Principal of the 2046 Notes will be payable at maturity on May 1, 2046.

Interest will be payable on the Notes semiannually on May 1 and November 1 of each year, with the next payment due on May 1, 2017, until the principal is paid or made available for payment. Interest on the Notes will accrue from the most recent date to which interest has been paid. Payment of interest on the Notes will be made to the person or persons in whose name or names such Notes are registered at the close of business on the April 15 and October 15 immediately preceding the relevant interest payment date. Interest will be computed based on a 360-day year consisting of twelve 30-day months. If any date on which interest is payable on the Notes is not a business day, then payment of the interest payable on that date will be made on the next succeeding day which is a business day (and without any additional interest or other payment in respect of any delay), with the same force and effect as if made on such date. If there has been a default in the payment of interest on any Note, such defaulted interest may be payable to the Holder of such Note as of the close of business on a date selected by the Trustee which is not more than 30 days and not less than 10 days before the date proposed by the Issuer for payment of such defaulted interest or in any other lawful manner, if the Trustee deems such manner of payment practicable.

Payment of principal of the Notes will be made against surrender of such Notes at the corporate trust office of the Trustee, as paying agent for us. We may change the paying agent at our discretion. For so long as the Notes are issued in book-entry form, payments of principal and interest shall be made in immediately available funds by wire transfer to The Depository Trust Company (“DTC”), or its nominee.

To the extent permitted by applicable Governmental Rule, all amounts paid by us for the payment of principal, premium (if any) or interest on any Notes that remain unclaimed at the end of two years, or prior to the applicable escheat date, after such payment has become due and payable will be repaid to us and the Holders of such Notes will thereafter look only to us for payment thereof.

Form and Denomination; Registration and Transfer

The Notes will be issued in fully registered form only in denominations of $2,000 and integral multiples of $1,000 in excess thereof. We will initially issue the Notes in global book-entry form. So long as the Notes are in book-entry form, transfers and exchanges will be registered on the records of the depositary or its participants. If the Notes are issued in certificated form, Holders of Notes may register the transfer of Notes, and may exchange Notes for other Notes of the same series and tranche, of authorized denominations and having the same terms and aggregate principal amount, at the corporate trust office of the Trustee, as registrar for the Notes (in such capacity,

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the “Registrar”). We may change the place for registration of transfer and exchange of the Notes, may appoint one or more additional Registrars (including us) and may remove any Registrar, all at our discretion. No service charge will be made for any transfer or exchange of the Notes, but we may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of the Notes. We will not be required to execute or provide for the registration of transfer of or the exchange of (a) any Note during a period of 15 days before giving any notice of redemption or (b) any Note selected for redemption in whole or in part, except the unredeemed portion of any Note being redeemed in part. See “—Book-Entry; Delivery and Form.” The Issuer and its Affiliates may, at their discretion, at any time and from time to time, acquire Notes by means other than a redemption, whether by tender offer, open market purchases, negotiated transactions or otherwise.

Further Issuances

We may Incur Additional Senior Indebtedness in the form of additional senior notes under the Indenture from time to time, in one or more series (each, an “Additional Series of Notes” and each of the 2026 Notes, the 2046 Notes and each such Additional Series of Notes, a “series”), each in a principal amount authorized under the Indenture prior to issuance. The particular terms of an Additional Series of Notes will be determined at the time of issue. No Additional Series of Notes can be issued if an Event of Default under the Indenture has occurred and is continuing with respect to the Notes. Each series of Notes will rank equally in right of payment with each other series of Notes, regardless of the date of issuance. Unless the context otherwise requires, all references to the “Securities” and the “Notes” under the Indenture and to the “Notes” in this “Description of the Exchange Notes” include the Notes offered hereby and any Additional Series of Notes.

Additionally, we may from time to time, without the consent of the existing Holders of the Notes, “reopen” any series of Notes, which means we can create and issue further Notes of any series (any such Notes, “Additional Notes”) having the same terms and conditions as, and ranking equally with, the Notes of such series offered by this prospectus in all respects (except for the offering price and issue date);providedthat such Additional Notes are fungible with the previously issued and outstanding Notes for United States federal income tax purposes. Additional Notes will be consolidated with, and form a single series with, the previously outstanding Notes of such series for all purposes under the Indenture, including with respect to waivers, amendments, redemptions and offers to purchase. Unless the context otherwise requires, references to the “Securities” and the “Notes” for all purposes under the Indenture and to the “Notes” in this “Description of the Exchange Notes” include any Additional Notes.

Ranking

Until the Collateral Release Date, the Notes will be our senior secured obligations and will:

• rankpari passuin right of payment to all of our existing and future senior Indebtedness, but to the extent of the value of the Collateral securing the Notes, will be effectively senior to all of our unsecured senior Indebtedness (as of the date hereof, our obligations under the 3.250% Senior Notes and the Term Loan constitute our only other outstanding senior secured Indebtedness);

• be senior in right of payment to any of our future subordinated Indebtedness; and

• be structurally subordinated to all existing and future Indebtedness and other liabilities (including trade payables) of our subsidiaries, including OpCo.

On and after the Collateral Release Date, the Notes will be our senior unsecured obligations and will:

• rankpari passuin right of payment with all of our existing and future senior Indebtedness;

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

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• be senior in right of payment to any of our future subordinated Indebtedness; and

• be structurally subordinated to all existing and future Indebtedness and other liabilities (including trade payables) of our subsidiaries, including OpCo.

Because we are a holding company and substantially all of our operations will be conducted by our subsidiaries (principally OpCo), holders of our debt securities, including Holders of the Notes, will have a junior position to claims of creditors and certain security holders of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. To the extent that we may be a creditor with recognized claims against any of our subsidiaries, our claims would also effectively be subordinated to any security interest in, or mortgages or other liens on, the assets of our subsidiaries and would be subordinated to any Indebtedness or other liabilities of our subsidiaries senior to our interest. Certain of our operating subsidiaries, principally OpCo, have ongoing corporate debt programs used to finance their business activities. As of December 31, 2016, we had approximately $1,347.7 million of senior secured debt outstanding (including the Outstanding Notes) and a $100.0 million revolving credit facility that may be drawn by us from time to time. As of December 31, 2016, OpCo had approximately $1,254.8 million of outstanding debt and a $300.0 million revolving credit facility that may be drawn by OpCo from time to time. We and OpCo retain the ability to incur substantial additional Indebtedness and other liabilities. Moreover, our ability to pay principal and interest on the Notes is dependent upon the earnings of our subsidiaries and the distribution or other payments from our subsidiaries to us in the form of dividends, loans, advances or the repayment of loans and advances from us. The Indenture does not contain any limitation on our ability to incur additional debt or our subsidiaries’ ability to incur additional debt to us or to third parties.

No Guarantees or Credit Support

The obligations to pay the principal of, premium, if any, and interest on the Notes are solely our obligations, and the Notes will not be guaranteed by, or otherwise be obligations of (and credit support will not be provided for such obligations by), our parent company, any of its direct or indirect subsidiaries (other than us), the members of the consortium that indirectly own our parent company, or any of our affiliates. Because the Notes will not be guaranteed by our subsidiaries, the Notes will be structurally subordinated to all existing and future liabilities of our subsidiaries. See “—Ranking” above.

Security

General

Until the Collateral Release Date, the Notes will be secured by first priority Liens (subject to Permitted Liens) on the same assets that secure our other Secured Obligations, including our Indebtedness under the Credit Agreement, which assets will consist principally of the Pledged Debt and the Pledged Equity.

Under the terms of the Pari Passu Intercreditor Agreement, the Collateral securing the Notes will be shared equally and ratably (subject to Permitted Liens) with the liens securing other Secured Obligations, which includes the Indebtedness under the Credit Agreement, any Secured Hedge Obligations and any future Additional Senior Indebtedness Obligations. As of the Issue Date, our obligations under the Notes and our obligations under the Revolving Credit Facility, the Term Loan, and the 3.250% Senior Notes constituted all of our Secured Obligations.

Pursuant to the Indenture and the Security Documents, substantial additional Indebtedness may, without the consent of Holders, constitute Secured Obligations. We will also be able to incur additional Secured Obligations and other Indebtedness and obligations secured by Permitted Liens. The amount of such obligations could be significant. The existence of any Permitted Liens could adversely affect the value of the Collateral securing the Notes, as well as the ability of the Collateral Agent to realize or foreclose on such Collateral. The Holders’ rights to the Collateral would be diluted by any increase in the obligations secured by such Collateral.

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Sufficiency of Collateral

The Collateral has not been appraised in connection with this offering. The value of the Collateral and the amount to be received upon a sale of the Collateral will depend upon many factors including, among others, the condition of the electric transmission, distribution and generation and natural gas distribution industries, the ability to sell the Collateral in an orderly sale, the condition of the international, national and local economies, the availability of buyers and similar factors. The book value of the Collateral should not be relied on as a measure of realizable value for these assets.

After-acquired Collateral

From and after the Issue Date and subject to certain limitations and exceptions, if we acquire any property or asset that would constitute Collateral, pursuant to the terms of the Security Documents, Holders of the Notes will obtain a Lien (subject to Permitted Liens) upon such property or asset as security for the Notes. However, there can be no assurance that the Trustee or the Collateral Agent will monitor, or that we will inform the Trustee or the Collateral Agent of, the future acquisition of property and rights that constitute Collateral, and that the necessary actions will be taken to properly perfect the security interest in such after-acquired property. Neither the Trustee nor the Collateral Agent will have any duty to monitor the status of any Collateral or any future acquisition of property and rights that constitute Collateral, nor shall the Trustee or the Collateral Agent have any duty to properly perfect the security interests.

Foreclosure

Upon the occurrence and during the continuance of an Event of Default, the Pari Passu Intercreditor Agreement provides for (among other available remedies) the foreclosure upon and sale of the applicable Collateral by the Collateral Agent at the direction of the Required Secured Creditors, and the distribution of the net proceeds of any such sale to the holders of Secured Obligations, including the Holders, on a pro rata basis. In the event of foreclosure on the Collateral, the proceeds from the sale of the Collateral may not be sufficient to satisfy in full our obligations under the Notes. Pursuant to the Pari Passu Intercreditor Agreement, only the Collateral Agent, acting at the direction of the Required Secured Creditors may exercise remedies with respect to the Liens securing Secured Obligations. Accordingly, the Holders may not ever have the right to control the remedies and the taking of other actions related to the Collateral.

Regulatory considerations may affect the ability of the Collateral Agent to exercise certain rights with respect to the Pledged Debt and the Pledged Equity upon the occurrence of an Event of Default. Because OpCo is a regulated public utility, such foreclosure proceedings, the enforcement of the Security Documents and the right to take other actions with respect to the Pledged Debt and the Pledged Equity may be limited and subject to regulatory approval. OpCo is subject to regulation at the state level by the LPSC. At the federal level, it is subject to regulation by the FERC. Regulation by the LPSC and the FERC includes regulation with respect to the change of control, transfer or ownership of utility property. In particular, such foreclosure proceedings, the enforcement of the Pledge Agreement and the right to take other actions or exercise other remedies with respect to the Pledged Debt and the Pledged Equity could require prior approval by the FERC and/or the LPSC. There can be no assurance that any such regulatory approval can be obtained on a timely basis, or at all.

Certain bankruptcy limitations

The right and ability of the Collateral Agent to repossess and dispose of the Collateral upon the occurrence of an Event of Default would be significantly impaired by applicable bankruptcy law in the event that a bankruptcy case were to be commenced by or against us or OpCo prior to the Collateral Agent having repossessed and disposed of the Collateral. Upon the commencement of a case for relief under the U.S. Bankruptcy Code, a secured creditor such as the Collateral Agent is prohibited from repossessing collateral from a debtor in a bankruptcy case, or from disposing of collateral repossessed from a debtor, without bankruptcy court approval.

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In view of the broad equitable powers of a U.S. bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the Collateral Agent could repossess or dispose of the Collateral, the value of the Collateral at the time of the bankruptcy petition or whether or to what extent Holders would be compensated for any delay in payment or loss of value of the Collateral. The U.S. Bankruptcy Code permits only the payment and/or accrual of post-petition interest, costs and attorneys’ fees to a secured creditor during a debtor’s bankruptcy case to the extent the value of the Collateral is determined by the bankruptcy court to exceed the aggregate outstanding principal amount of the obligations secured by the Collateral.

Furthermore, in the event a bankruptcy court determines that the value of the Collateral is not sufficient to repay all amounts due on the Notes, the Holders would hold secured claims only to the extent of the value of the Collateral, and unsecured claims with respect to any shortfall.

Any future pledge of Collateral in favor of the Collateral Agent, including pursuant to Security Documents delivered after the date of the Indenture, might be voidable by the pledgor (as debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits the Holders of the Notes to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

See “Risk Factors—Risks Relating to the Notes—Rights of holders in the Collateral may be adversely affected by bankruptcy proceedings” and “Risk Factors—Risks Relating to the Notes—Any future pledge of Collateral might be voidable in bankruptcy.”

Certain covenants with respect to the Collateral

The Collateral has been pledged pursuant to the Pledge Agreement, which contains provisions relating to identification of the Collateral and the maintenance of perfected Liens securing the Secured Obligations. The Pledge Agreement provides, inter alia, that:

(a) we will, at our expense, promptly execute and deliver, or otherwise authenticate, all further instruments and documents, and take all further action that may be necessary or desirable, or that the Collateral Agent (at the direction of the Intercreditor Agent) may reasonably request, in order to perfect and protect any pledge or security interest granted or purported to be granted by us under the Pledge Agreement or to enable the Collateral Agent to exercise and enforce its rights and remedies under the Pledge Agreement with respect to any Collateral; and

(b) we will (i) cause OpCo not to issue any Equity Interests or other securities in substitution for the Pledged Equity issued by OpCo, except to us, (ii) cause OpCo not to issue any Equity Interests or other securities in addition to the Pledged Equity issued by OpCo except to the extent such issuance would not create a Change of Control or change in control (each as defined in the Secured Obligation Documents, or such similar definition therein), and (iii) pledge, immediately upon our acquisition (directly or indirectly) thereof, any and all additional Equity Interests or other securities issued to us by OpCo.

Intercreditor Arrangements

The Pari Passu Intercreditor Agreement sets forth, inter alia, provisions relating to the exercise of rights and remedies in respect of the Collateral, the relative rights of the Secured Parties with respect to the proceeds thereof, and certain other matters relating to the administration of the security interests of the Secured Parties in the Collateral. On the Issue Date, the Trustee entered into an Accession Agreement to the Pari Passu Intercreditor Agreement with the Intercreditor Agent and the Issuer for the purpose of joining the Trustee to the Pari Passu Intercreditor Agreement as a Secured Party on behalf of the holders of the Notes.

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The Pari Passu Intercreditor Agreement contains, inter alia, the following provisions:

• Appointment of Collateral Agent and Intercreditor Agent. Each of the Secured Parties that is a party to the Pari Passu Intercreditor Agreement has appointed Wells Fargo Bank, N.A. to act as Collateral Agent and Mizuho Bank, Ltd., to act as Intercreditor Agent. The Collateral Agent and the Intercreditor Agent are each authorized to exercise such rights, powers and authorities as are specifically delegated to the Collateral Agent or the Intercreditor Agent, as the case may be, by the terms of the Pari Passu Intercreditor Agreement and the other Secured Obligation Documents to which it is a party.

• Relative Priorities. The Pari Passu Intercreditor Agreement provides that the Lien of the Collateral Agent in the Collateral shall be for the ratable benefit of the Secured Parties with respect to all Collateral and each class of Secured Creditor ranks and will rank equally in priority with each other class of Secured Creditor in the Lien granted to the Collateral Agent.

• Priority of Payments. All amounts paid to or received by the Collateral Agent or any other Secured Party and representing the proceeds of the Collateral shall be paid promptly to the Secured Parties ratably in the following order of priority: first, administrative costs payable to the Collateral Agent, the Intercreditor Agent and each of the Secured Debt Representatives pursuant to the applicable Secured Obligation Documents, pro rata based on such respective amounts then due to such Persons; second, certain other outstanding fees, costs, charges and expenses then due and payable to the Secured Parties under any Secured Obligation Document, pro rata based on such respective amounts then due to such Persons; third, any accrued but unpaid interest and commitment fees owed to the Secured Creditors on the applicable Secured Obligations and any regularly scheduled payments due to any Hedge Providers, pro rata based on such respective amounts then due to such Secured Creditors; fourth, the unpaid principal, unreimbursed letter of credit disbursements and premium, if any, owed to the Secured Creditors under the applicable Secured Obligation Documents and any termination payments then due and payable to Hedge Providers under the Secured Hedge Agreements, pro rata based on such respective amounts then due to such Secured Creditors; fifth, any remaining unpaid Secured Obligations then due and payable to the relevant Secured Parties (including any additional obligations to provide cash collateral in respect thereof pursuant to the terms of the Secured Obligation Documents), pro rata based on such respective amounts then due to such Secured Parties; and sixth, after final payment in full of all Secured Obligations, to pay to the Issuer, or as may be directed by the Issuer or as a court of competent jurisdiction may direct, any remaining proceeds.

• Decision Making. Where, in accordance with the Pari Passu Intercreditor Agreement or any other Secured Obligation Document, the approval, direction or instruction of the Required Secured Creditors is required, the determination of whether such approval, direction or instruction will be granted or withheld shall be made in accordance with the procedures set forth in the Pari Passu Intercreditor Agreement among the Secured Creditors entitled to vote with respect to the particular approval, direction or instruction. Further, each approval or other direction or instruction of the Required Secured Creditors made in accordance with the terms of the Pari Passu Intercreditor Agreement shall be binding upon each of the Secured Parties.

• Exercise of Remedies. Upon the occurrence of an Event of Default (or equivalent event) under any of the Secured Obligation Documents, the Required Secured Creditors may, through an instruction to the Intercreditor Agent, direct the Collateral Agent to take any action required to protect or enforce the rights vested in any of the Secured Parties by the Secured Obligation Documents, including, without limitation, by instituting judicial or extra-judicial proceedings, selling or causing to be sold any assets which form part of the Collateral in accordance with the relevant Security Document and foreclosing on receivables constituting part of the Collateral and other rights as provided pursuant to the Security Documents. The Collateral Agent shall seek to enforce the Security Documents and to realize upon the Collateral or, in the case of a Bankruptcy of the Issuer, to seek to enforce the claims of the Secured Parties under the Secured Obligation Documents in respect thereof. Upon the acceleration of the Secured Obligations, the proceeds of any collection, recovery, receipt, appropriation, realization or sale

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of any or all of the Collateral or the enforcement of any Security Documents shall be applied as described above in “—Priority of Payments.”

• Standstill. Subject to certain customary exceptions, none of the holders of Secured Obligations which are party to the Pari Passu Intercreditor Agreement may exercise or enforce any of the rights, powers or remedies which the Collateral Agent is authorized to exercise or enforce under the Pari Passu Intercreditor Agreement or any of the other Security Documents with respect to the Collateral.

• Modifications of Secured Obligation Documents. The Pari Passu Intercreditor Agreement provides that, subject to certain exceptions, modifications of any Secured Obligation Document (other than the Security Documents) shall be made in accordance with the requirements of such Secured Obligation Document, and that modifications of any Security Document may be made only with the consent of the Required Secured Creditors. The written consent of the Unanimous Voting Parties is required for certain material modifications including (i) permitting the Issuer to assign its rights or delegate its duties under any Security Document, (ii) releasing any material portion of the Collateral from the Lien of any of the Security Documents or allowing the release of any funds held by the Collateral Agent, (iii) altering the relative priority of payments or application of proceeds as among the Secured Parties, including applicable modifications to the enforcement proceeds waterfall described in the Pari Passu Intercreditor Agreement and (iv) modifications of certain material defined terms. Any modification of any Security Document in a manner that would disproportionately and adversely impact the rights of any class of Secured Creditors as compared to the other classes of Secured Creditors shall, in each case, require the affirmative vote of the class of Secured Creditors so affected (in addition to the consent of the Required Secured Creditors to the extent otherwise required pursuant to the Pari Passu Intercreditor Agreement).

• Delivery of notices, etc. The Collateral Agent and the Intercreditor Agent have agreed to promptly deliver to the Secured Debt Representatives the notices, certificates, reports, opinions, agreements and other documents which it receives under the Pari Passu Intercreditor Agreement and the other Secured Obligation Documents in its capacity as Collateral Agent or Intercreditor Agent, as the case may be.

This summary of the Pari Passu Intercreditor Agreement is not, and does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of such document, which is available for inspection upon written request of any potential investor (subject to appropriate confidentiality restrictions) to us. Unless otherwise stated, any reference in this prospectus to the Pari Passu Intercreditor Agreement means such document and all schedules, exhibits and attachments thereto, as amended, supplemented or otherwise modified and in effect as of the date of this prospectus. Capitalized terms used in the summary and not otherwise defined in this prospectus have the meanings ascribed to such terms in the Pari Passu Intercreditor Agreement.

Collateral Agent

Pursuant to the Pari Passu Intercreditor Agreement, we have appointed Wells Fargo Bank, N.A. to serve as the Collateral Agent for the benefit of the Secured Parties.

Additional debt

To the extent, but only to the extent, permitted by the provisions of the then-extant Secured Obligation Documents, we may incur or issue and sell one or more classes of additional Indebtedness. The obligations in respect of any such additional Indebtedness may be secured by a Lien on the Collateral on apari passubasis, in each case under and pursuant to the Security Documents, if and subject to the condition that the representative of any such additional class or series of Indebtedness, acting on behalf of the holders of such Indebtedness, becomes a party to the Pari Passu Intercreditor Agreement by satisfying the conditions set forth therein.

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Release of Collateral

On the Collateral Release Date, the Notes will become unsecured and rank equally with all of our other unsecured senior Indebtedness. The Collateral Release Date is not expected to occur before May 1, 2023, unless prior to such date we repurchase, amend or otherwise retire our secured Indebtedness (other than the Notes) that is secured by the Collateral.

The Security Documents relating to the Notes and the Indenture provide that the Liens on the Collateral may be released:

(a) in whole, upon the Termination Date;

(b) as to any Collateral that is sold or otherwise disposed of by us or to be sold or otherwise disposed of by us as part of or in connection with any sale or other disposition permitted under the Pari Passu Intercreditor Agreement and under the other applicable Secured Obligation Documents to a person that is not us;

(c) as to a release of less than all or a material portion of the Collateral (other than the Pledged Debt and the Pledged Equity), at any time prior to the Termination Date, if the release of such Liens on such Collateral has been approved, authorized or ratified by the Required Secured Creditors pursuant to the Pari Passu Intercreditor Agreement; and

(d) as to a release of all or any material portion of the Collateral (other than upon the Termination Date), if written consent to release of that Collateral has been given by the Unanimous Voting Parties pursuant to the Pari Passu Intercreditor Agreement.

Upon request by the Collateral Agent at any time, the applicable Secured Parties may be requested to confirm in writing the Collateral Agent’s authority to release its interest in particular types or items of property pursuant to the Pari Passu Intercreditor Agreement. In each case as specified in the Pari Passu Intercreditor Agreement, the Collateral Agent will (and each Secured Party will irrevocably authorize the Collateral Agent to), at our expense, execute and deliver to us such documents as such person may reasonably request to evidence the release of such item of Collateral from the assignment and security interest granted under the Security Documents, in accordance with the terms of the Secured Obligation Documents.

Under the Pari Passu Intercreditor Agreement, if at any time the Collateral Agent forecloses upon or otherwise exercises remedies against any Collateral, then (whether or not any insolvency or liquidation proceeding is pending at the time) the Liens in favor of the Collateral Agent for the benefit of the Holders and the Liens upon such Collateral securing all other Secured Obligations will automatically be released and discharged. However, any proceeds of any Collateral realized therefrom will be applied as described under “—Pari Passu Intercreditor Agreement.”

Amendments

The Collateral Agent may, without obtaining the consent of any Secured Party other than as set forth in the Pari Passu Intercreditor Agreement, modify any Security Document to which it is a party to (a) cure any immaterial ambiguity, defect or inconsistency, (b) to provide for any other ministerial actions with respect to matters arising under the Security Documents (including any such modifications to incorporate appropriate ministerial provisions with respect to the Notes incurred in accordance with the terms of the Indenture), (c) to make any change that would provide any additional rights or benefits to the Secured Parties, (d) to make, complete or confirm any grant of Collateral permitted or required by the Security Documents, and (e) to correct any typographical errors, drafting mistakes or other similar mistakes that do not modify the intended rights, benefits and obligations of the parties hereto, in each case, which do not involve any material change;providedthat such actions do not materially adversely affect the interests of the Secured Parties.

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Subject to certain exceptions, the Pari Passu Intercreditor Agreement may be amended with the consent of the Required Secured Creditors,providedthat if any amendment disproportionately and adversely affects any class of Secured Parties (other than any Agent or Trustee) as compared to any other such class, the affirmative vote of such class so affected (in addition to the consent of the Required Secured Creditors to the extent otherwise required pursuant to the Pari Passu Intercreditor Agreement), is required.

Authorization of actions to be taken

Each Holder of Notes, by its acceptance thereof, will be deemed to have consented and agreed to the terms of each Security Document, as originally in effect and as amended, supplemented or replaced from time to time in accordance with its terms or the terms of the Indenture, to have authorized and directed the Trustee to enter into the Pari Passu Intercreditor Agreement, and to have authorized and empowered the Trustee and (through the Pari Passu Intercreditor Agreement) the Collateral Agent to bind the Holders of Notes as set forth in the Security Documents to which they are a party and to perform its respective obligations and exercise its respective rights and powers thereunder.

Optional Redemption

At any time prior to February 1, 2026 or November 1, 2045 (three months and six months prior to maturity of the 2026 Notes and 2046 Notes, respectively) (each, a “Par Call Date”), as applicable, we may, at our option, redeem the 2026 Notes or the 2046 Notes, respectively, in whole at any time or in part from time to time, upon notice sent by electronic transmission or by first-class mail not less than 30 nor more than 60 days before the date fixed for redemption, at a redemption price equal to the greater of:

(a) 100% of the principal amount of the Notes then outstanding to be redeemed; and

(b) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed that would be due if such Notes matured on the applicable Par Call Date (not including any portion of such interest payments accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus 30 basis points and 40 basis points for the 2026 Notes and 2046 Notes, respectively,

plus accrued and unpaid interest thereon (including additional interest, if any) to, but excluding, the date of redemption. The Issuer will calculate the Treasury Rate prior to such redemption date and file with the Trustee an officer’s certificate setting forth the redemption price and the Treasury Rate, showing the calculation of each in reasonable detail.

In addition, at any time on or after the applicable Par Call Date, we may, at our option, redeem the 2026 Notes or the 2046 Notes, in whole at any time or in part from time to time, upon notice sent by electronic transmission or by first-class mail not less than 30 nor more than 60 days before the date fixed for redemption, at a redemption price equal to 100% of the principal amount of the Notes then outstanding to be redeemed, plus accrued and unpaid interest thereon (including additional interest, if any) to, but excluding, the date of redemption.

If less than all of any series of Notes are to be redeemed, the particular Notes to be redeemed will be selected by the Registrar from the outstanding Notes of such series not previously called for redemption in compliance with the requirements of the principal national securities exchange, if any, on which the series of Notes is listed or, if the series of Notes is not listed on a national securities exchange, on a pro rata basis, by lot or by such method as the Trustee deems fair and appropriate that complies with applicable legal requirements, if any, and in accordance with the procedures of DTC. A portion of any series of Notes may be redeemed only in denominations of $2,000 principal amount and integral multiples of $1,000 in excess thereof.

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Any notice of redemption at our option may state that the Notes are to be refinanced by the issuance of other Indebtedness by us or any of our Affiliates, in which event such redemption will be conditional upon our (or our Affiliate’s) receipt, on or before the date fixed for such redemption, of proceeds of such Indebtedness sufficient to pay the principal of and premium, if any, and interest, if any, on the Notes being redeemed, and if such money has not been so received, such notice will be of no force or effect and we will not be required to redeem such Notes. If a notice of redemption does not include such a statement, notices of redemption may not be conditional and once a notice of optional redemption is sent, Notes called for redemption become irrevocably due and payable on the redemption date at the redemption price.

Unless we default in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the Notes or portions thereof called for redemption.

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 (equal to $2,000 or an integral multiple of $1,000 in excess thereof) 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 the mailing of written notice 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 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 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:

(a) 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;

(b) the Change of Control Purchase Price;

(c) the Purchase Date;

(d) the name and address of the paying agent; and

(e) the procedures that Holders must follow to cause the Notes to be repurchased.

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:

(a) 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;

(b) that such Notes are to be repurchased by us pursuant to the applicable Change of Control provisions of the Indenture; and

(c) 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

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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 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 (a “Certificated Note”) 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 offer. 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 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 our Senior Secured Credit Facilities. Depending on the circumstances, it is possible that a change in control may occur for purposes of our Senior Secured 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.

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Under clause (c) 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. InSan 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 shareholders. 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.

The Indenture requires us to comply with the provisions of Regulation 14E and any other tender offer rules under the Securities Exchange Act of 1934, as amended (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. 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” below (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.

Certain Material Covenants

Merger, Consolidation, Sale, Lease or Conveyance

The Indenture will provide 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:

(i) 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;

(ii) 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;

(iii) immediately after such consolidation or merger, no Event of Default exists; and

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(iv) 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

We will not pledge, mortgage, hypothecate or grant a security interest in, or permit any mortgage, pledge, security interest or other Lien upon, any of the Issuer’s assets or property, whether owned on the Issue Date 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 pursuant to the terms of the Pari Passu Intercreditor Agreement 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).

Reports and Other Information

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 filer that is a “non-accelerated filer”:

(a) 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

(b) 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 clauses (a) and (b) above with the SEC for public availability within the time periods specified in clauses (a) and (b) above (unless the SEC will not accept such a filing). We agree that we will not take any action for the purpose of causing the SEC not to accept any such filings. 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 the Issuer’s compliance with any of their covenants under the Indenture (as to which the Trustee is entitled to rely exclusively on officer’s certificates).

Information Regarding Collateral

We will furnish to the Collateral Agent prompt written notice of any change in our (a) legal name, (b) jurisdiction of incorporation or (c) identity or corporate structure. We will agree not to effect or permit any change referred to in the preceding sentence unless all filings have been made or will have been made promptly

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following any such change (and in no event later than the expiry of any applicable statutory period) under the Uniform Commercial Code or otherwise that are required in order for the Collateral Agent to continue at all times following such change to have a valid, legal and perfected security interest in all the Collateral. We also agree promptly to notify the Collateral Agent if any material portion of the Collateral is damaged, destroyed or condemned.

In addition, each year, at the time of delivery of our annual financial statements with respect to the preceding fiscal year, we will deliver to the Trustee and the Holders a certificate of a Financial Officer setting forth the information required pursuant to the schedules required by the Security Documents or confirming that there has been no change in such information since the date of the prior annual financial statements.

No Liability of Directors, Officers, Employees, Incorporators and Shareholders

None of our directors, officers, employees, incorporators, members or shareholders, as such, will have any liability for any of our obligations under the Notes or the Indenture or for any claim based on, in respect of, or by reason of, such obligations. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Events of Default

Any one or more of the following events with respect to the Notes that has occurred and is continuing will constitute an “Event of Default” with respect to the Notes under the Indenture:

(a) failure to pay interest within 30 days after the same becomes due and payable;

(b) failure to pay the principal of, or any premium on, the Notes at maturity, upon redemption, upon required purchase, upon acceleration or otherwise;

(c) failure to perform or breach of any covenant, representation, warranty or other agreement contained in the Indenture, the Notes or the Security Documents (other than a default referred to in clauses (a) and (b) above) for 60 days after written notice to us by the Trustee or to us and the Trustee by the Holders of at least 25% in principal amount of the Notes as provided in the Indenture unless the Trustee, or the Trustee and the Holders of a principal amount of the Notes not less than the principal amount of Notes the Holders of which gave such notice, as the case may be, agree in writing to an extension of such period before its expiration;providedthat the Trustee, or the Trustee and the Holders of such principal amount of Notes, as the case may be, will be deemed to have agreed to an extension of such period (not to exceed a total period of 120 days) if corrective action is initiated by us within such period and is being diligently pursued;

(d) the occurrence of an event of default (howsoever defined), as defined in any of our instruments or any Significant Subsidiary’s instruments under which there is or by which there is evidenced any Indebtedness of us or any Significant Subsidiary, that has resulted in the acceleration of such Indebtedness in excess of $50 million, or any default in payment of Indebtedness in excess of $50 million at final maturity, after the expiration of any applicable grace or cure periods;providedthat the waiver or cure of any such default under any such instrument or Indebtedness shall constitute a waiver and cure of the corresponding Event of Default under the Indenture and the rescission and annulment of the consequences thereof shall constitute a rescission and annulment of the corresponding consequences under the Indenture;

(e) certain events of bankruptcy or insolvency described in the Indenture with respect to us or any Significant Subsidiary of ours;

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(f) our repudiation of any of our obligations under any of the Security Documents or the unenforceability of any of the Security Documents against us for any reason if such unenforceability shall be applicable to (i) Collateral having an aggregate Fair Market Value of $50 million or more or (ii) the Pledged Equity and any such unenforceability has not been cured within 60 days after written notice to us by the Trustee or to us and the Trustee by the Holders of at least 25% in principal amount of the Notes as provided in the Indenture;

(g) any Security Document or any Lien purported to be granted thereby is held in any judicial proceeding to be unenforceable or invalid, in whole or in part, or ceases for any reason (other than pursuant to a release that is delivered or becomes effective as set forth in the Indenture) to be fully enforceable and perfected and any such unenforceability or lack of perfection has not been cured within 60 days after written notice to us by the Trustee or to us and the Trustee by the Holders of at least 25% in principal amount of the Notes as provided in the Indenture; and

(h) 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.

Remedies

Acceleration of Maturity

In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to us or any Significant Subsidiary of ours, as described in clause (e) under “—Events of Default” above, then the principal, premium, if any, and accrued interest on the Notes will be immediately due and payable, without any declaration or other act on the part of the Trustee or any Holder. If any other Event of Default occurs and is continuing, then either the Trustee or the Holders of not less than 25% in aggregate principal amount of the outstanding Notes may declare the principal amount of all of the outstanding Notes to be due and payable immediately by written notice to us (and to the Trustee if given by the Holders);providedthat if an Event of Default occurs and is continuing with respect to more than one series of Notes, including the Notes offered hereby, the Trustee or the Holders of not less than 25% in aggregate principal amount of the Notes of all such series, considered as one class, may make such declaration of acceleration and not the Holders of any one series of such Notes.

At any time after such a declaration of acceleration with respect to any series of Notes outstanding under the Indenture has been made, but before a judgment or decree for payment of the money due has been obtained, such declaration and its consequences will, without further act, be deemed to have been rescinded and annulled, if:

(a) We have paid or deposited with the Trustee a sum sufficient to pay:

(i) all overdue interest, if any, on all Notes of such series;

(ii) the principal of and premium, if any, on any Notes of such series which have become due otherwise than by such declaration of acceleration and interest, if any, thereon at the rate or rates prescribed therefor in such Notes;

(iii) interest, if any, upon overdue interest, if any, at the rate or rates prescribed therefor in the Notes, to the extent that payment of such interest is lawful; and

(iv) all amounts due to the Trustee under the Indenture in respect of compensation and reimbursement of expenses; and

(b) all Events of Default with respect to the Notes of such series, other than the nonpayment of the principal of the Notes of such series which has become due solely by such declaration of acceleration, have been cured or waived as provided in the Indenture.

However, no such rescission and annulment will extend to or affect any subsequent default or impair any related right.

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Right to Direct Proceedings

If an Event of Default with respect to any series of Notes outstanding under the Indenture occurs and is continuing, the Holders of a majority in principal amount of such Notes will have the right to direct the time, method and place of conducting any proceedings for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee, to the extent such action does not conflict with the provisions of the Indenture, the Pari Passu Intercreditor Agreement or applicable Governmental Rule;providedthat if an Event of Default occurs and is continuing with respect to more than one series of Notes outstanding under the Indenture, the Holders of a majority in aggregate principal amount of the outstanding Notes of all such series, considered as one class, will have the right to make such direction, and not the Holders of the Notes of any one of such series;provided,further, that (a) such direction does not conflict with any rule of law or with the Indenture, and could not involve the Trustee in personal liability in circumstances where indemnity would not, in the Trustee’s sole discretion, be adequate, (b) the Trustee does not determine that the action so directed would be unjustly prejudicial to the Holders of such series of Notes not taking part in such direction and (c) the Trustee may take any other action deemed proper by the Trustee which is not inconsistent with such direction.

Limitation on Right to Institute Proceedings

No Holder of any Note will have any right to institute any proceeding, judicial or otherwise, with respect to the Indenture or for the appointment of a receiver or for any other remedy thereunder unless:

(a) such Holder has previously given to the Trustee written notice of a continuing Event of Default with respect to the Notes;

(b) the Holders of at least 25% in aggregate principal amount of Notes of all series outstanding under the Indenture in respect of which such Event of Default has occurred, considered as one class, have made written request to the Trustee to institute proceedings in respect of such Event of Default and have offered the Trustee an indemnity satisfactory to the Trustee against costs, expenses and liabilities to be incurred in complying with such request; and

(c) for 60 days after receipt of such notice, the Trustee has failed to institute any such proceeding and no direction inconsistent with such request has been given to the Trustee during such 60-day period by the Holders of a majority in aggregate principal amount of Notes then outstanding under the Indenture.

Furthermore, no Holder of Notes will be entitled to institute any such action if and to the extent that such action would disturb or prejudice the rights of other Holders of Notes.

No Impairment of Right to Receive Payment

Notwithstanding that the right of a Holder of Notes to institute a proceeding with respect to the Indenture is subject to certain conditions precedent, each Holder of a Note will have the right, which is absolute and unconditional, to receive payment of the principal of and premium, if any, and interest, if any, on such Note when due and to institute suit for the enforcement of any such payment, and such rights may not be impaired or affected without the consent of such Holder.

Notice of Default

The Trustee is required to give the Holders of Notes outstanding under the Indenture notice of any default under the Indenture to the extent required by the Trust Indenture Act, unless such default has been cured or waived, except that no such notice to Holders of a default of the character described in clause (c) under “—Events of Default” may be given until at least 75 days after the occurrence thereof. For purposes of the preceding sentence, the term “default” means any event which is, or after notice or lapse of time, or both, would become, an Event of Default. The Trust Indenture Act currently permits the Trustee to withhold notices of default (except for certain payment defaults) if the Trustee in good faith determines the withholding of such notice to be in the interests of the Holders.

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Officer’s Certificates

The Indenture requires that certain of our officers certify, on or before a date not more than 120 days after the end of each fiscal year, that to the best of those officers’ knowledge, we have fulfilled all our obligations under the Indenture. We are also obligated to notify the Trustee of any default or defaults in the performance of any covenants or agreements under the Indenture, but a failure by us to deliver such notice of a default will not constitute a default under the Indenture if we have remedied such default within any applicable cure period.

Modification of Indenture

Modifications Without Consent

We and the Trustee may enter into one or more supplemental Indentures without the consent of any Holder of the Notes, for any of the following purposes:

(a) to evidence the succession of another person to the Issuer and the assumption by any such successor of the covenants of such party;

(b) to add one or more covenants of the Issuer or other provisions for the benefit of Holders of the Notes, or to surrender any right or power conferred upon us by the Indenture;

(c) to change or eliminate any provision of the Indenture or to add any new provision to the Indenture,providedthat if such change, elimination or addition adversely affects the interests of the Holders of any series or tranche of Notes in any material respect, such change, elimination or addition will become effective only when no Notes are outstanding;

(d) to comply with any requirements of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;

(e) to make, complete or confirm any grant of Collateral permitted or required by the Security Documents or, with the consent of the Collateral Agent, any release of Collateral that becomes effective as set forth in the Security Documents;

(f) to establish the form or terms of Notes of any series or tranche under the Indenture as permitted by the Indenture;

(g) to provide for the authentication and delivery of bearer Notes and coupons appertaining thereto representing interest, if any, thereon and for the procedures for the registration, exchange and replacement thereof and for the giving of notice to, and the solicitation of the vote or consent of, the Holders thereof, and for any and all other matters incidental thereto;

(h) to evidence and provide for the acceptance of appointment by a successor Trustee;

(i) to provide for the procedures required to permit the utilization of a non-certificated system of registration for all, or any series or tranche of, the Notes under the Indenture;

(j) to change any place or places where—

(i) the principal of and premium, if any, and interest, if any, on all or any series of Notes under the Indenture, or any tranche thereof, will be payable,

(ii) all or any series of Notes under the Indenture, or any tranche thereof, may be surrendered for registration of transfer,

(iii) all or any series of Notes under the Indenture, or any tranche thereof, may be surrendered for exchange, and

(iv) notices and demands to or upon us in respect of all or any series of Notes under the Indenture, or any tranche thereof, and the Indenture may be served;

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(k) to cure any ambiguity or mistake, to correct or supplement any provision therein which may be defective or inconsistent with any other provision therein:

(l) to make any other changes to the provisions thereof or to add other provisions with respect to matters and questions arising under the Indenture, so long as such other changes or additions do not adversely affect the interests of the Holders of any series or tranche of Notes under the Indenture in any material respect;

(m) to conform the text of the Indenture or the Notes to any provision of this “Description of the Exchange Notes”, as described in an officer’s certificate; or

(n) to waive the rights of other secured debt holders.

In addition, if the Trust Indenture Act is amended after the date of the original Indenture in such a way as to require changes to the Indenture or the incorporation therein of additional provisions or so as to permit changes to, or the elimination of, provisions which, at the date of the original Indenture or at any time thereafter, were required by the Trust Indenture Act to be contained in the Indenture, the Indenture will be deemed to have been amended so as to conform to such amendment or to effect such changes or elimination, and we and the Trustee may, without the consent of any Holders of Notes outstanding under the Indenture, enter into one or more supplemental Indentures to evidence such amendment.

Modifications Requiring Consent

Except as provided above, the consent of the Holders of a majority in aggregate principal amount of all series of Notes then outstanding under the Indenture, considered as one class, is required for the purpose of adding any provisions to, or changing in any manner, or eliminating any of the provisions of, the Indenture pursuant to one or more supplemental Indentures;providedthat if less than all of the series of Notes outstanding under the Indenture are directly affected by a proposed supplemental Indenture, then the consent only of the Holders of a majority in aggregate principal amount of outstanding Notes of all series so directly affected, considered as one class, will be required;provided,further, that if the Notes of any series have been issued in more than one tranche and if the proposed supplemental Indenture directly affects the rights of the Holders of one or more, but less than all, of such tranches, then the consent only of the Holders of a majority in aggregate principal amount of the outstanding Notes of all tranches so directly affected, considered as one class, will be required;provided,further, that no such supplemental Indenture may, without the consent of the Holder of each Note affected thereby:

(a) reduce the principal amount of or change the stated maturity of any installment of principal of the Notes;

(b) reduce the rate of or change the stated maturity of any interest payment on the Notes;

(c) reduce the amount payable upon the redemption of the Notes or, in respect of an optional redemption, change the times at which the Notes may be redeemed or, once notice of redemption has been given, the time at which they must thereupon be redeemed;

(d) waive an Event of Default in the payment of principal of, or premium, if any, or interest on, the Notes (except a rescission of acceleration of such Notes by the Holders of at least a majority in aggregate principal amount of such Notes and a waiver of the payment default that resulted from such acceleration);

(e) make the Notes payable in money other than that stated in the Notes;

(f) impair the right of any Holder of Notes to receive any principal payment or interest payment on such Holder’s Notes, on or after the stated maturity thereof, or to institute suit for the enforcement of any such payment;

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(g) make any change in the percentage of the principal amount of the Notes required for amendments or waivers; or

(h) modify or change any provision of the Indenture affecting the ranking of the Notes in a manner adverse to the Holders of the Notes.

It is not necessary for Holders to approve the particular form of any proposed amendment, supplement or waiver, but it is sufficient if their consent approves the substance thereof.

Neither we nor any of our subsidiaries or affiliates may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any Holder for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or agreed to be paid to all Holders of the Notes that consent, waive or agree to amend such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver or amendment.

A supplemental Indenture which changes or eliminates any covenant or other provision of the Indenture which has expressly been included solely for the benefit of the Holders of, or which is to remain in effect only so long as there shall be outstanding, Notes of one or more specified series outstanding under the Indenture, or one or more tranches thereof, or modifies the rights of the Holders of Notes of such series or tranches with respect to such covenant or other provision, will be deemed not to affect the rights under the Indenture of the Holders of the Notes of any other series or tranche.

If the supplemental Indenture or other document establishing any series or tranche of Notes under the Indenture so provides, and as specified in the applicable prospectus, prospectus supplement and/or pricing supplement, the Holders of such Notes will be deemed to have consented, by virtue of their purchase of such Notes, to a supplemental Indenture containing the additions, changes or eliminations to or from the Indenture which are specified in such supplemental Indenture or other document, no act of such Holders will be required to evidence such consent and such consent may be counted in the determination of whether the Holders of the requisite principal amount of Notes have consented to such supplemental Indenture.

Satisfaction and Discharge

The Notes, or any portion of the principal amount thereof, will be deemed to have been paid for purposes of the Indenture and, at our election, our entire Indebtedness in respect thereof will be deemed to have been satisfied and discharged, if there shall have been irrevocably deposited with the Trustee, in trust:

(a) money in an amount which will be sufficient, or

(b) in the case of a deposit made before the maturity of such Notes that do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, Eligible Obligations (as defined below), the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide moneys which, together with the money, if any, deposited with or held by the Trustee, will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent accountants, or

(c) a combination of (a) and (b) which will be sufficient,

to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Notes. For this purpose, “Eligible Obligations” means direct obligations of, or obligations unconditionally guaranteed by, the United States, entitled to the benefit of the full faith and credit thereof and certificates, depositary receipts or other instruments which evidence a direct ownership interest in such obligations or in any specific interest or principal payments due in respect thereof, and such other obligations or instruments as shall be specified in an accompanying prospectus supplement.

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The Indenture will be deemed to have been satisfied and discharged when no Notes remain outstanding thereunder and we have paid or caused to be paid all other sums payable by us under the Indenture.

Our right to cause our entire Indebtedness in respect of any Notes to be deemed to be satisfied and discharged as described above will be subject to the delivery to the Trustee of an opinion of counsel to the effect that in connection with any such deposit above, the Holders of such Notes will not recognize income, gain or loss for United States federal income tax purposes as a result of the satisfaction and discharge of our Indebtedness in respect thereof and will be subject to United States federal income tax on the same amounts, at the same times and in the same manner as if such satisfaction and discharge had not been effected.

In addition, the Issuer must deliver an officer’s certificate and an opinion of counsel to the Trustee stating that all conditions precedent to the satisfaction and discharge have been satisfied.

Concerning the Trustee

Wells Fargo Bank, N.A. is the Trustee under the Indenture.

Except during the continuance of an Event of Default, the Trustee need perform only those duties that are specifically set forth in the Indenture and no others, and no implied covenants or obligations will be read into the Indenture against the Trustee. In case an Event of Default has occurred and is continuing, the Trustee will exercise those rights and powers vested in it by the Indenture and use the same degree of care and skill in their exercise as a prudent person would exercise or use under the circumstances in the conduct of such person’s own affairs. No provision of the Indenture will require the Trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties thereunder, or in the exercise of its rights or powers, unless it receives indemnity satisfactory to it against any loss, liability or expense.

The Indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the Trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee is permitted to engage in other transactions with us and our affiliates;providedthat if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the SEC for permission to continue or resign.

Book-Entry; Delivery and Form

All interests in the global Notes, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of their systems.

Book-Entry Procedures for the Global Notes

The description of the operations and procedures of DTC, Euroclear and Clearstream set forth below are provided solely as a matter of convenience and are not intended to serve as a representation or warranty of any kind. These operations and procedures are solely within the control of these settlement systems and are subject to change by term from time to time. Neither we nor the initial purchasers take any responsibility for these operations or procedures, and investors are urged to contact the relevant system and its participants directly to discuss these matters.

The following is based upon information furnished by DTC:

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 pursuant to the provisions of Section 17A of the Exchange Act. DTC holds and provides asset

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servicing for issues of U.S. and non-U.S. equity, corporate and municipal debt issues, and money market instruments that DTC’s participants (“Direct Participants”) deposit with DTC.

DTC also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The DTC Rules applicable to its Direct and Indirect Participants are on file with the SEC. More information about DTC can be found at www.dtcc.com.

Purchases of Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the Notes on DTC’s records. The ownership interest of each actual purchaser of each Note (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from DTC of their purchase. Beneficial Owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the Notes are to be accomplished by entries made on the books of Direct Participants and Indirect Participants acting on behalf of Beneficial Owners. Transfers between participants in Euroclear and Clearstream will be effected in the ordinary way in accordance with their respective rules and operating procedures. Beneficial Owners will not receive certificates representing their ownership interests in Notes, except in the event that use of the book-entry system for the Notes is discontinued.

To facilitate subsequent transfers, all Notes deposited by Direct Participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of Notes with DTC and their registration in the name of Cede & Co. or such other nominee do not effect any change in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the Notes; DTC’s records reflect only the identity of the Direct Participants to whose accounts such Notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Beneficial Owners of Notes may wish to take certain steps to augment transmission to them of notices of significant events with respect to the Notes, such as redemptions, tenders, defaults and proposed amendments to the Security Documents. For example, Beneficial Owners of Notes may wish to ascertain that the nominee holding the Notes for their benefit has agreed to obtain and transmit notices to Beneficial Owners; in the alternative, Beneficial Owners may wish to provide their names and addresses to the Registrar and request that copies of the notices be provided directly to them.

Redemption notices shall be sent to DTC. If less than all of the Notes within an issue are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each Direct Participant in such issue to be redeemed.

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Neither DTC nor Cede & Co. (nor other DTC nominee) will consent or vote with respect to the Notes unless authorized by a Direct Participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an omnibus proxy to the issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the Notes are credited on the record date (identified in a listing attached to the omnibus proxy).

Redemption proceeds, distributions and interest payments on the Notes will be made to Cede & Co. or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit Direct Participants’ accounts, upon DTC’s receipt of funds and corresponding detailed information from the issuer or agent on the payable date in accordance with their respective holdings shown on DTC’s records. Payments by Direct or Indirect Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of such Direct or Indirect Participant and not of DTC or its nominee, agent or issuer, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of redemption proceeds, distributions and dividend payments to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) is the responsibility of the issuer or agent, disbursement of such payments to Direct Participants will be the responsibility of DTC, and disbursement of such payments to the Beneficial Owners will be the responsibility of Direct and Indirect Participants.

Cross-market transfers between DTC, on the one hand, and directly or indirectly through Euroclear or Clearstream participants, on the other, will be effected in DTC in accordance with DTC rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; 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 its rules and procedures and within its established deadlines (Brussels time). Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the global securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in the global securities from a DTC participant will be credited during the securities settlement processing day (which must be a business day for Euroclear or Clearstream, as the case may be) immediately following the DTC settlement date, and such credit of any transactions in the global securities settled during such processing day will be reported to the relevant Euroclear or Clearstream participant on such day. Cash received by Euroclear or Clearstream as a result of sales of interests in the global securities by or through a Euroclear or Clearstream participant to a DTC participant will be received with value on the DTC settlement date, but will be available in the relevant Euroclear or Clearstream cash account only as of the business day following settlement in DTC.

If DTC at any time is unwilling or unable to continue as a depositary, defaults in the performance of its duties as depositary or ceases to be a clearing agency registered under the Exchange Act or other applicable statute or regulation, and a successor depositary is not appointed by us within ninety (90) days, we will issue Notes in definitive form in exchange for the global securities relating to the Notes. In addition, we may at any time and in our sole discretion, subject to the procedures of the depositary and DTC, determine not to have the Notes or portions of the Notes represented by one or more global securities and, in that event, will issue individual Notes in exchange for the global security or securities representing the Notes. Further, if we so specify with respect to any Notes, an owner of a beneficial interest in a global security representing the Notes may, on terms acceptable to us and the depositary for the global security, receive individual Notes in exchange for such beneficial interest, subject to DTC’s procedures. In any such instance, an owner of a beneficial interest in a global security will be entitled to physical delivery in definitive form of Notes represented by the global security equal in principal amount to the beneficial interest, and to have the Notes registered in its name. Notes so issued

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in definitive form will be issued as registered Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof, unless otherwise specified by us. Such Notes will be subject to certain restrictions on registration of transfers as described under “Notice to Investors” and will bear the legend set forth thereunder. The Notes may not be resold or transferred except as permitted under the Securities Act and the applicable state securities laws pursuant to registration or exemption therefrom. We will have no obligation to register the Notes offered hereby for resale under United States securities laws, and have no plans to do so. Furthermore, we have not registered the Notes under any other country’s securities laws.

Governing Law

The Indenture and the Notes shall be governed by, and construed in accordance with, the laws of the State of New York.

Definitions

Set forth below are certain defined terms used in the Indenture and in this description. Reference is made to the Indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

“Accession Agreement” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“Acquisition Facilities Credit Agreement” means the Credit Agreement, dated as of April 13, 2016, among us, the Acquisition Facilities Administrative Agent and the lenders party thereto, as amended, restated or otherwise modified from time to time.

“Acquisition Facilities Administrative Agent” means Mizuho Bank, Ltd., in its capacity as administrative agent for the lenders under the Acquisition Facilities Credit Agreement.

“Acquisition Loan Facility” means the term loan facility in the original principal amount of $1,350,000,000 made available to the Issuer under the Acquisition Facilities Credit Agreement.

“Additional Senior Indebtedness” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“Additional Senior Indebtedness Obligations” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“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.

“Affiliate” 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).

“Agents” means the Acquisition Facilities Administrative Agent and the Collateral Agent.

“Authorized Officer” means, (a) with respect to any person that is a corporation or a limited liability company, the chairman, any director or manager, the president, any vice president or the Financial Officer of

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such person or any other person authorized to act on behalf of such corporation or limited liability company in respect of the action, and (b) with respect to any person that is a partnership, any director or manager, the president, any vice president or the Financial Officer of a general partner or managing partner of such person or any other person authorized to act on behalf of such partnership in respect of the action.

“Business Day” means any day, other than a Saturday or Sunday, that is not a day on which banking institutions or trust companies in the place of payment are generally authorized or required by law, regulation or executive order to remain closed.

“Change of Control” means the occurrence of any of the following events:

(a) 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;

(b) 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 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;

(c) 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

(d) 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.

“Collateral” means (a) the Pledged Debt, (b) the Pledged Equity, (c) any other assets from time to time subject to a Lien in favor of the Collateral Agent for the benefit of the Secured Parties to secure the Secured Obligations as required under the Secured Obligation Documents, and (d) all proceeds of the foregoing;provided,however, “Collateral” shall not include cash collateral granted for a specific purpose under any Secured Obligation Document as long as such cash collateral is permitted under the terms of each other Secured Obligation Document and not required to be subject to a Lien in favor of the Collateral Agent for the benefit of any other Secured Parties to secure the Secured Obligations of such other Secured Parties (“Excluded Cash Collateral”).

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“Collateral Agent” means Wells Fargo Bank, N.A., in its capacity as collateral agent under the Security Documents and Pari Passu Intercreditor Agreement, and any successor collateral agent under the Pari Passu Intercreditor Agreement.

“Collateral Release Date” means the date on which we have retired all of our Indebtedness (other than the Notes) that is secured by the Collateral.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Notes to be redeemed (assuming for this purpose that the 2026 Notes matured on February 1, 2026, and the 2046 Notes matured on November 1, 2045) that would be used, 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 the Notes.

“Comparable Treasury Price” means, with respect to any redemption date, (a) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third Business Day preceding such redemption date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated “Composite 3:30 p.m. Quotations for U.S. Government Securities” or (b) if such release (or any successor release) is not published or does not contain such prices on such third Business Day, (i) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations or (ii) if the Independent Investment Banker obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such Quotations.

“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.

“Credit Agreement” means the Acquisition Facilities Credit Agreement (or any amendments, modifications, refinancings or replacements thereof).

“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).

“Event of Default” has the meaning assigned to such term in “—Events of Default.”

“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.

“Financial Officer” means the chief financial officer, principal accounting officer, vice president finance, treasurer or assistant treasurer of the Issuer or individual holding a similar position.

“Fitch” means Fitch Investors Service, Inc. or its successors.

“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.

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“GAAP” means generally accepted accounting principles in the United States of America, as in effect from time to time, consistently applied.

“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.

“Hedge Provider” means any person that is a lender under any Credit Agreement or a holder of any Additional Senior Indebtedness or Permitted Refinancing Indebtedness or an Affiliate of any thereof at the time it enters into a Secured Hedge Agreement, in each case that at the time it enters into the applicable Secured Hedge Agreement, is a United States commercial bank or financial institution or a United States branch of a foreign commercial bank or financial institution;providedthat such Hedge Provider executes an Accession Agreement pursuant to the terms of the Pari Passu Intercreditor Agreement.

“Incremental Facilities” means, collectively, the “Incremental Facilities” as defined in the Acquisition Facilities Credit Agreement.

“Incur” means, with respect to any Indebtedness, to incur, create, issue, assume, guarantee or otherwise become directly or indirectly liable for or with respect to, or become responsible for, the payment of, contingently or otherwise, such Indebtedness. “Incurrence” and “Incurred” will have meanings correlative to the foregoing.

“Indebtedness” of any person means:

(a) all indebtedness of such person for borrowed money,

(b) all obligations of such person evidenced by bonds, debentures, notes or other similar instruments,

(c) all obligations of such person to pay the deferred purchase price of property or services (other than trade payables not overdue for more than 180 days) that in accordance with GAAP would be included as a liability on the balance sheet of such person,

(d) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such person,

(e) any capital lease obligations (and the amount of these obligations shall be the amount so capitalized),

(f) all obligations, contingent or otherwise, of such person under acceptances issued or created for the account of such person,

(g) all unconditional obligations of such person to purchase, redeem, retire, defease or otherwise acquire for value any capital stock or other Equity Interests of such person or any warrants, rights or options to acquire such capital stock or other Equity Interests,

(h) all net obligations of such person pursuant to hedging transactions,

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(i) all guarantees of such person in respect of obligations of the kind referred to in clauses (a) through (h) above, and

(j) all Indebtedness of the type referred to in clauses (a) through (h) above secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property (including accounts and contracts rights) owned by such person, even though such person has not assumed or become liable for the payment of such Indebtedness, but only to the extent of the lesser of such Indebtedness or the value of the property secured by such Lien.

For purposes of this definition, the amount of the liability of such person with respect to any hedge agreement (or similar agreement or arrangement) at any time shall be the maximum aggregate amount (giving effect to any netting agreements) that such person would be required to pay if such hedging agreement were terminated at such time.

“Independent Investment Banker” means each of Mizuho Securities USA Inc., CIBC World Markets Corp., Credit Agricole Securities (USA) Inc., Scotia Capital (USA) Inc. and SMBC Nikko Securities America, Inc. or their respective successors, or if any such firm is unwilling or unable to serve as such, an independent investment banking institution of national standing appointed by us.

“Intercreditor Agent” means Mizuho Bank, Ltd., in its capacity as intercreditor agent under the Pari Passu Intercreditor Agreement, and any successor intercreditor agent under the Pari Passu Intercreditor Agreement.

“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. For purposes of the preceding sentence, the term “portfolio companies” does not include, without limitation, (i) any investment fund or investment vehicle managed or co-managed by any Investor or by any of such investment funds’ or investment vehicles’ Affiliates or (ii) any direct or indirect non-operating subsidiary of any Investor.

“Issue Date” means May 17, 2016.

“Issuing Bank” has the meaning assigned to such term in the Acquisition Facilities Credit Agreement.

“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.

“Pari Passu Intercreditor Agreement” means that certain Collateral Agency and Intercreditor Agreement dated as of April 13, 2016, as amended, restated or otherwise modified from time to time, among us, the Collateral Agent, the Acquisition Facilities Administrative Agent, the Intercreditor Agent, the Trustee and the other agents, trustees or other persons from time to time party thereto.

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“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 clause (h) of “—Events of Default” or any criminal or unindemnified civil liability (in the case of any such civil liability, otherwise required to be indemnified by the Issuer 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;providedthat, 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:

(a) 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;

(b) Liens for Taxes, assessments or governmental charges, which are not yet due or which are being contested pursuant to the Permitted Contest Conditions;

(c) 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;

(d) 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;

(e) Liens securing judgments that do not constitute an Event of Default described in clause (h) of “—Events of Default”;

(f) 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 the business of the Issuer;

(g) Liens that have been placed by a third party on the fee title of leased real property or property over which the Issuer has easement rights, and subordination or similar agreements relating thereto;

(h) Liens (i) pursuant to the Security Documents securing the Secured Obligations and (ii) from and after the Collateral Release Date, securing Indebtedness in an aggregate principal amount not to exceed 15% of the Fair Market Value of the property and assets of the Issuer;

(i) 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;

(j) 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,

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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);

(k) 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;

(l) Liens securing or deposits securing obligations of the Issuer and its subsidiaries with respect to workers’ compensation, unemployment insurance and other types of social security; and

(m) Liens permitted under the Credit Agreement (or any amendments, modifications, refinancings or replacements thereof) other than Liens securing obligations of the Issuer under or in connection with the Credit Agreement (or any amendments, modifications, refinancings or replacements thereof).

“Permitted Refinancing Indebtedness” means any Indebtedness of the Issuer issued in exchange for, or the net cash proceeds of which are used to refund, refinance, replace, defease or discharge, other Indebtedness of the Issuer;providedthat:

(a) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on such Indebtedness and the amount of all reasonable out of pocket expenses and premiums, underwriting, issuance, commitment, syndication and other similar fees, costs and expenses reasonably incurred in connection therewith);

(b) such Permitted Refinancing Indebtedness has a weighted average life to maturity equal to or greater than the weighted average life to maturity of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(c) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the Notes, such Permitted Refinancing Indebtedness is subordinated in right of payment to the Notes on terms at least as favorable to the Holders as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;providedthat a certificate of an Authorized Officer of the Issuer delivered to the Intercreditor Agent and the Trustee at least five Business Days (or such shorter period as the Trustee may reasonably agree) prior to the incurrence of such Indebtedness, together with a reasonably detailed description of the material terms and conditions of such subordination terms or drafts of the documentation relating thereto, stating that the Issuer has determined in good faith that such terms and conditions satisfy the foregoing requirement shall be conclusive evidence that such terms and conditions satisfy the foregoing requirement unless the Intercreditor Agent or Trustee notifies the Issuer within such period that it disagrees with such determination (including a reasonable description of the basis upon which it disagrees);

(d) the direct or any contingent obligor with respect to such Permitted Refinancing Indebtedness is not changed from the direct or contingent obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(e) the Permitted Refinancing Indebtedness is not secured by any collateral not granted to the holders of the Indebtedness being financed, renewed, replaced, defeased or refunded; and

(f) such Permitted Refinancing Indebtedness shall have terms which shall be no more restrictive taken as a whole, and shall not, taken as a whole, be materially less favorable, in any respect on the Issuer or its subsidiaries

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than the provisions of the Indebtedness being refinanced, renewed, replaced, defeased or refunded;providedthat the foregoing requirements shall not apply to pricing terms in respect of any Indebtedness being so refinanced, renewed, replaced, defeased or refunded so long as such pricing is consistent with then-prevailing market pricing.

“Pledge Agreement” means the Pledge Agreement, dated as of April 13, 2016, by us, as pledgor, in favor of the Collateral Agent (as amended, restated, supplemented or otherwise modified from time to time).

“Pledged Debt” means all Indebtedness from time to time owed to us by OpCo, with respect to which a Lien is purported to be created under the Pledge Agreement.

“Pledged Equity” means all shares of stock and other Equity Interests in OpCo from time to time owned or acquired by us in any manner, with respect to which a Lien is purported to be created under the Pledge Agreement.

“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).

“Reference Treasury Dealer” means (a) Mizuho Securities USA Inc. or its successor, and Scotia Capital (USA) Inc. and its affiliates or successors (b) one primary U.S. Government securities dealer in New York City (a “Primary Treasury Dealer”) selected by CIBC World Markets Corp. or its successor, (c) one Primary Treasury Dealer selected by Credit Agricole Securities (USA) Inc. or its successor, (d) one Primary Treasury Dealer selected by SMBC Nikko Securities America, Inc. or its successor and (e) one other Primary Treasury Dealer selected by us.

“Reference Treasury Dealer Quotation” 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 Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker by such Reference Treasury Dealer at or before 5:00 p.m., New York City time, on the third Business Day preceding such redemption date.

“Required Secured Creditors” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“Revolving Credit Facility” means the revolving credit facility in the original principal amount of $100,000,000 made available to the Issuer under the Acquisition Facilities Credit Agreement.

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“S&P” means Standard & Poor’s Financial Services LLC, a subsidiary of The McGraw-Hill Companies, Inc., or its successors.

“Secured Debt Representative” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“Secured Hedge Agreement” means any interest rate protection agreement, interest rate option agreement, interest rate hedge agreement or other similar agreement or arrangement between one or more Hedge Providers and us designed to protect against fluctuations in interest rates that is permitted under the terms of the Secured Obligation Documents then in effect to share in the Collateral.

“Secured Hedge Obligations” means all Secured Obligations of the Issuer arising under or in connection with the Secured Hedge Agreements.

“Secured Hedge Transaction” means any interest rate hedging transaction governed by a Secured Hedge Agreement.

“Secured Obligations” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“Secured Obligation Documents” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“Secured Parties” means, collectively, the Agents, the lenders under the Credit Agreement, the Issuing Banks, the Trustee, the Holders, the Hedge Providers, the holders of Additional Senior Indebtedness or Permitted Refinancing Indebtedness, and each co-agent or sub-agent appointed by an Agent from time to time pursuant to a Credit Agreement or the Pari Passu Intercreditor Agreement, as applicable.

“Security Documents” means, collectively, the Pari Passu Intercreditor Agreement, the Pledge Agreement and, to the extent required under any Secured Obligation Document or otherwise agreed to in writing by the Issuer in its sole discretion, any other security agreements, pledge agreements or other similar agreements delivered to the Collateral Agent for the benefit of the Secured Parties that create or purport to create a Lien in favor of the Collateral Agent for the benefit of the Secured Parties.

“Senior Facilities Commitments” means any commitment or commitments to extend credit to the Issuer pursuant to any Credit Agreement.

“Senior Secured Credit Facilities” means the Acquisition Loan Facility, the Revolving Credit Facility and any Incremental Facility.

“Significant Subsidiary” means any subsidiary that would be considered a “significant subsidiary” under Article 1 of Regulation S-X under the Exchange Act.

“Subsidiary” means, with respect to any person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more than 50% of the general partnership interests are, as of such date, owned, Controlled or held, or (b) that is, as of such date, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

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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.

“Termination Date” means, except as otherwise provided in the Secured Obligation Documents: (a) the repayment in full in cash of all Secured Obligations, (b) all commitments of the Secured Parties to make loans or otherwise extend credit under any Secured Obligation Document have been terminated, and (c) all outstanding Secured Hedge Transactions shall have been terminated.

“Treasury Rate” means, with respect to any redemption date, the rate per year equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming 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.

“Unanimous Voting Parties” has the meaning assigned to such term in the Pari Passu Intercreditor Agreement.

“U.S. Bankruptcy Code” means the United States Bankruptcy Reform Act of 1978, as heretofore and hereafter amended, and codified as 11 U.S.C. Section 101 et seq.

“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).

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REGISTRATION RIGHTS AGREEMENT

We entered into a registration rights agreement with the initial purchasers on May 17, 2016 in connection with the closing of the private offering of the Outstanding Notes. In that agreement, we agreed for the benefit of the holders of the Outstanding Notes that we will use our reasonable best efforts to file with the Commission and cause to become effective a registration statement relating to an offer to exchange the notes for an issue of Commission-registered notes with terms identical to the notes (except that the Exchange Notes are not subject to restrictions on transfer or to any increase in annual interest rate as described below).

If applicable interpretations of the staff of the Commission do not permit us to effect the exchange offer, we are required to use our reasonable best efforts to cause to become effective a shelf registration statement relating to resales of the notes and to keep that shelf registration statement effective for a period of two years following the effective date of such shelf registration statement, or if earlier, the date on which all notes covered by the shelf registration statement have been sold. We will, in the event of such a shelf registration, provide to each outstanding noteholder copies of the prospectus that is a part of the shelf registration statement, notify each noteholder when the shelf registration statement has become effective and take certain other actions to permit resales of the notes. A noteholder that sells notes under the shelf registration statement generally 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 noteholder (including certain indemnification obligations).

Pursuant to the terms of the registration rights agreement, we agreed to use commercially reasonable efforts to (a) as soon as practicable after the closing of the private offering, but in any event before December 13, 2016, file a registration statement on an appropriate registration form with respect to registered offers to exchange the Outstanding Notes for Exchange Notes, (b) cause the registration statement to be declared effective under the Securities Act before February 13, 2017 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. 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 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.

Our initial Registration Default under the registration rights agreement occurred on December 13, 2016 due to the fact that we did not file the required registration statement within 210 days of May 17, 2016. This Registration Default triggered additional interest to accrue on the Outstanding Notes in an amount of 0.25% per annum. Our second Registration Default occurred on February 13, 2017 due to the fact that we did not cause a registration statement to be declared effective under the Securities Act within 270 days of May 17, 2016. Beginning March 13, 2017, 90 days after the initial Registration Default, the amount of additional interest on the Outstanding Notes will increase and begin to accrue at 0.50% per annum. Additional interest will continue to accrue on the Outstanding Notes until the registration statement, of which this prospectus forms a part, is declared effective.

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If we effect the exchange offer, we will be entitled to close the exchange offer not earlier than 20 business days after its commencement, provided that we have accepted all notes validly surrendered in accordance with the terms of the exchange offer. Notes not tendered in the exchange offer shall bear interest at the rate set forth on the cover page of this prospectus (plus additional interest as set forth above until the date that the registration statement, of which this prospectus forms a part, is declared effective) and be subject to all the terms and conditions specified in the indenture, including transfer restrictions.

The preceding is a summary of the material terms and provisions of the registration rights agreement. A copy of the registration rights agreement is incorporated by reference as an exhibit to the registration statement of which this prospectus is a part.

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain material United States federal income tax considerations that may be relevant to the exchange of Outstanding Notes for Exchange Notes and to the ownership and disposition of the Exchange Notes, but does not purport to be an analysis of all potential tax effects. This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary, and proposed Treasury Regulations, all as in effect on the date hereof and all of which are subject to change, possibly with retroactive effect, or to different interpretations, and any such change or differing interpretations could affect the accuracy of the statements and conclusions set forth herein. We have not sought and will not seek any rulings from the U.S. Internal Revenue Service (the “IRS”) regarding the matters discussed below. Accordingly, there can be no assurance that the IRS or a court will not take a different position concerning the tax consequences described below.

This summary applies only to holders that are beneficial owners of Outstanding Notes that purchased the Outstanding Notes in the initial offering at their original “issue price” (the first price at which a substantial amount of the notes is sold for cash (excluding sales to bond houses, brokers, or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers)) for cash and that hold such notes as “capital assets” within the meaning of Section 1221 of the Code (generally, property held for investment). This summary does not address the tax considerations that may be relevant to subsequent purchasers of the Outstanding Notes or Exchange Notes. This summary does not discuss all aspects of United States federal income taxation that may be relevant to holders in light of their particular circumstances or status, or that may be relevant to holders subject to special tax rules under the United States federal income tax laws (including, for example, financial institutions, broker-dealers, traders in securities that elect mark-to-market tax treatment, corporations treated as personal holding companies, regulated insurance companies, insurance companies, real estate investment trusts, controlled foreign corporations, passive foreign investment companies,tax-exempt organizations, governmental organizations, dealers in securities or currencies, partnerships, S corporations and other pass-through entities and investors in such entities, persons subject to alternative minimum tax, persons holding the notes as a part of a hedge, straddle, conversion, constructive sale, or other integrated transaction, U.S. holders (as defined below) whose functional currency is not the U.S. dollar, or former U.S. citizens or long-term residents subject to taxation as expatriates under Section 877 of the Code). This summary also does not discuss any tax consequences arising under other United States federal tax laws (including estate and gift tax laws) or the law of any state, local, foreign or other taxing jurisdiction.

If a partnership (including any entity treated as a partnership for United States federal income tax purposes) is a beneficial owner of a note, the tax treatment of a partner in that partnership will generally depend on the status of the partner and the activities of the partnership. Holders of notes that are partnerships and partners in those partnerships are urged to consult their tax advisors regarding the United States federal income tax consequences of the exchange of Outstanding Notes for Exchange Notes and of the ownership and disposition of the Exchange Notes.

THIS SUMMARY IS FOR GENERAL INFORMATION ONLY AND IS NOT INTENDED TO CONSTITUTE A COMPLETE DESCRIPTION OF ALL TAX CONSEQUENCES RELATING TO THE EXCHANGE OF THE OUTSTANDING NOTES FOR THE EXCHANGE NOTES AND OF THE OWNERSHIP AND DISPOSITION OF THE EXCHANGE NOTES. YOU SHOULD CONSULT YOUR OWN TAX ADVISOR REGARDING THE APPLICATION OF U.S. FEDERAL INCOME TAX LAWS TO YOUR PARTICULAR SITUATION AND THE CONSEQUENCES OF OTHER FEDERAL TAX LAWS (INCLUDING ESTATE AND GIFT TAX LAWS) AND THE LAWS OF ANY STATE, LOCAL, FOREIGN, OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY AND THE POSSIBLE EFFECT OF CHANGES IN THESE TAX LAWS.

As used this summary, the term “U.S. holder” means a beneficial owner of a note that is for United States federal income tax purposes: (i) an individual who is a citizen or resident of the United States, (ii) a corporation

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(including an entity treated as a corporation for United States federal income tax purposes) created or organized in or under the laws of the United States or of any political subdivision thereof, (iii) an estate, the income of which is subject to United States federal income tax regardless of its source, or (iv) a trust, (a) if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or (b) if a valid election is in place to treat the trust as a United States person.

As used in this summary, the term“non-U.S. holder” means a beneficial owner of a note (other than a partnership) that is not a U.S. holder.

Tax Consequences to U.S. Holders

Exchange Offer

The exchange of the Outstanding Notes for the Exchange Notes in connection with the exchange offer will not be treated as a taxable sale or exchange for United States federal income tax purposes. Accordingly,

• U.S. holders will not recognize taxable gain or loss as a result of the exchange;

• the adjusted tax basis of an Exchange Note immediately after the exchange will be the same as the adjusted tax basis of the Outstanding Note exchanged therefor immediately before the exchange;

• the holding period of the Exchange Note will include the holding period of the Outstanding Note; and

• any original issue discount, acquisition premium, market discount or bond premium applicable to the Outstanding Notes will carry over to the Exchange Notes.

Interest on the Notes

Stated interest on the notes will generally be included in the income of a U.S. holder as ordinary interest income at the time such interest is received or accrued in accordance with a holder’s regular method of accounting for United States federal income tax purposes.

Market Discount

If a U.S. holder acquired an Outstanding Note (which will be exchanged for an Exchange Note pursuant to the exchange offer) for an amount that is less than its adjusted issue price, the difference will be treated as “market discount” (unless such difference is less than a statutorily definedde minimis amount) for United States federal income tax purposes. Any market discount applicable to an Outstanding Note will carry over to the Exchange Note received in the exchange for such original Outstanding Note. The rules described below do not apply to a U.S. holder who purchased an Outstanding Note that has a de minimis market discount.

Under the market discount rules, a U.S. holder will be required to treat any full or partial principal payment on, or any gain on the sale, exchange, redemption, retirement, or other taxable disposition of, an Exchange Note as ordinary income to the extent of any accrued market discount (on the Outstanding Note or the Exchange Note) that has not previously been included in income. If a U.S. holder disposes of an Exchange Note in certain otherwise nontaxable transactions, such U.S. holder must include any accrued market discount as ordinary income as if the U.S. holder had sold the Exchange Note at its then fair market value. The amount of market discount treated as having accrued will be determined either:

• on astraight-line basis by multiplying the market discount times a fraction, the numerator of which is the number of days the note was held by the holder and the denominator of which is the total number of days after the date such holder acquired the note up to, and including, the note’s maturity date; or

• if the holder so elects, on the basis of a constant rate of compound interest.

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A U.S. holder of an Exchange Note subject to the market discount rules may elect to include market discount in income currently, through the use of either thestraight-line inclusion method or the elective constant interest rate method, in lieu of recharacterizing gain upon disposition as ordinary income to the extent of accrued market discount at the time of disposition. Once made, this election will apply to all debt instruments with market discount acquired by the electing U.S. holder on or after the first day of the first taxable year to which the election applies and may not be revoked without the consent of the IRS. If an election is made to include market discount on a debt instrument in income currently, the basis of the debt instrument in the hands of the U.S. holder will be increased by the market discount thereon as it is included in income. U.S. holders should consult their own tax advisors before making this election.

A U.S. holder who does not elect to include the market discount on an Exchange Note in income currently may be required to defer interest expense deductions for a portion of the interest paid on indebtedness incurred or continued to purchase or carry such note, until the maturity of the note, its earlier disposition in a taxable transaction or, if the U.S. holder so elects, a subsequent taxable year in which sufficient income exists with respect to the Exchange Note.

Amortizable Bond Premium

If a U.S. holder purchased an Outstanding Note (which will be exchanged for an Exchange Note pursuant to the exchange offer) for an amount in excess of its principal amount, the excess will be treated as “bond premium.” Any bond premium applicable to an Outstanding Note will carry over to the Exchange Note received in exchange for such Outstanding Note. In general, a U.S. holder may elect to amortize bond premium by offsetting stated interest allocable to an accrual period with the premium allocable to that period at the time that the U.S. holder takes the interest into account under the U.S. holder’s regular method of accounting for United States federal income tax purposes. Bond premium is allocable to an accrual period on a constant yield basis. Because the Exchange Notes are redeemable at our option (see “Description of Exchange Notes—Optional Redemption”), special rules will apply which require a U.S. holder to determine the yield and maturity of the Exchange Notes for purposes of calculating and amortizing bond premium by assuming that we will exercise our option to redeem the U.S. holder’s notes in a manner that maximizes the U.S. holder’s yield. If we do not exercise our option to redeem the Exchange Notes in the manner assumed, then solely for purposes of calculating and amortizing any remaining bond premium, the U.S. holder must treat the Exchange Note as retired and reissued on the deemed redemption date for its adjusted acquisition price as of that date. The adjusted acquisition price of the Exchange Note is the U.S. holder’s initial investment in the Exchange Note or the Outstanding Note, decreased by the amount of any payments, other than qualified stated interest payments, received with respect to such note and any bond premium previously amortized by the U.S. holder. Under Treasury Regulations, the amount of amortizable bond premium that a U.S. holder may deduct in any accrual period is limited to the amount by which the U.S. holder’s total interest inclusions on the note in prior accrual periods exceed the total amount treated by the U.S. holder as a bond premium deduction in prior accrual periods. If any of the excess bond premium is not deductible, that amount is carried forward to the next accrual period.

A U.S. holder who elects to amortize bond premium must reduce the U.S. holder’s tax basis in the note by the amount of the premium used to offset interest income as set forth above. Once made, the election to amortize bond premium on a constant yield method applies to all debt instruments (other than debt instruments the interest on which is excludable from gross income) held or subsequently acquired by the U.S. holder on or after the first day of the first taxable year to which the election applies and may not be revoked without the consent of the IRS. U.S. holders should consult their own tax advisors concerning the computation and amortization of any bond premium on the Exchange Notes.

Sale, Redemption, Retirement, or Other Taxable Disposition of the Notes

A U.S. holder of an Exchange Note will generally recognize gain or loss upon the sale, redemption, retirement, or other taxable disposition of the note equal to the difference between (i) the sum of cash and the fair

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market value of any property received (except to the extent attributable to accrued interest) and (ii) the U.S. holder’s adjusted tax basis in the note. A U.S. holder’s adjusted tax basis in a note generally will equal such U.S. holder’s initial investment in the note, increased by the amount of original issue discount and any accrued market discount previously included in income and decreased (but not below zero) by the amount of any payments, other than qualified stated interest payments, received with respect to such note and any amortized bond premium. If a U.S. holder disposes of a note between interest payment dates, a portion of the amount received represents stated interest accrued to the date of disposition and must be reported as ordinary interest income, and not as proceeds from the disposition, in accordance with the U.S. holder’s regular method of accounting for federal income tax purposes as described above under “—Interest on the Notes.” Subject to the market discount rules discussed above, any gain or loss recognized by a U.S. holder on the disposition of a note generally will be capital gain or loss and will belong-term capital gain or loss if the U.S. holder’s holding period is more than one year. Long-term capital gains of non-corporate U.S. holders generally are eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations.

Medicare Tax

Certain U.S. holders that are individuals, estates, or trusts are subject to a 3.8% tax on their net investment income, which generally includes interest (including interest paid with respect to a note), dividends, annuities, royalties, rents, net gain attributable to the disposition of property not held in a trade or business (including net gain from the sale, exchange, redemption, or other taxable disposition of a note) and certain other income, but will be reduced by any deductions properly allocable to such income or net gain. If you are a U.S. holder that is an individual, estate, or trust, you are urged to consult your tax advisors regarding the applicability of the Medicare tax to your income and gains in respect of your investment in the notes.

Tax Consequences toNon-U.S. Holders

Exchange Offer

The exchange of the Outstanding Notes for the Exchange Notes in connection with the exchange offer will not be treated as a taxable sale or exchange for United States federal income tax purposes.

Interest on the Notes

Subject to the discussion below concerning effectively connected income, backup withholding, and FATCA, payments of interest (including original issue discount) on the notes to a non-U.S. holder generally will be exempt from U.S. federal income and withholding tax under the “portfolio interest” exemption if: (i) the non-U.S. holder does not own actually or constructively 10% or more of the total combined voting power of the Company; (ii) the non-U.S. holder is not a controlled foreign corporation related to the Company through the actual or constructive stock ownership rules of the Code; (iii) the non-U.S. holder is not a bank whose receipt of interest on the notes is described in Section 881(c)(3)(A) of the Code; and (iv) either (a) the non-U.S. holder certifies, under penalties of perjury, to us or our paying agent on an IRS FormW-8BEN orW-8BEN-E, as applicable (or other applicable form), that the non-U.S. holder is not a United States person and provides certain other information or satisfies certain other certification requirements, or (b) a financial institution holding the notes on the non-U.S. holder’s behalf certifies, under penalty of perjury, that it has received an IRS FormW-8BEN orW-8BEN-E, as applicable (or other applicable form) from the beneficial owner and provides a copy or, in the case of certain foreign intermediaries, satisfies other certification requirements under the applicable Treasury Regulations. Special certification requirements apply to certainnon-U.S. holders that are entities.

If anon-U.S. holder cannot satisfy the requirements described above, payments of interest made to the non-U.S. holder will be subject to the United States federal withholding tax, currently at a 30% rate, unless the non-U.S. holder provides us with either (i) a properly executed IRS Form W-8BEN or W-8BEN-E (or appropriate substitute form) claiming an exemption from or reduction in withholding under the benefit of an applicable

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income tax treaty, or (ii) a properly executed IRS Form W-8ECI (or appropriate substitute form) stating that interest paid or accrued on the notes is not subject to withholding tax because it is effectively connected with the conduct of a trade or business in the United States and is includible in such non-U.S. holder’s gross income.

Anon-U.S. holder eligible for a reduced rate of United States withholding tax pursuant to an income tax treaty may obtain a refund of any excess amounts withheld by filing an appropriate claim for refund with the IRS.

Sale, Redemption, Retirement, or Other Taxable Disposition of the Notes

Subject to the discussion below concerning effectively connected income, backup withholding, and FATCA, anon-U.S. holder will not be subject to United States federal income tax on any gain realized on the sale, redemption, retirement, or other taxable disposition of a note (other than amounts attributable to accrued and unpaid interest, which will be treated as described above under “—Interest on the Notes”) unless (i) the gain is effectively connected with the conduct by the non-U.S. holder of a U.S. trade or business, or (ii)thenon-U.S. holder is an individual who is present in the U.S. for at least 183 days during the year of disposition of the note and other conditions are satisfied.

If you are a non-U.S. holder described in subparagraph (i) above, you generally will be subject to U.S. federal income tax as described below (see “—Effectively Connected Income”). If you are a non-U.S. holder described in the second bullet point above, you generally will be subject to U.S. federal income tax at a flat 30% rate (or a lower applicable income tax treaty rate) on the gain derived from the disposition, which may be offset by certain U.S.-source capital losses recognized in such taxable year.

Effectively Connected Income

If anon-U.S. holder is engaged in a trade or business in the United States and the non-U.S. holder’s investment in a note is effectively connected with such trade or business, then the non-U.S. holder will be exempt from the 30% withholding tax on interest (provided a certification requirement, generally on IRS FormW-8ECI, is met), but will instead generally be subject to regular United States federal income tax on a net income basis on any interest and gain with respect to the notes in the same manner as if the holder were a U.S. holder (unless an applicable income tax treaty provides otherwise). In addition, if thenon-U.S. holder is a foreign corporation, that portion of the non-U.S. holder’s earnings and profits that is attributable to such effectively connected income or gain, subject to certain adjustments, may be subject to a “branch profits tax” at a 30% rate (or the lower rate provided by an applicable income tax treaty). If anon-U.S. holder is eligible for the benefits of a tax treaty, any effectively connected income or gain will generally be subject to United States federal income tax only if it is also attributable to a permanent establishment maintained by the holder in the United States.

Information Reporting and Backup Withholding

U.S. holders. Payments of interest (including original issue discount) and principal on, and proceeds received from a sale, exchange, retirement, redemption, or other taxable disposition of, a note generally will be reported to the IRS. In addition, a backup withholding tax (currently at a rate of 28%) may apply to such payments or proceeds if the U.S. holder fails to furnish the payor with a correct taxpayer identification number or other required certification or if it has been notified by the IRS that it is subject to backup withholding for failing to report interest or dividends required to be shown on the holder’s federal income tax returns. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be allowed as a refund or credit against that U.S. holder’s U.S. federal income tax liability provided the required information is timely furnished to the IRS.

Non-U.S. holders.Payments of interest (including original issue discount) paid to anon-U.S. holder generally must be reported annually to the holder and the IRS. Copies of these information returns may also be

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made available under the provisions of a specific treaty or other agreement to the tax authorities of the country in which thenon-U.S. holder resides. In general, anon-U.S. holder will not be subject to backup withholding (currently at a rate of 28%) with respect to interest or principal payments on the notes if such holder has provided the statement described above under “–United States Federal Income Tax Consequences toNon-U.S. Holders—Interest Payments on the Notes” and the payor does not have actual knowledge or reason to know that such holder is a U.S. person. In addition, anon-U.S. holder will not be subject to backup withholding with respect to the proceeds of the sale of a note (including on redemption or retirement) made within the United States or conducted through certain United States financial intermediaries if the payor receives the statement described above and does not have actual knowledge or reason to know that such non-U.S. holder is a United States person or such non-U.S. holder otherwise establishes an exemption. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to anon-U.S. holder will be allowed as a credit against such non-U.S. holder’s U.S. federal income tax liability, if any, and may entitle such holder to a refund, provided that the required information is timely furnished to the IRS.Non-U.S. holders should consult their tax advisors regarding the application of information reporting and backup withholding in their particular situations, the availability of exemptions and the procedure for obtaining such exemptions, if available.

Foreign Account Tax Compliance

The Foreign Account Tax Compliance Act, together with administrative guidance and certain intergovernmental agreements entered into thereunder (“FATCA”), generally imposes a 30% U.S. withholding tax on certain U.S. source payments, including interest (and original issue discount) on the Exchange Notes, and, after December 31, 2018, on gross proceeds from a disposition of property of a type which can produce U.S. source interest (such as the Exchange Notes), paid to a foreign financial institution, or to a non-financial foreign entity, unless (a) the foreign financial institution agrees to comply with certain diligence, reporting and withholding obligations with respect to its U.S. accounts, (b) a non-financial foreign entity identifies and provides information relating to its 10% or greater U.S. owners (or confirms the absence of substantial U.S. owners), or (c) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. Certain countries have entered into, and other countries are expected to enter into, agreements with the United States to facilitate the type of information reporting required under FATCA. Such intergovernmental agreements may provide different rules with respect tonon-U.S. financial institutions. The 30% withholding tax under FATCA applies regardless of whether the foreign financial institution or non-financial foreign entity receives payments as a beneficial owner or intermediary and whether the applicable payment otherwise is exempt from U.S. withholding (e.g., as “portfolio interest” or as capital gain upon the sale, exchange, redemption or other disposition of an Exchange Note).

As a result, non-U.S. holders may receive less interest or principal than expected with respect to the Exchange Notes. We will not pay any additional amounts with respect to any withholding tax imposed pursuant to FATCA. Non-U.S. Holders are urged to consult their own tax advisors with respect to these information reporting rules and due diligence requirements and the potential application of FATCA to them.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of those Exchange Notes. 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 those Outstanding Notes as a result of market-making activities or other trading activities. We have agreed that for a period of 180 days after the expiration date of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with those resales.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers. Broker-dealers may sell Exchange Notes received by them for their own account pursuant to the exchange offer 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 those methods of resale, at market prices prevailing at the time of resale, at prices related to prevailing market prices or negotiated prices. Any 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 broker-dealer or the purchasers of any 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 those Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act. A profit on any resale of those Exchange Notes and any commissions or concessions received by any of those persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the expiration date of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests these documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer, including the expenses of one counsel for the holders of the Outstanding Notes, other than commissions or concessions of any brokers or dealers and will indemnify the holders of the Outstanding Notes, including any broker-dealers, against specified liabilities, including liabilities under the Securities Act.

You should be aware that the laws and practices of certain countries require investors to pay stamp taxes and other charges in connection with purchases of securities.

The trustee and its affiliates perform various financial advisory, investment banking and commercial banking services from time to time for us and our affiliates, for which they receive customary fees. Wells Fargo Bank, N.A. is the Trustee and exchange agent in connection with the exchange offer.

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LEGAL MATTERS

The validity of the Exchange Notes offered hereby will be passed upon for us by Locke Lord LLP, Houston, Texas. Locke Lord LLP will deliver an opinion stating that the notes will be binding obligations of Cleco. In rendering its opinion, Locke Lord LLP will rely on the opinion of Baker, Donelson, Bearman, Caldwell & Berkowitz, PC, New Orleans, Louisiana, with respect to certain matters regarding Louisiana law.

EXPERTS

The financial statements as of December 31, 2016 and for the period April 13, 2016 to December 31, 2016 (Successor) included in this Prospectus and the financial statement schedules as of December 31, 2016 and for the period April 13, 2016 to December 31, 2016 (Successor) included in the Registration Statement for Cleco Corporate Holdings LLC 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. Such financial statements and financial statement schedules have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements for the period January 1, 2016 to April 12, 2016 (Predecessor) included in this Prospectus and the financial statement schedules for the period January 1, 2016 to April 12, 2016 (Predecessor) included in the Registration Statement for Cleco Corporation 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. Such financial statements and financial statement schedules have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements as of December 31, 2016 and for the year ended December 31, 2016 included in this Prospectus and the financial statement schedule included in the Registration Statement for Cleco Power LLC 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. Such financial statements and financial statement schedule have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements as of December 31, 2015 and 2014, and for each of the two years in the period ended December 31, 2015, included in this Prospectus and the related financial statement schedules included elsewhere in the Registration Statement for Cleco Corporate Holdings LLC (formerly Cleco Corporation), have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and elsewhere in the Registration Statement. Such financial statements and financial statement schedules have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements as of December 31, 2015 and 2014, and for each of the two years in the period ended December 31, 2015, included in this Prospectus and the related financial statement schedule included elsewhere in the Registration Statement for Cleco Power LLC, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and elsewhere in the Registration Statement. Such financial statements and financial statement schedule have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

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. As permitted by the rules and regulations of the Commission, this

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prospectus incorporates important information about us that is not included in or delivered with this prospectus but that is included in the registration statement. 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 Transactions, 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. Such reports and other information filed by us may be read and copied at the Commission’s public reference room at 100 F Street, NE, Washington, D.C. 20549. For further information about the public reference room, call 1-800-SEC-0330. 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 athttp://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                 , 2017 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 this 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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EXCHANGE AGENT

We have appointed Wells Fargo Bank, N.A. as exchange agent in connection with the exchange offer. Holders should direct questions, requests for assistance or additional copies of the prospectus, letters of transmittal or notices of guaranteed delivery to the exchange agent as follows:

By Air Courier Service:	By Registered or Certified Mail:
Wells Fargo Bank, N.A. Corporate Trust Operations MAC N9300-070 600 Fourth Street South, 7th Floor Minneapolis, MN 55479	Wells Fargo Bank, N.A. Corporate Trust Operations MAC N9300-070 PO BOX 1517 Minneapolis, MN 55480-1517
By Facsimile Transmission: 612-667-6282

For Information or Confirmation by Telephone:

1-800-344-5128

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.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Management’s Reports on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firms	F-3
Report of Independent Registered Public Accounting Firms	F-3
Report of Independent Registered Public Accounting Firms	F-4
Financial Statements of Cleco
Consolidated Statements of Income for the years ended December 31, 2016, 2015, and 2014	F-5
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015, and 2014	F-6
Consolidated Balance Sheets at December 31, 2016, and 2015	F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015, and 2014	F-9
Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015, and 2014	F-11
Report of Independent Registered Public Accounting Firms	F-12
Report of Independent Registered Public Accounting Firms	F-13
Financial Statements of Cleco Power
Cleco Power Consolidated Statements of Income for the years ended December 31, 2016, 2015, and 2014	F-14
Cleco Power Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015, and 2014	F-15
Cleco Power Consolidated Balance Sheets at December 31, 2016, and 2015	F-16
Cleco Power Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015, and 2014	F-18
Cleco Power Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015, and 2014	F-20
Notes to the 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, 2016, 2015, and 2014	F-83
Condensed Statements of Comprehensive Income for the years ended December 31, 2016, 2015, and 2014	F-84
Condensed Balance Sheets at December 31, 2016, and 2015	F-85
Condensed Statements of Cash Flows for the years ended December 31, 2016, 2015, and 2014	F-86
Notes to the Condensed Financial Statements	F-87
Schedule II—Valuation and Qualifying Accounts	F-90
Cleco	F-90
Cleco Power	F-91
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

Management’s Reports on Internal Control Over Financial Reporting

The management of Cleco and Cleco Power is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act. Cleco and Cleco Power’s internal control over financial reporting is a process designed by, or under the supervision of, each of Cleco and Cleco Power’s principal executive and financial officers and effected by Cleco and Cleco Power’s board of managers, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes.

Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements. Management’s assessments included review and testing of both the design effectiveness and operating effectiveness of controls over relevant assertions related to significant accounts and disclosures in the financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even

those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

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

The management of Cleco and Cleco Power, under the supervision of each of the Registrants’ principal executive officer and principal financial officer, conducted an assessment of the effectiveness of Cleco and Cleco Power’s respective internal control over financial reporting as of December 31, 2016. 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 and Cleco Power concluded that, as of December 31, 2016, the Registrants’ internal control over financial reporting was effective.

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Managers of

Cleco Corporate Holdings LLC

Pineville, Louisiana

In our opinion, the accompanying consolidated statements listed in the index appearing under item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Corporate Holdings, LLC and its subsidiaries (the “Company”) as of December 31, 2016 and the results of their operations and their cash flows for the period April 13, 2016 to December 31, 2016 (Successor) in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) as of December 31, 2016 and for the period of April 13, 2016 to December 31, 2016 presents fairly, in all material respects, the information set forth therein when read in conjunction with the consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the

Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audit. We conducted our audit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

February 22, 2017

Report of Independent Registered Public Accounting Firm

To the Board of Managers of

Cleco Corporate Holdings LLC

Pineville, Louisiana

In our opinion, the accompanying consolidated statement of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the results of operations and their cash flows for the period January 1, 2016 to April 12, 2016 (Predecessor) for Cleco Corporation and its subsidiaries (the “Company”) in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) for the period January 1, 2016 to April 12, 2016 presents fairly, in all material respects, the information set forth therein when read in conjunction with the consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and

financial statement schedules based on our audit. We conducted our audit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

February 22, 2017

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Managers of

Cleco Corporate Holdings LLC

Pineville, Louisiana

We have audited the accompanying consolidated balance sheet of Cleco Corporate Holdings LLC (formerly Cleco Corporation) and subsidiaries (the “Company”) as of December 31, 2015, and the related consolidated statements of income, comprehensive income, cash flows and changes in equity for the years ended December 31, 2015 and 2014. Our audits also included the financial statement schedules as of December 31, 2015 and for the years ended December 31, 2015 and 2014 listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the

financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cleco Corporate Holdings LLC and subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the years ended December 31, 2015 and 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules as of December 31, 2015 and for the years ended December 31, 2015 and 2014, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

New Orleans, Louisiana

February 26, 2016

F-4

CLECO

Consolidated Statements of Income

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016- DEC. 31, 2016			JAN. 1, 2016- APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Operating revenue
Electric operations	$	802,592		$	281,154		$	1,142,389		$	1,225,960
Other operations		51,562			19,080			69,186			67,055
Gross operating revenue		854,154			300,234			1,211,575			1,293,015
Electric customer credits		(1,149	)		(364	)		(2,173	)		(23,530	)
Operating revenue, net		853,005			299,870			1,209,402			1,269,485
Operating expenses
Fuel used for electric generation		250,142			96,378			373,117			322,696
Power purchased for utility customers		92,337			27,249			130,095			242,219
Other operations		90,313			33,563			127,410			117,369
Maintenance		63,944			29,813			88,137			98,999
Depreciation and amortization		109,739			44,076			149,579			146,505
Taxes other than income taxes		35,543			14,611			49,134			43,924
Merger transaction and commitment costs		174,696			34,912			4,591			17,848
Gain on sales of assets		—			(1,095	)		—			(6,107	)
Total operating expenses		816,714			279,507			922,063			983,453
Operating income		36,291			20,363			287,339			286,032
Interest income		840			265			895			1,768
Allowance for equity funds used during construction		3,735			723			3,063			5,380
Other income		3,350			870			1,443			4,790
Other expense		(1,385	)		(590	)		(3,376	)		(2,509	)
Interest charges
Interest charges, including amortization of debt issuance costs, premiums, and discounts, net		90,852			22,330			78,877			75,186
Allowance for borrowed funds used during construction		(1,086	)		(207	)		(886	)		(1,580	)
Total interest charges		89,766			22,123			77,991			73,606
(Loss) income before income taxes		(46,935	)		(492	)		211,373			221,855
Federal and state income tax (benefit) expense		(22,822	)		3,468			77,704			67,116
Net (loss) income	$	(24,113	)	$	(3,960	)	$	133,669		$	154,739

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-5

CLECO

Consolidated Statements of Comprehensive Income

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016- DEC. 31, 2016			JAN. 1, 2016- APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Net (loss) income	$	(24,113	)	$	(3,960	)	$	133,669	$	154,739
Other comprehensive income (loss), net of tax
Postretirement benefits gain (loss) (net of tax expense of $938, $367, and $3,670 and tax benefit of $4,378, respectively)		1,500			587			5,869		(7,001	)
Net gain on cash flow hedges (net of tax expense of $0, $37, $132, and $132, respectively)		—			60			211		212
Total other comprehensive income (loss), net of tax		1,500			647			6,080		(6,789	)
Comprehensive (Ioss) income, net of tax	$	(22,613	)	$	(3,313	)	$	139,749	$	147,950

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-6

CLECO

Consolidated Balance Sheets

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	23,077		$	68,246
Restricted cash and cash equivalents		23,084			9,263
Customer accounts receivable (less allowance for doubtful accounts of $7,199 in 2016 and $2,674 in 2015)		56,780			43,255
Other accounts receivable		19,778			27,677
Unbilled revenue		34,268			33,995
Fuel inventory, at average cost		46,410			72,838
Materials and supplies, at average cost		81,818			76,731
Energy risk management assets		7,884			7,673
Accumulated deferred fuel		20,787			12,910
Cash surrender value of company-/trust-owned life insurance policies		77,225			73,823
Prepayments		7,813			7,883
Regulatory assets		26,803			14,117
Other current assets		1,315			448
Total current assets		427,042			448,859
Property, plant, and equipment
Property, plant, and equipment		3,476,581			4,661,212
Accumulated depreciation		(75,816	)		(1,536,158	)
Net property, plant, and equipment		3,400,765			3,125,054
Construction work in progress		78,577			66,509
Total property, plant, and equipment, net		3,479,342			3,191,563
Equity investment in investee		18,672			16,822
Goodwill		1,490,797			—
Prepayments		4,731			4,542
Restricted cash and cash equivalents		23,410			16,195
Regulatory assets—deferred taxes, net		237,449			236,941
Regulatory assets		454,644			284,689
Net investment in direct financing lease		13,420			13,464
Intangible assets		142,634			74,963
Tax credit fund investment, net		11,888			13,741
Other deferred charges		39,115			21,575
Total assets	$	6,343,144		$	4,323,354

The accompanying notes are an integral part of the Consolidated Financial Statements.

(Continued on next page)

F-7

CLECO

Consolidated Balance Sheets

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Liabilities and member’s equity/shareholders’ equity
Liabilities
Current liabilities
Long-term debt due within one year	$	19,715		$	19,421
Accounts payable		112,087			93,822
Customer deposits		56,599			55,233
Provision for rate refund		3,974			2,696
Provision for merger commitments		14,371			—
Taxes payable		3,942			2,573
Interest accrued		14,783			7,814
Energy risk management liabilities		201			275
Regulatory liabilities—other		—			312
Deferred compensation		11,654			10,156
Other current liabilities		14,850			14,277
Total current liabilities		252,176			206,579
Long-term liabilities and deferred credits
Accumulated deferred federal and state income taxes, net		1,033,055			925,103
Accumulated deferred investment tax credits		2,751			3,245
Postretirement benefit obligations		223,003			205,036
Restricted storm reserve		17,385			16,177
Other deferred credits		29,440			24,670
Total long-term liabilities and deferred credits		1,305,634			1,174,231
Long-term debt, net		2,738,571			1,267,703
Total liabilities		4,296,381			2,648,513
Commitments and contingencies (Note 15)
Member’s equity/Shareholders’ equity
Member’s equity/Common shareholders’ equity
Membership interest/Common stock(1)		2,069,376			456,412
(Accumulated deficit)/Retained earnings		(24,113	)		1,245,014
Accumulated other comprehensive income (loss)		1,500			(26,585	)
Total member’s equity/common shareholders’ equity		2,046,763			1,674,841
Total liabilities and member’s equity/shareholders’ equity	$	6,343,144		$	4,323,354

(1) At December 31, 2015, shareholders’ equity included $418.5 million of premium on common stock, $61.1 million of common stock, and $23.2 million of treasury stock. At December 31, 2015, Cleco had 100,000,000 shares of common stock authorized, 61,058,918 shares of common stock issued, and 60,482,468 shares of common stock outstanding, par value $1 per share. At December 31, 2015, Cleco had 576,450 shares of treasury stock.

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-8

CLECO

Consolidated Statements of Cash Flows

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Operating activities
Net (loss) income	$	(24,113	)	$	(3,960	)	$	133,669		$	154,739
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation and amortization		141,544			45,869			156,211			156,590
Gain on sales of assets		—			(1,095	)		—			(6,224	)
Provision for doubtful accounts		4,473			1,212			3,464			2,994
Unearned compensation expense		1,147			3,276			6,344			6,545
Allowance for equity funds used during construction		(3,735	)		(723	)		(3,063	)		(5,380	)
Net deferred income taxes		(21,053	)		2,219			74,103			63,597
Deferred fuel costs		(8,192	)		977			9,899			(11,558	)
Cash surrender value of company-/trust-owned life insurance		(2,561	)		(840	)		950			(3,616	)
Provision for merger commitments		21,964			—			—			—
Changes in assets and liabilities
Accounts receivable		(21,537	)		(1,865	)		(13,656	)		11,556
Unbilled revenue		(837	)		563			4,481			(7,310	)
Fuel inventory and materials and supplies		2,880			19,312			(13,698	)		(12,147	)
Prepayments		(2,514	)		2,395			2,750			27
Accounts payable		5,183			8,348			(25,294	)		4,481
Customer deposits		7,333			3,342			12,162			14,960
Postretirement benefit obligations		3,750			9,746			14,173			8,864
Regulatory assets and liabilities, net		13,750			5,178			18,793			(777	)
Other deferred accounts		(28,010	)		6,878			(17,454	)		(14,691	)
Taxes accrued		(24,210	)		10,820			(831	)		(22,685	)
Interest accrued		(11,104	)		17,909			(1,024	)		(3,519	)
Deferred compensation		(799	)		(793	)		(1,166	)		332
Other operating		(2,037	)		1,012			209			(1,609	)
Net cash provided by operating activities		51,322			129,780			361,022			335,169

The accompanying notes are an integral part of the Consolidated Financial Statements.

(Continued on next page)

F-9

CLECO

Consolidated Statements of Cash Flows

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Investing activities
Additions to property, plant, and equipment		(144,444	)		(42,392	)		(156,819	)		(207,636	)
Allowance for equity funds used during construction		3,735			723			3,063			5,380
Proceeds from sale of property		766			1,932			—			9,316
Reimbursement for property loss		3,159			53			—			191
Contributions to equity investment in investee		—			(2,450	)		(2,290	)		—
Premiums paid on trust-owned life insurance		—			—			(3,607	)		(2,831	)
Return of equity investment in tax credit fund		901			476			2,128			2,579
Contributions to tax credit fund		—			—			(9,966	)		(55,315	)
Transfer of cash (to) from restricted accounts, net		(25,884	)		4,847			(1,341	)		(10,097	)
Sale of restricted investments		—			—			—			11,138
Maturity of restricted investments		—			—			—			1,458
Other investing		622			—			881			(697	)
Net cash used in investing activities		(161,145	)		(36,811	)		(167,951	)		(246,514	)
Financing activities
Draws on credit facility		15,000			3,000			120,000			254,000
Payments on credit facility		(15,000	)		(10,000	)		(163,000	)		(202,000	)
Issuances of long-term debt		1,680,000			—			75,000			—
Repayments of long-term debt		(1,668,268	)		(8,546	)		(100,824	)		(14,876	)
Repurchase of common stock		—			—			—			(12,449	)
Payment of financing costs		(8,655	)		(43	)		(693	)		(71	)
Dividends paid on common stock		(572	)		(24,579	)		(97,283	)		(95,044	)
Contribution from member		100,720			—			—			—
Distributions to member		(88,765	)		—			—			—
Other financing		(1,890	)		(717	)		(2,448	)		(2,448	)
Net cash provided by (used in) financing activities		12,570			(40,885	)		(169,248	)		(72,888	)
Net (decrease) increase in cash and cash equivalents		(97,253	)		52,084			23,823			15,767
Cash and cash equivalents at beginning of period		120,330			68,246			44,423			28,656
Cash and cash equivalents at end of period	$	23,077		$	120,330		$	68,246		$	44,423
Supplementary cash flow information
Interest paid, net of amount capitalized	$	116,496		$	2,478		$	74,349		$	74,515
Income taxes paid (refunded), net	$	4,263		$	(481	)	$	1,434		$	15,286
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$	17,599		$	10,619		$	7,313		$	12,325
Non-cash additions to property, plant, and equipment—ARO	$	—		$	—		$	184		$	4,400

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-10

CLECO

Consolidated Statements of Changes in Equity

(THOUSANDS)	COMMON STOCK/(1) MEMBERSHIP INTEREST			RETAINED EARNINGS/ (ACCUMULATED DEFICIT)			AOCI			TOTAL SHAREHOLDERS’/ MEMBER’S EQUITY
PREDECESSOR
Balances, Dec. 31, 2013	$	463,070		$	1,149,003		$	(25,876	)	$	1,586,197
Common stock issued for compensatory plans		602			—			—			602
Repurchase of common stock		(12,449	)		—			—			(12,449	)
Dividends on common stock, $1.5625 per share		—			(95,030	)		—			(95,030	)
Net income		—			154,739			—			154,739
Other comprehensive loss, net of tax		—			—			(6,789	)		(6,789	)
Balances, Dec. 31, 2014	$	451,223		$	1,208,712		$	(32,665	)	$	1,627,270
Common stock issued for compensatory plans		5,189			—			—			5,189
Dividends on common stock, $1.60 per share		—			(97,367	)		—			(97,367	)
Net income		—			133,669			—			133,669
Other comprehensive income, net of tax		—			—			6,080			6,080
Balances, Dec. 31, 2015	$	456,412		$	1,245,014		$	(26,585	)	$	1,674,841
Common stock issued for compensatory plans		(1,277	)		—			—			(1,277	)
Dividends on common stock, $0.40 per share		—			(24,190	)		—			(24,190	)
Net loss		—			(3,960	)		—			(3,960	)
Other comprehensive income, net of tax		—			—			647			647
Balances, Apr. 12, 2016	$	455,135		$	1,216,864		$	(25,938	)	$	1,646,061
SUCCESSOR
Balances, Apr. 13, 2016(2)	$	2,158,141		$	—		$	—		$	2,158,141
Distributions to member		(88,765	)		—			—			(88,765	)
Net loss		—			(24,113	)		—			(24,113	)
Other comprehensive income, net of tax		—			—			1,500			1,500
Balances, Dec. 31, 2016	$	2,069,376		$	(24,113	)	$	1,500		$	2,046,763

(1) At April 12, 2016, December 31, 2015, and December 31, 2014, shareholders’ equity of the predecessor company included $61.1 million of common stock. At December 31, 2013, shareholders’ equity of the predecessor company included $61.0 million of common stock. At April 12, 2016, December 31, 2015, December 31, 2014, and December 31, 2013, shareholders’ equity of the predecessor company included premium on common stock of $414.6 million, $418.5 million, $415.5 million, and $422.6 million, respectively. At April 12, 2016, December 31, 2015, December 31, 2014, and December 31, 2013, shareholders’ equity of the predecessor company included treasury stock of $20.5 million, $23.2 million, $25.3 million, and $20.6 million, respectively.

(2) The April 13, 2016, beginning balance of the successor company differs from the April 12, 2016, ending balances of the predecessor company due to acquisition accounting adjustments related to the Merger.

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-11

Report of Independent Registered Public Accounting Firm

To the Member and Board of Managers of

Cleco Power LLC

Pineville, Louisiana

In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Power, LLC and its subsidiaries (the “Company”) as of December 31, 2016 and, and the results of their operations and their cash flows for the period January 1, 2016 to December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the consolidated financial statements. These financial statements are the responsibility of the Company’s management.

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

February 22, 2017

F-12

Report of Independent Registered Public Accounting Firm

To the Member and Board of Managers of

Cleco Power LLC

Pineville, Louisiana

We have audited the accompanying consolidated balance sheet of Cleco Power LLC and subsidiaries (the “Company”) as of December 31, 2015, and the related consolidated statements of income, comprehensive income, changes in member’s equity, and cash flows for the years ended December 31, 2015 and 2014. Our audits also included the financial statement schedule for the years ended December 31, 2015 and 2014 listed in the Index at Item 15. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the

financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cleco Power LLC and subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the years ended December 31, 2015 and 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule for the years ended December 31, 2015 and 2014, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

New Orleans, Louisiana

February 26, 2016

F-13

CLECO POWER

Consolidated Statements of Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016			2015			2014
Operating revenue
Electric operations	$	1,091,229		$	1,142,389		$	1,225,960
Other operations		68,573			67,109			64,893
Affiliate revenue		884			1,142			1,326
Gross operating revenue		1,160,686			1,210,640			1,292,179
Electric customer credits		(1,513	)		(2,173	)		(23,530	)
Operating revenue, net		1,159,173			1,208,467			1,268,649
Operating expenses
Fuel used for electric generation		346,520			373,117			322,696
Power purchased for utility customers		119,586			130,095			247,686
Other operations		125,892			128,697			116,664
Maintenance		93,340			87,416			96,054
Depreciation and amortization		146,142			147,839			144,026
Taxes other than income taxes		48,287			47,102			41,812
Merger commitment costs		151,501			—			—
Gain on sales of assets		(1,095	)		—			(4	)
Total operating expenses		1,030,173			914,266			968,934
Operating income		129,000			294,201			299,715
Interest income		860			725			1,707
Allowance for equity funds used during construction		4,458			3,063			5,380
Other income		1,601			1,764			1,483
Other expense		(1,976	)		(2,549	)		(2,322	)
Interest charges
Interest charges, including amortization of debt issuance costs, premiums, and discounts, net		77,739			77,446			76,253
Allowance for borrowed funds used during construction		(1,293	)		(886	)		(1,580	)
Total interest charges		76,446			76,560			74,673
Income before income taxes		57,497			220,644			231,290
Federal and state income tax expense		18,369			79,294			76,974
Net income	$	39,128		$	141,350		$	154,316

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-14

CLECO POWER

Consolidated Statements of Comprehensive Income

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016		2015			2014
Net income	$	39,128	$	141,350		$	154,316
Other comprehensive income (loss), net of tax:
Postretirement benefits gain (loss) (net of tax expense of $2,163 and tax benefit of $9 and $1,453, respectively)		3,459		(15	)		(2,323	)
Net gain on cash flow hedges (net of tax expense of $132 in each year)		211		211			212
Total other comprehensive income (loss), net of tax		3,670		196			(2,111	)
Comprehensive income, net of tax	$	42,798	$	141,546		$	152,205

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-15

CLECO POWER

Consolidated Balance Sheets

(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Assets
Utility plant and equipment
Property, plant, and equipment	$	4,790,565		$	4,645,698
Accumulated depreciation		(1,618,241	)		(1,525,298	)
Net property, plant, and equipment		3,172,324			3,120,400
Construction work in progress		77,306			66,069
Total utility plant and equipment, net		3,249,630			3,186,469
Current assets
Cash and cash equivalents		21,482			65,705
Restricted cash and cash equivalents		23,084			9,263
Customer accounts receivable (less allowance for doubtful accounts of $7,199 in 2016 and $2,674 in 2015)		56,780			43,255
Accounts receivable—affiliate		1,406			1,908
Other accounts receivable		19,457			27,553
Taxes receivable, net		12,490			—
Unbilled revenue		34,268			33,995
Fuel inventory, at average cost		46,410			72,838
Materials and supplies, at average cost		81,818			76,731
Energy risk management assets		7,884			7,673
Accumulated deferred fuel		20,787			12,910
Cash surrender value of company-owned life insurance policies		20,018			20,003
Prepayments		5,892			6,309
Regulatory assets		17,721			14,117
Other current assets		577			337
Total current assets		370,074			392,597
Equity investment in investee		18,672			16,822
Prepayments		4,731			4,542
Restricted cash and cash equivalents		23,389			16,174
Regulatory assets—deferred taxes, net		237,449			236,941
Regulatory assets		268,016			284,689
Intangible asset		58,473			74,963
Other deferred charges		37,014			20,140
Total assets	$	4,267,448		$	4,233,337

The accompanying notes are an integral part of the Consolidated Financial Statements.

(Continued on next page)

F-16

CLECO POWER

Consolidated Balance Sheets

(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Liabilities and member’s equity
Member’s equity	$	1,535,202	$	1,552,404
Long-term debt, net		1,235,056		1,234,039
Total capitalization		2,770,258		2,786,443
Current liabilities
Long-term debt due within one year		19,715		19,421
Accounts payable		101,874		88,235
Accounts payable—affiliate		7,190		6,598
Customer deposits		56,599		55,233
Provision for rate refund		3,974		2,696
Provision for merger commitments		14,371		—
Taxes payable		—		17,045
Interest accrued		7,141		7,813
Energy risk management liabilities		201		275
Regulatory liabilities—other		—		312
Other current liabilities		9,951		10,078
Total current liabilities		221,016		207,706
Commitments and contingencies (Note 15)
Long-term liabilities and deferred credits
Accumulated deferred federal and state income taxes, net		1,068,592		1,043,531
Accumulated deferred investment tax credits		2,751		3,245
Postretirement benefit obligations		159,107		152,152
Restricted storm reserve		17,385		16,177
Other deferred credits		28,339		24,083
Total long-term liabilities and deferred credits		1,276,174		1,239,188
Total liabilities and member’s equity	$	4,267,448	$	4,233,337

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-17

CLECO POWER

Consolidated Statements of Cash Flows

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016			2015			2014
Operating activities
Net income	$	39,128		$	141,350		$	154,316
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		152,978			152,833			151,252
Gain on sales of assets		(1,095	)		—			(346	)
Provision for doubtful accounts		5,512			2,986			1,994
Unearned compensation expense		1,572			2,000			2,004
Allowance for equity funds used during construction		(4,458	)		(3,063	)		(5,380	)
Net deferred income taxes		20,492			43,675			82,315
Deferred fuel costs		(7,215	)		9,899			(11,558	)
Provision for merger commitments		21,964			—			—
Changes in assets and liabilities
Accounts receivable		(23,306	)		(13,681	)		11,689
Accounts and notes receivable, affiliate		2,612			6,195			709
Unbilled revenue		(274	)		4,481			(7,310	)
Fuel inventory and materials and supplies		22,192			(13,698	)		(12,114	)
Accounts payable		9,140			(20,575	)		5,459
Accounts and notes payable, affiliate		(3,639	)		(3,990	)		(2,749	)
Customer deposits		10,675			12,162			14,960
Postretirement benefit obligations		5,076			7,405			4,963
Regulatory assets and liabilities, net		17,506			18,793			(777	)
Other deferred accounts		(21,818	)		(15,991	)		(10,798	)
Taxes accrued		(29,535	)		36,287			(26,373	)
Interest accrued		(671	)		(1,412	)		(4,364	)
Other operating		(1,079	)		882			(820	)
Net cash provided by operating activities		215,757			366,538			347,072
Investing activities
Additions to property, plant, and equipment		(186,143	)		(156,357	)		(206,607	)
Allowance for equity funds used during construction		4,458			3,063			5,380
Proceeds from sale of property		2,698			—			—
Reimbursement for property loss		3,212			—			—
Contributions to equity investment in investee		(2,450	)		(2,290	)		—
Transfer of cash to restricted accounts, net		(21,037	)		(1,341	)		(10,097	)
Sale of restricted investments		—			—			11,138
Maturity of restricted investments		—			—			1,458
Other investing		622			881			2,153
Net cash used in investing activities		(198,640	)		(156,044	)		(196,575	)

The accompanying notes are an integral part of the Consolidated Financial Statements.

(Continued on next page)

F-18

CLECO POWER

Consolidated Statements of Cash Flows

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016			2015			2014
Financing activities
Draws on credit facility		15,000			63,000			157,000
Payments on credit facility		(15,000	)		(83,000	)		(157,000	)
Issuances of long-term debt		330,000			75,000			—
Repayments of long-term debt		(326,814	)		(100,824	)		(14,876	)
Contribution from parent		50,000			—			—
Distributions to parent		(110,000	)		(135,000	)		(115,000	)
Other financing		(4,526	)		(3,127	)		(2,514	)
Net cash used in financing activities		(61,340	)		(183,951	)		(132,390	)
Net (decrease) increase in cash and cash equivalents		(44,223	)		26,543			18,107
Cash and cash equivalents at beginning of period		65,705			39,162			21,055
Cash and cash equivalents at end of period	$	21,482		$	65,705		$	39,162
Supplementary cash flow information
Interest paid, net of amount capitalized	$	92,585		$	74,219		$	74,326
Income taxes (refunded) paid, net	$	(485	)	$	(27	)	$	257
Supplementary non-cash investing and financing activities
Accrued additions to property, plant, and equipment	$	16,755		$	7,249		$	12,225
Non-cash additions to property, plant, and equipment—ARO	$	—		$	184		$	4,400
Non-cash additions to property, plant, and equipment—Coughlin	$	—		$	—		$	176,244

The accompanying notes are an integral part of the Consolidated Financial Statements.

F-19

CLECO POWER

Consolidated Statements of Changes in Member’s Equity

(THOUSANDS)	MEMBER’S EQUITY			AOCI			TOTAL MEMBER’S EQUITY
Balances, Dec. 31, 2013	$	1,385,750		$	(15,177	)	$	1,370,573
Other comprehensive loss, net of tax		—			(2,111	)		(2,111	)
Non-cash contributions from parent		138,080			—			138,080
Distributions to parent		(115,000	)		—			(115,000	)
Net income		154,316			—			154,316
Balances, Dec. 31, 2014	$	1,563,146		$	(17,288	)	$	1,545,858
Other comprehensive income, net of tax		—			196			196
Distributions to parent		(135,000	)		—			(135,000	)
Net income		141,350			—			141,350
Balances, Dec. 31, 2015	$	1,569,496		$	(17,092	)	$	1,552,404
Other comprehensive income, net of tax		—			3,670			3,670
Contribution from parent		50,000			—			50,000
Distributions to parent		(110,000	)		—			(110,000	)
Net income		39,128			—			39,128
Balances, Dec. 31, 2016	$	1,548,624		$	(13,422	)	$	1,535,202

The accompanying notes are an integral part of the Consolidated Financial Statements.

Index to Applicable Notes to the Financial Statements of Registrants

Note 1	The Company	Cleco and Cleco Power
Note 2	Summary of Significant Accounting Policies	Cleco and Cleco Power
Note 3	Business Combinations	Cleco
Note 4	Regulatory Assets and Liabilities	Cleco and Cleco Power
Note 5	Jointly Owned Generation Units	Cleco and Cleco Power
Note 6	Fair Value Accounting	Cleco and Cleco Power
Note 7	Debt	Cleco and Cleco Power
Note 8	Common Stock	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	Operating Leases	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 and Goodwill	Cleco and Cleco Power
Note 18	Coughlin Transfer	Cleco and Cleco Power
Note 19	Accumulated Other Comprehensive Loss	Cleco and Cleco Power
Note 20	Miscellaneous Financial Information (Unaudited)	Cleco and Cleco Power

F-20

Notes to the Financial Statements

Note 1—The Company

General

Cleco Holdings is a holding company composed of the following:

• Cleco Power, a regulated electric utility subsidiary, which owns nine generating units with a total nameplate capacity of 3,310 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.

• Midstream is a wholesale energy subsidiary, regulated by FERC, which owns Evangeline. Prior to March 15, 2014, Evangeline owned

Coughlin and its two generating units with a total nameplate capacity of 775 MW. On March 15, 2014, Coughlin was transferred from Evangeline to Cleco Power.

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

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 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. As a result, Cleco Corporation is presented as the predecessor entity and Cleco Holdings is presented as the successor entity. For more information on the Merger, see Note 3—“Business Combinations.”

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.

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 will be assessed annually or more often if an event occurs or circumstances change that would indicate the

carrying amount may be impaired. If the fair value of Cleco is less than the carrying value, a full valuation of Cleco’s assets and liabilities, conducted as though Cleco were a newly acquired business, would occur. For more information on goodwill, see Note 17—“Intangible Assets and Goodwill.”

Intangible Assets

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, and a fair value adjustment for the valuation of the Cleco trade name. The intangible assets are being amortized over their estimated useful lives in a manner that best reflects the economic benefits derived from such assets. Impairment will be

F-21

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’s carrying amount over its fair value. For more information on intangible assets, see Note 17—“Intangible Assets 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 Power complies with the accounting policies and practices prescribed by its regulatory commissions. Cleco Power’s retail rates are regulated by the LPSC and its tariffs for transmission services are regulated by FERC. Rates for wholesale power sales are based on market-based rates, pending FERC review of Cleco Power’s generation market power analysis. 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 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 4—“Regulatory Assets and Liabilities.”

AROs

Cleco Power recognizes 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 Power recognizes 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 then 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, these costs are capitalized 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.

In April 2015, the EPA published the final rule in the Federal Register for regulating the disposal and management of CCRs from coal-fired power plants under Subtitle D of the Resource Conservation and Recovery Act. The Subtitle D option will regulate CCRs in a manner similar to industrial solid waste. The final rule does not require expensive synthetic lining of existing impoundments. At December 31, 2015, based on management’s best estimate of the retirement costs related to this ruling, Cleco Power recorded a $1.0 million increase to its ARO for the

F-22

retirement of certain ash disposal facilities. All costs of the CCR rule are expected to be recovered from 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 Power will continue to gather additional data in future periods and will make decisions about compliance strategies and the timing of closure

activities. As this additional information becomes available, Cleco Power will update the ARO balance for these changes in estimates. At December 31, 2016, management’s analysis confirmed that no additional adjustments were needed to update Cleco Power’s ARO balance.

For more information on Cleco Power’s current AROs, see Note 4—“Regulatory Assets and Liabilities—AROs.”

Property, Plant, and Equipment

Property, plant, and equipment consists primarily of regulated utility generation and energy transmission and distribution assets. Regulated assets, utilized primarily for retail operations and electric transmission and distribution, are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits, administrative and general costs, and the estimated cost of funds used during construction. Jointly owned assets are reflected in property, plant, and equipment at Cleco Power’s share of the cost to construct or purchase the assets. For information on jointly owned assets, see Note 5—“Jointly Owned Generation Units.”

Most of the carrying values of Cleco’s assets were determined to be stated at fair value at the Merger date, considering that most of these assets are subject to regulation by the LPSC and FERC. A fair value adjustment was made to record the stepped-up basis for the Coughlin assets, since Cleco Power is able to earn a return on and recover these costs from customers. At the date of the Merger, the gross balance of fixed depreciable assets at Cleco was adjusted to be net of accumulated depreciation, as no accumulated depreciation existed on the date of the Merger. Since pushdown accounting was not elected at the Cleco Power level, Cleco Power retained its accumulated depreciation. For more information about merger related adjustments to property, plant, and equipment, see Note 3—“Business Combinations.”

Cleco’s cost of improvements to property, plant, and equipment is capitalized. Costs associated with repairs and major maintenance projects are expensed as incurred. Cleco capitalizes the cost to purchase or develop software for internal use. The amounts of unamortized computer software costs at

December 31, 2016, and 2015 were $10.0 million and $12.5 million, respectively. Amortization of capitalized computer software costs charged to expense in Cleco and Cleco Power’s Statements of Income for the years ending December 31, 2016, 2015, and 2014 is shown in the following tables:

Cleco

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016—DEC. 31, 2016		JAN. 1, 2016—APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Amortization	$	2,351	$	921	$	2,194	$	1,397

Cleco Power
	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016		2015		2014
Amortization	$	2,405	$	1,718	$	1,096

Upon retirement or disposition, the cost of Cleco Power’s depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. For Cleco’s other depreciable assets, upon disposition or retirement, the difference between the net book value of the property and any proceeds received for the property is recorded as a gain or loss on asset disposition on Cleco’s Consolidated Statements of Income. Any cost incurred to remove the asset is charged to expense. Annual depreciation provisions expressed as a percentage of average depreciable property for Cleco Power for both 2016 and 2015 was 2.68%. Annual depreciation provisions expressed as a percentage of average depreciable property for Cleco Power for 2014 was 2.66%.

F-23

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

CATEGORY	YEARS
Utility Plants
Production		10 – 95
Distribution		15 – 50
Transmission		5 – 55
Other utility plant		5 – 45
Other property, plant, and equipment		5 – 45

At December 31, 2016, and 2015, Cleco and Cleco Power’s property, plant, and equipment consisted of the following:

Cleco
	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Utility plants
Production	$	1,866,601		$	2,385,345
Distribution		955,126			1,350,475
Transmission		503,996			665,338
Other utility plant		146,976			244,540
Other property, plant, and equipment		3,882			15,514
Total property, plant, and equipment		3,476,581			4,661,212
Accumulated depreciation		(75,816	)		(1,536,158	)
Net property, plant, and equipment	$	3,400,765		$	3,125,054

Cleco Power
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Regulated utility plants
Production	$	2,406,572			2,385,345
Distribution		1,405,703			1,350,475
Transmission		719,052			665,338
Other utility plant		259,238			244,540
Total property, plant, and equipment		4,790,565			4,645,698
Accumulated depreciation		(1,618,241	)		(1,525,298	)
Net property, plant, and equipment	$	3,172,324		$	3,120,400

During 2016, Cleco Power’s regulated utility property, plant, and equipment increased primarily due to the Cenla Transmission Expansion project, the

Layfield/Messick project, and general rehabilitation of transmission, distribution, and generation assets.

Cleco Power’s property, plant, and equipment includes plant acquisition adjustments related primarily to the acquisition of Acadia Unit 1 in 2010 and Teche in 1997. Accumulated amortization associated with the plant acquisition adjustments are reported in accumulated depreciation on Cleco Power’s Consolidated Balance Sheets. The plant acquisition adjustments and accumulated amortization reported in property, plant, and equipment and accumulated depreciation on Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2016, and 2015 are shown in the following tables:

Cleco
	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Acadia Unit 1
Plant acquisition adjustment	$	76,116		$	95,578
Accumulated amortization		(2,287	)		(18,567	)
Net plant acquisition adjustment	$	73,829		$	77,011
Teche and other
Plant acquisition adjustment	$	544		$	5,271
Accumulated amortization		(183	)		(4,655	)
Net plant acquisition adjustment	$	361		$	616

Cleco Power
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Acadia Unit 1
Plant acquisition adjustment	$	95,578		$	95,578
Accumulated amortization		(21,749	)		(18,567	)
Net plant acquisition adjustment	$	73,829		$	77,011
Teche and other
Plant acquisition adjustment	$	5,271		$	5,271
Accumulated amortization		(4,910	)		(4,655	)
Net plant acquisition adjustment	$	361		$	616

F-24

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,

2016, and 2015, Cleco Power had deferred $5.0 million and $4.6 million, respectively, 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 stated at average cost 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.

Accounts Receivable

Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management

determines it is probable the receivable will not be recovered. At December 31, 2016, and 2015, the balance of the allowance for doubtful accounts was $7.2 million and $2.7 million, respectively. The increase in allowance for doubtful accounts is primarily due to a reserve related to a potential industrial customer. There was no off-balance sheet credit exposure related to Cleco’s customers.

Financing Receivables

At December 31, 2016, Cleco, through Perryville and Attala, had a combined net investment in direct financing lease long-term assets of $13.5 million. The net investment at December 31, 2015, was also $13.5 million. Each subsidiary leases its respective transmission assets to a single counterparty. Both counterparties are considered credit worthy and are expected to pay their obligations when due, thus, no allowance for credit loss has been recognized. Management bases this assessment on the following common factors of each counterparty:

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

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

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

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

Management monitors both entities for indication of adverse actions by their respective public service commissions and market conditions which would indicate an inability to pay their obligations under the direct financing leases when due. Since the inception of the agreements, each counterparty has paid their respective obligations when due, and at December 31, 2016, and 2015, no amounts were past due.

Reserves

Cleco maintains property insurance on generating stations, buildings and contents, and substations.

Cleco is self-insured for any damage to transmission and distribution lines. To mitigate the exposure to potential financial loss for damage to lines, Cleco maintains an LPSC-approved funded storm reserve.

F-25

Cleco Power also maintains liability and workers’ compensation insurance to mitigate financial losses due to injuries and damages to the property of others. Cleco’s insurance covers claims that exceed certain self-insured limits. For claims that do not meet the limits to be covered by insurance, Cleco Power maintains reserves. At December 31, 2016, and 2015, the general liability and workers compensation

reserves together were $4.6 million and $5.5 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
	SUCCESSOR		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current
Cleco Katrina/Rita’s storm recovery bonds	$	9,213	$	9,263
Cleco Power’s charitable contributions		1,200		—
Cleco Power’s rate credit escrow		12,671		—
Total current		23,084		9,263
Non-current
Diversified Lands’ mitigation escrow		21		21
Cleco Power’s future storm restoration costs		17,379		16,174
Cleco Power’s charitable contributions		4,179		—
Cleco Power’s rate credit escrow		1,831		—
Total non-current		23,410		16,195
Total restricted cash and cash equivalents	$	46,494	$	25,458

Cleco Power
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current
Cleco Katrina/Rita’s storm recovery bonds	$	9,213	$	9,263
Charitable contributions		1,200		—
Rate credit escrow		12,671		—
Total current		23,084		9,263
Non-current
Future storm restoration costs		17,379		16,174
Charitable contributions		4,179		—
Rate credit escrow		1,831		—
Total non-current		23,389		16,174
Total restricted cash and cash equivalents	$	46,473	$	25,437

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. The change from December 31, 2015, to 2016 was due to Cleco Katrina/Rita collecting $21.2 million net of administration fees, partially offset by bond and interest payments. In March and September 2016, Cleco Katrina/Rita used $8.5 million and $8.3 million, respectively, for scheduled storm recovery bond principal payments and $2.3 million and $2.1 million, respectively, for related interest payments.

Included in the Merger Commitments were $6.0 million of charitable contributions to be disbursed over five years and $136.0 million of rate credits to

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eligible customers. On April 25, 2016, in accordance with the Merger Commitments, Cleco Power established the charitable contribution fund and deposited the rate credit funds into an escrow account. On April 28, 2016, the LPSC voted to issue

the rate credits equally to customers with service as of June 30, 2016, beginning in July 2016. As of December 31, 2016, $0.6 million of the charitable contributions and $121.5 million of the rate credits had been remitted from restricted cash.

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 2016, 2015, or 2014. For more information on Cleco’s equity investments, see Note 13—“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 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 immediately. The LPSC specifically requires that the state tax benefits associated with the deductions related to certain storm damages be normalized. For more information on income taxes, see Note 10—“Income Taxes.”

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.

NMTC Fund

In 2008, Cleco Holdings and US Bancorp Community Development Corporation (USBCDC) formed the NMTC Fund. The purpose of the NMTC Fund is to invest in projects located in qualified active low-income communities that are underserved by typical debt capital markets. These investments are designed to generate NMTCs and Historical Rehabilitation tax credits. The NMTC Fund was later amended to include renewable energy investments.

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The majority of the energy investments qualify for grants under Section 1603 of the ARRA. The gross investment amortization expense of the NMTC Fund will be recognized over a over a ten-year period, with two years remaining under the new amendment, using the cost method. The grants received under Section 1603, which allow certain projects to receive a federal grant in lieu of tax credits, and other cash reduce the basis of the investment. Periodic

amortization of the investment and the deferred taxes generated by the basis reduction temporary difference are included as components of income tax expense.

For more information, see Note 15—“Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Other Commitments—NMTC Fund.”

Accounting for Renewable Energy Tax Credits and Grants Under the ARRA

Cleco and the NMTC Fund have elected to receive cash grants under the ARRA for investments in various projects. Cleco has elected to reduce the carrying value of the qualifying assets as cash grants are received, which will reduce the amount of

depreciation expense recognized after the underlying assets are placed in service. Certain cash grants also reduce the tax basis of the underlying assets. Grants received via the NMTC Fund reduce the carrying value of the investment for GAAP, but do not reduce the income tax basis of the investment.

Debt 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 retail customers currently are recovered from customers through the FAC. These costs are subject to audit and final determination by regulators. Excise taxes and pass-through fees collected on the sale of electricity are not recorded in utility revenue.

Unbilled Revenue

Cleco Power accrues estimated revenue monthly for energy used by customers but not yet billed. The monthly estimated unbilled revenue amounts are recorded as unbilled revenue and a receivable. During the third quarter of 2014, Cleco Power began using 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 Power 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’s Consolidated Statements of Income but are reflected at gross amounts on Cleco’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’s Consolidated Statements of Income as revenue and expense, but is reflected at gross amounts on Cleco’s Consolidated Balance Sheets as a receivable until it is collected and as a payable until the liability is paid.

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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 11.94% on a pretax basis (7.39% net of tax) for 2016, 11.46% on a pretax basis (7.09% net of tax) for 2015, and 10.46% on a pretax basis (6.47% net of tax) for 2014.

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 6—“Fair Value Accounting.”

Risk Management

Market risk inherent in Cleco’s market risk-sensitive instruments and positions includes potential changes in value arising from changes in interest rates and the commodity market prices of power, FTRs, and natural gas in the industry on different energy exchanges. Cleco’s Energy Market Risk Management Policy authorizes the use of various derivative instruments, including exchange traded futures and option contracts, forward purchase and sales contracts, and swap transactions to reduce exposure to fluctuations in the price of power, FTRs, and natural gas. Cleco evaluates derivatives and hedging activities to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market.

Cleco Power may also enter into risk mitigating positions that would not meet the requirements of a normal-purchase, normal-sale transaction in order to attempt to mitigate the volatility in customer fuel costs. These positions would be marked-to-market with the resulting gain or loss recorded on Cleco and Cleco Power’s Consolidated Balance Sheets as a component of energy risk management assets or liabilities. Such gain or loss would be deferred as a component of deferred fuel assets or liabilities in accordance with regulatory policy. When these positions close, actual gains or losses would be included in the FAC and reflected on customers’ bills as a component of the fuel charge. In June 2015, the LPSC approved a long-term natural gas hedging pilot program that requires Cleco Power to establish a

proposal for a program that will be designed to provide gas price stability for a minimum of five years. This proposal is currently scheduled to be submitted to the LPSC in the second half of 2017. There were no open natural gas positions at December 31, 2016, or 2015.

Cleco Power purchases the majority of its FTRs in annual auctions facilitated by MISO during the second quarter of each year and may also purchase additional FTRs in monthly auctions facilitated by MISO. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Cleco Power’s customer load. FTRs are not designated as hedging instruments for accounting purposes. Cleco Power initially records FTRs at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period based on the most recent MISO FTR auction prices. Unrealized gains or losses on FTRs held by Cleco Power are included in Accumulated deferred fuel on Cleco Power’s Consolidated Balance Sheets. Realized gains or losses on settled FTRs are recorded in Fuel used for electric generation on Cleco Power’s Consolidated Statements of Income. At December 31, 2016, Cleco Power’s Consolidated Balance Sheets reflected the fair value of open FTR positions of $7.9 million in Energy risk management assets and $0.2 million in Energy risk management liabilities, compared to $7.7 million in Energy risk management assets and $0.3 million in Energy risk management liabilities at

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December 31, 2015. For more information on FTRs, see Note 6—“Fair Value Accounting—Commodity Contracts.”

Cleco and Cleco Power maintain a master netting agreement policy and monitor credit risk exposure through review of counterparty credit quality, aggregate counterparty credit exposure, and aggregate counterparty concentration levels. Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties

or their affiliates, as deemed necessary. Cleco Power has agreements in place with various counterparties that authorize the netting of financial buys and sells and contract payments to mitigate credit risk for transactions entered into for risk management purposes.

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 the years ended December 31, 2016, and 2015, Cleco did not enter into any contracts to mitigate the volatility in interest rate risk.

Stock-Based Compensation

For information on Cleco’s stock-based compensation, see Note 8—“Common Stock—Stock-Based Compensation.”

Accounting for MISO Transactions

Cleco Power participates 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 Power purchased for utility customers on Cleco and Cleco Power’s Consolidated Statements of Income.

Recent Authoritative Guidance

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

In May 2014, FASB amended the accounting guidance for revenue recognition. The amended guidance affects entities that enter into contracts for the transfer of non-financial assets unless those contracts are within the scope of other standards. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Under the new guidance, an entity must identify the performance obligations in a contract and the transaction price, and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require extensive disclosure of sufficient information to allow users to understand the nature, amount, timing, and uncertainty of revenue and cash flow arising from contracts. Additional disclosure requirements include

disaggregated revenue, reconciliation of contract balances, the entity’s performance obligations, significant judgments used, costs to obtain or fulfill a contract and the use of practical expedients. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. Cleco does not plan to early adopt the amended guidance. Reporting entities have the option of using either a full retrospective or a modified retrospective approach. Under the full retrospective approach, companies will apply rules to contracts in all reporting periods presented, subject to certain allowable exceptions. Under the modified retrospective approach, companies will apply the rules to all contracts existing as of January 1, 2018, recognizing in beginning retained earnings an adjustment for the cumulative effect of the change and providing additional disclosures comparing results to previous rules. Cleco intends to implement the amended guidance using the modified retrospective approach.

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Upon initial evaluation, key changes in the standard that management is assessing for potential areas of impact include accounting for contract modifications, contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight-line or estimated future market prices), accounting for contributions in aid of construction, and the ability to recognize revenue in situations where collectability is in question. Management will continue to evaluate the impact of this guidance, including additional clarifying amendments issued following the date of initial issuance. The amended guidance could have a material impact on the results of operations, financial condition, or cash flows of the Registrants.

In August 2014, FASB amended the guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. The amended guidance requires management to evaluate whether there is substantial doubt about its ability to continue as a going concern. The guidance provides that management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. If substantial doubt exists, then the principle events giving rise to the substantial doubt and management’s plans to alleviate those doubts should be disclosed. The adoption of this guidance is effective for annual reporting periods ending after December 15, 2016, and for interim periods thereafter. Management’s evaluation of Cleco’s ability to continue as a going concern concluded that substantial doubt does not exist. The adoption of this guidance will not have an impact on the results of operations, financial condition, or cash flows of the Registrants.

In September 2015, FASB amended the business combinations guidance to simplify the accounting for measurement-period adjustments. This guidance eliminates the requirement to retrospectively account for these adjustments. The adoption of this guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. This amendment should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted. Cleco was subject to this guidance starting January 1, 2016. As a result of the Merger on April 13, 2016, Cleco adopted this guidance and does not expect it to have a material impact on the results of operations, financial

condition, or cash flows of the Registrants as a result of provisional merger adjustments in future periods.

In January 2016, FASB amended the guidance for recognition and measurement of financial assets and liabilities. These amendments address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The adoption of this guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption of certain provisions of this guidance is permitted as of the beginning of the fiscal year of adoption. Entities should apply these amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair value should be applied prospectively to equity investments that exist as of the date of adoption. 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 February 2016, FASB amended the guidance to account for leases. This guidance is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The adoption of this guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes practical expedients that may be elected by entities. Management will continue to evaluate the impact of this guidance. The amended guidance could have a material impact on the results of operations, financial condition, or cash flows of the Registrants.

In March 2016, FASB amended the derivatives and hedging accounting guidance to address the effect of derivative contract novations on existing hedge accounting relationships. The amended guidance clarifies that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument does not, in and of itself, require dedesignation of the hedging relationship provided

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that all other hedge accounting criteria continue to be met. The adoption of this guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. Entities have the option to apply these amendments on either a prospective basis or a modified retrospective basis. This guidance will not have an impact on the results of operations, financial condition, or cash flows of the Registrants.

In March 2016, FASB amended the derivatives and hedging accounting guidance related to contingent put and call options in debt instruments. This guidance clarifies the requirements for assessing whether contingent put and call options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. Entities performing the assessment will be required to assess the embedded put and call options solely in accordance with the four-step decision sequence clarified in the amended guidance. The adoption of this guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. Entities should apply these amendments on a modified retrospective basis to existing debt instruments as of the beginning of the fiscal year for which the amendments are effective. Management is evaluating the impact that the adoption of this guidance will have on the results of operations, financial condition, or cash flows of the Registrants.

In March 2016, FASB amended the accounting guidance to simplify the transition to the equity method of accounting. This guidance impacts entities that have an investment that becomes qualified for the equity method of accounting as a result of an increase in the level of ownership interest or degree of influence. This amended guidance eliminates the requirement to retroactively adopt the equity method of accounting. The adoption of this guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. Early adoption is permitted. These amendments should be applied prospectively upon their effective date to increases in the level of ownership interest or degree of influence that results in the adoption of the equity method. Management does not expect this guidance to have any impact on the results of operations, financial condition, or cash flows of the Registrants.

In June 2016, FASB amended the guidance for the measurement of credit losses on financial instruments. The guidance affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The guidance affects loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The adoption of this guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those years. Early adoption is permitted. Management does not expect this guidance to have any impact on the results of operations, financial condition, or cash flows of the Registrants.

In August 2016, FASB amended the guidance for certain cash flow issues with the objective of reducing existing diversity in practice. This guidance affects the cash flow classification related to certain types of transactions including debt, contingent consideration, proceeds from the settlement of insurance claims, and distributions from equity method investees. The adoption of this guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted. Management is evaluating the impact that the adoption of this guidance will have on the results of operations, financial condition, or cash flows of the Registrants.

In October 2016, FASB amended the income tax guidance related to intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. This new guidance states that an entity should recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The adoption of this guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within those annual reporting periods. Early adoption is permitted for all entities as of the beginning of an annual reporting period for which financial statements have not been issued or made available for issuance. Management is evaluating the impact that the adoption of this guidance will have on the result of

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operations, financial condition, or cash flows of the Registrants.

In October 2016, FASB amended the consolidations guidance as it relates to interest held through related parties that are under common control. This amended guidance changes the evaluation of whether a reporting entity is the primary beneficiary of a variable interest entity (VIE) by changing how a reporting entity that is a single decision maker of a VIE treats indirect interests in the entity held through related parties that are under common control with the reporting entity. The adoption of this guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The adoption of this guidance is not expected to have an effect on the results of operations, financial condition, or cash flows of the Registrants.

In November 2016, FASB amended guidance for certain cash flow issues. The amended guidance requires that a statement of cash flow explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash. Therefore, amounts generally described as restricted cash and cash equivalents should be included with cash and cash equivalents

when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The adoption of this guidance is effective for fiscal years beginning after December 15, 2016, including interim reporting periods within those fiscal years. Early adoption is permitted. Management is currently evaluating the impact that the adoption of this guidance will have on the results of operations, financial condition, or cash flows of the Registrants.

In January 2017, FASB amended the accounting guidance to simplify the measurement of a goodwill impairment loss. The amended guidance eliminates step two of the goodwill impairment test, which requires a hypothetical purchase price allocation to measure goodwill impairment. Under the new guidance, a goodwill impairment loss will instead be measured at the amount by which a reporting unit’s carrying amount exceeds its fair value. 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 is evaluating the impact that the adoption of this guidance will have on the results of operations, financial condition, or cash flows of the Registrants.

Note 3—Business Combinations

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 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. At the effective time of the Merger, each outstanding share of Cleco Corporation common stock, par value $1.00 per share (other than shares that were owned by Cleco Corporation, Cleco Partners, Merger Sub, or any other direct or indirect wholly owned subsidiary of Cleco Partners or Cleco Corporation), were cancelled and converted into the right to receive $55.37 per share in cash, without interest, with all dividends payable before the effective time of the Merger.

Regulatory Matters

On March 28, 2016, the LPSC approved the Merger. The LPSC’s written order approving the Merger was issued on April 7, 2016. Approval of the Merger was conditioned upon certain commitments, including $136.0 million of customer rate credits, a $7.0 million one-time contribution for economic development in Cleco Power’s service territory to be administered by the LED, $6.0 million of charitable contributions to be disbursed over five years, and $2.5 million of contributions for economic development for Louisiana state and local organizations to be disbursed over five years. These commitment costs were accrued on April 13, 2016, and are included in Merger transaction and commitment costs and Merger commitment costs on Cleco and Cleco Power’s Consolidated Statements of Income, respectively. In addition, the Merger Commitments also included $1.2 million of annual refunds to customers representing cost savings due to the Merger. For more information, see Note 12 — “Regulation and Rates.”

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Accounting for the Merger Transaction

The total purchase price consideration was approximately $3.36 billion, which consisted of cash paid to Cleco Corporation shareholders of $3.35 billion and cash paid for Cleco LTIP equity awards of $9.5 million. There were no remaining LTIP equity awards as of the close of the Merger.

Pushdown accounting was applied to Cleco, and accordingly, the Cleco consolidated assets acquired and liabilities assumed were recorded on April 13, 2016, at their fair values as follows:

Purchase Price Allocation
(THOUSANDS)	AT APR. 13, 2016
Current assets	$	455,016
Property, plant, and equipment, net		3,432,144
Goodwill		1,490,797
Other long-term assets		1,023,487
Less
Current liabilities		228,515
Net deferred income tax liabilities		1,059,939
Other deferred credits		279,379
Long-term debt, net		1,470,126
Total purchase price	$	3,363,485

Cleco Power’s assets and liabilities were recorded at historical cost since Cleco did not elect pushdown accounting at the Cleco Power level.

The following tables present the fair value adjustments to Cleco’s balance sheet and recognition of goodwill:

(THOUSANDS)	AT APR. 13, 2016
Property, plant, and equipment	$	(1,334,932	)
Accumulated depreciation	$	(1,565,776	)
Goodwill	$	1,490,797
Intangible assets	$	91,826
Regulatory assets	$	250,409
Deferred income tax liabilities	$	126,853
Other deferred credits	$	21,175
Long-term debt	$	198,599

Most of the carrying values of Cleco’s assets and liabilities were determined to be stated at fair value at the Merger date, considering that most of these assets are subject to regulation by the LPSC and FERC. Under such regulation, rates charged to customers are

established by a regulator to provide for recovery of costs and a fair return on rate base and are generally measured at historical cost. As such, a market participant would not expect to recover any more or less than the carrying value of the assets. Prior to the Merger, the Coughlin step-up value was not recorded on Cleco’s Consolidated Balance Sheet due to the accounting treatment for the transfer of that asset in March 2014. However, the recovery of the step-up value of the Coughlin asset was approved by the LPSC for recovery in base rates, including a return on rate base. On the date of the Merger, the step-up value for the Coughlin asset was recognized on Cleco’s Consolidated Balance Sheet since Cleco Power is able to earn a return on and recover these costs from its customers. The beginning balance of fixed depreciable assets was shown net at the date of the Merger, as no accumulated depreciation existed on the date of the Merger.

The excess of the purchase price over the estimated fair value of assets acquired and the liabilities assumed was $1.49 billion, which was recognized as goodwill by Cleco at the Merger date. The goodwill represents the potential long-term return of Cleco to its member. Management has assigned goodwill to Cleco’s reportable segment, Cleco Power.

A fair value adjustment was recorded on Cleco’s Consolidated Balance Sheet to reflect the valuation of the Cleco trade name. This adjustment is included in Intangible assets on Cleco’s Consolidated Balance Sheet. The valuation of the trade name was estimated by applying the relief-from-royalty method under the income approach. This valuation method is based on the premise that, in lieu of ownership of the asset, a company would be willing to pay a royalty to a third-party for the use of that asset. The owner of the asset is spared this cost, and the value of the asset is estimated by the cost savings. The projected revenue attributed to the trade name was based on projections of the value of Cleco’s wholesale contracts. The trade name is being amortized over 20 years. The amortization of the Cleco trade name is included in Depreciation and amortization on Cleco’s Consolidated Statement of Income.

On the date of the Merger, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the difference between the contract price and the market price of long-term wholesale power supply agreements. These adjustments are classified

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as Intangible assets on Cleco’s Consolidated Balance Sheet. The valuation of the power supply agreements was estimated using the income approach. The income approach is based upon discounted projected future cash flows associated with the underlying contracts. The intangible assets for the power supply agreements will be amortized over the remaining term of the applicable contract. The amortization of the power supply agreements is included in Electric operations on Cleco’s Consolidated Statement of Income.

The net increase in deferred tax liabilities on Cleco’s Consolidated Balance Sheet represents the differences between the assigned fair values of assets acquired and their related income tax basis, net of a deferred tax asset representing the net operating loss carryforward that will be utilized in future periods. As the underlying asset assigned fair values are amortized, the related deferred tax liabilities will be included in income tax expense. Goodwill is not deductible for income tax purposes; therefore, no deferred income tax assets or liabilities were recognized for goodwill.

Other fair value adjustments were recorded for long-term debt, postretirement benefit remeasurements and deferred losses, and interest rate derivative settlement gains/losses. These fair value adjustments are subject to rate regulation, but do not earn a return. In these instances, a corresponding regulatory asset was established, as the underlying utility asset or liability amounts are recoverable from or refundable to customers at historical cost through the rate setting process. These regulatory assets established to offset fair value adjustments are amortized in amounts and over time frames consistent with the realization or

settlement of the fair value adjustments. In November and December 2016, Cleco Power redeemed $60.0 million and $250.0 million in long-term debt, respectively. As a result, the fair value adjustments for the redeemed long-term debt and the related unamortized debt issuance cost of $19.8 million on Cleco’s Consolidated Balance Sheet were derecognized. The offset was to the respective regulatory assets. For more information, see Note 4—“Regulatory Assets and Liabilities.”

The valuations performed in the second quarter of 2016 to estimate the fair value of assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the Merger and the end of the second quarter of 2016. During the third quarter of 2016, valuations were performed for the valuation and assessment of the postretirement benefit plans as of April 13, 2016, and the economic useful life of the Cleco trade name. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the Merger, as more information is obtained about the fair value of assets acquired and liabilities assumed. The preliminary amounts recognized are subject to revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the date of the Merger. Except for the effects of the positions related to the Merger reflected on income tax returns, Cleco completed its evaluation and determination of the fair value of certain assets and liabilities acquired as of December 31, 2016. While management believes the positions reflected on the income tax returns are reasonable, the returns have not been audited by the applicable taxing authorities.

Note 4—Regulatory Assets and Liabilities

Cleco 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 believes these regulatory assets will be fully

recoverable; however, if in the future, as a result of regulatory changes or competition, Cleco’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 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 could require discontinuance of the application of the authoritative guidance of regulated operations.

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The following table summarizes Cleco Power’s net regulatory assets and liabilities:

Cleco Power

(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015			REMAINING RECOVERY PERIOD
Total federal regulatory (liability) asset—income taxes	$	(635	)	$	5,614
Total state regulatory asset—income taxes		112,751			105,868
AFUDC		126,335			127,092
Total investment tax credit		(1,002	)		(1,633	)
Total regulatory assets—deferred taxes, net		237,449			236,941			*
Mining costs		6,372			8,921			2.5 yrs.
Interest costs		4,860			5,221			*
AROs(1)		2,096			2,462			*
Postretirement costs(1)		145,268			150,274			*
Tree trimming costs		5,549			6,318			*
Training costs		6,708			6,863			43 yrs.
Surcredits, net(2)		5,876			9,661			*
Amended lignite mining agreement contingency(1)		—			3,781			—
AMI deferred revenue requirement		4,772			5,318			9 yrs.
Production operations and maintenance expenses		13,999			12,436			*
AFUDC equity gross-up(2)		70,423			71,444			*
Acadia Unit 1 acquisition costs		2,442			2,548			23 yrs.
Financing costs		8,663			9,032			*
Biomass costs		18			50			0.5 yrs.
MISO integration costs		1,404			2,340			1.5 yrs.
Coughlin transaction costs		999			1,030			32.5 yrs.
Corporate franchise tax		1,308			373			*
Acadia FRP true-up		—			377			—
MATS Costs		4,270			—			1.5 yrs
Other		710			357			*
Total regulatory assets		285,737			298,806
PPA true-up		—			(312	)		—
Fuel and purchased power		20,787			12,910			*
Total regulatory assets, net	$	543,973		$	548,345

(1) Represents regulatory assets in which cash has not yet been expended and the assets are offset by liabilities that do not incur a carrying cost.

(2) Represents regulatory assets for past expenditures that were not earning a return on investment at December 31, 2016. 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

	SUCCESSOR(1)		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Total Cleco Power regulatory assets, net	$	543,973	$	548,345
Cleco Holdings’ Merger adjustments
Fair value of long-term debt		155,776		—
Postretirement costs		23,362		—
Financing costs		8,966		—
Debt issuance costs		7,606		—
Total Cleco regulatory assets, net	$	739,683	$	548,345

(1) Cleco Holdings’ regulatory assets include acquisition accounting adjustments as a result of the Merger.

Income Taxes

The regulatory asset recorded for deferred income taxes represents 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.

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 began receiving fuel cost savings through the year 2011 while actual mining costs incurred above a certain percentage of the benchmark price were deferred, and could be recovered from retail customers through the FAC only when the actual mining costs are below a certain percentage of the benchmark price.

In 2006, Cleco Power recognized that there was a possibility it may not recover all or part of the lignite mining costs it had deferred and sought relief from the LPSC. In December 2007, the LPSC approved a settlement agreement between Cleco Power, SWEPCO, and the LPSC Staff authorizing Cleco Power to recover the existing deferred mining cost balance, including interest, over 11.5 years. In connection with its approval of the Oxbow Lignite Mine acquisition, in 2009, the LPSC agreed to discontinue benchmarking and the corresponding

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potential to defer future lignite mining costs while preserving the recovery of the legacy deferred fuel balance previously authorized.

Interest Costs

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

AROs

Cleco Power has 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 10 years as of December 31, 2016, 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 9—“Pension Plan and Employee Benefits.”

Tree Trimming Costs

In 2008, the LPSC approved Cleco Power’s request to establish a regulatory asset for costs incurred to trim, cut, or remove trees that were damaged by Hurricanes Katrina and Rita, but were not addressed as part of the restoration efforts. Cleco Power was

allowed to recover these expenditures and the regulatory asset for the initial tree trimming project was completely amortized in January 2015.

In April 2013, the LPSC approved Cleco Power’s request to expend and defer up to $8.0 million in additional tree management costs. Cleco Power requested similar accounting treatment as authorized in the initial tree extraction request and requested authorization to defer actual expenditures as a regulatory asset through the completion date of the tree extraction effort. In February 2015, Cleco Power completed the tree extraction and began amortizing the additional charges over a 3.5-year period.

As a result of increased vegetation growth and to remain in compliance with regulatory requirements, Cleco Power anticipates the need to spend $20.8 million through December 2020 in tree and vegetation management costs. In September 2016, Cleco Power requested approval from the LPSC to defer a portion of these costs utilizing the same accounting treatment of similar costs approved in previous dockets. In October 2016, the LPSC approved Cleco Power to defer an additional amount up to $10.9 million. Of the remaining costs, $4.0 million will be expensed to Maintenance on Cleco Power’s Consolidated Statements of Income, and $5.9 million will be deferred and recovered in current base rates through June 2020.

Training Costs

In February 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 October 2009. In February 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 accumulated deferred income tax liabilities at a rate

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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 also was allowed to record a corresponding regulatory asset in an amount representing the flow back of the carrying charges to ratepayers. This amount is being amortized over various terms of the established surcredits.

In the third quarter of 2013 and the first quarter of 2014, 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 has recorded a regulatory asset that represents excess surcredits refunded to customers that will be collected from ratepayers in future periods. These amounts are being collected and amortized over a four-year period.

As a result of a settlement with the LPSC, Cleco Power is required to implement a surcredit when funds are withdrawn from the restricted storm reserve. In March 2014, Cleco Power withdrew $4.0 million from the restricted storm reserve to pay for storm damages, resulting in the establishment of a new surcredit. This surcredit will be utilized to partially replenish the storm reserve. These amounts are being collected and amortized over a four-year period.

In June 2014, the LPSC approved Cleco Power’s FRP extension. A provision of the FRP extension was to reduce base rates by the amount of the surcredits beginning in July 2014. For more information on the FRP extension, see Note 12—“Regulation and Rates.”

Amended Lignite Mining Agreement Contingency

In April 2009, Cleco Power and SWEPCO entered into a series of transactions to acquire additional lignite reserves and mining equipment from the North American Coal Corporation (NAC), each agreeing to purchase a 50% ownership interest in Oxbow from NAC for a combined price of $25.7 million. Cleco Power, SWEPCO, and DHLC entered into the Amended Lignite Mining Agreement which requires DHLC to mine lignite at the existing Dolet Hills Mine along with the Oxbow Mine and deliver

the lignite to the Dolet Hills Power Station at cost plus a specified management fee. The mining areas are expected to be sufficient to provide the Dolet Hills Power Station with lignite fuel until at least 2036.

Among the provisions of the Amended Lignite Mining Agreement is a requirement that if DHLC is unable to pay for loans and lease payments when due, Cleco Power will pay 50% of the amounts due. Any payments under this provision will be considered a prepayment of lignite to be delivered in the future and will be credited to future invoices from DHLC. This provision meets the recognition requirements as a guarantee to an unrelated third party. Previously, Cleco Power recorded a liability of $3.8 million with an offsetting regulatory asset due to Cleco Power’s ability to recover prudent fuel costs from customers through the FAC. Management determined that it does not expect to be required to pay DHLC under this guarantee. As a result of this determination, the liability and the offsetting regulatory asset were remeasured to zero during the second quarter of 2016.

AMI Deferred Revenue Requirement

In February 2011, the LPSC approved Cleco Power’s stipulated settlement in Docket No. U-31393 allowing Cleco Power to defer, as a regulatory asset, the estimated revenue requirements for the AMI project. The amount of the regulatory asset, including carrying charges, is capped by the LPSC at $20.0 million. In June 2014, the LPSC approved Cleco Power’s FRP extension and the AMI regulatory asset and project capital costs were included in rate base. Cleco Power is recovering the AMI deferred revenue requirement over 11 years beginning July 2014.

Production Operations and Maintenance Expenses

In September 2009, the LPSC authorized Cleco Power to defer, as a regulatory asset, production operations and maintenance expenses, net of fuel and payroll, above the retail jurisdictional portion of $25.6 million annually (deferral threshold). On June 18, 2014, the LPSC approved Cleco Power’s FRP extension, which increased the operations and maintenance deferral threshold to $45.0 million annually. The amount of the regulatory asset is capped at $23.0 million. Also, as part of the FRP

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extension, the LPSC allowed 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. In December 2013, 2014, 2015, and 2016, Cleco Power deferred $8.5 million, $7.7 million, $1.8 million, and $7.3 million, respectively, 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 October 2009, the LPSC approved Cleco Power’s request to establish a regulatory asset for costs incurred as a result of the acquisition by Cleco Power of Acadia Unit 1 and half of Acadia Power Station’s related common facilities. The Acadia Unit 1 acquisition costs are being recovered over a 30-year period beginning February 2010.

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.

Biomass Costs

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

MISO Integration Costs

In June 2014, the LPSC approved Cleco Power’s request to recover the non-capital integration costs associated with Cleco Power joining MISO. The MISO integration costs are being recovered over a four-year period beginning July 2014.

Coughlin Transaction Costs

In January 2014, the LPSC authorized Cleco Power to create a regulatory asset for the Coughlin transfer transaction costs. The Coughlin transaction costs are being recovered over a 35-year period beginning July 2014.

Corporate Franchise Tax

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. In 2016 and 2015, Cleco Power’s net retail portion of franchise taxes paid was $2.5 million and $1.7 million, respectively. The retail portion of state corporate franchise taxes paid each year will be recovered over 12 months beginning July 1 of the following year.

Acadia FRP True-up

For the FRP period July 1, 2013 through June 30, 2014, Cleco Power was authorized by the LPSC to recover the estimated revenue requirement of $58.3 million related to Acadia Unit 1. In June 2014, Cleco Power determined that it had under-recovered $0.8 million in revenue from customers based on the actual revenue requirement for Acadia Unit 1. The amount representing the under-collection was deferred and was recovered from customers over 12 months beginning July 1, 2015.

MATS Costs

On February 1, 2016, the LPSC approved Cleco Power’s request to recover the revenue requirements associated with the installation of MATS equipment. The MATS rule required affected EGUs to meet specific emission standards and work practice standards to address hazardous air pollutants by April 2015. The LPSC approval also allowed Cleco Power to record a regulatory asset of $7.1 million representing the unrecovered revenue requirements

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of MATS equipment placed in service in the years prior to the LPSC review and approval. This amount is being amortized over three years beginning January 1, 2016.

Other

In June 2014, the LPSC approved Cleco Power’s FRP extension which authorized the recovery of previously deferred costs incurred as a result of Cleco Power’s FRP extension filing, the 2003 through 2008 fuel audit, and a biomass study. These costs are being recovered over a three-year period beginning July 2014. In October 2015, the LPSC approved the recovery of costs incurred as a result of Cleco Power’s 2009 through 2013 fuel audit. In April 2016, the LPSC approved the recovery of costs incurred as part of Cleco Power’s IRP report filed under the IRP Order No. R-30021. Both the 2009 through 2013 fuel audit costs and the IRP costs are being recovered over a three-year period beginning July 2016.

PPA True-up

In preparing the FRP monitoring report for the year ended June 30, 2014, Cleco Power determined it had recovered $0.6 million above the actual PPA capacity costs. Cleco Power recorded the overcollection as a regulatory liability and returned this amount to the customers over 12 months beginning July 1, 2015.

Fuel and Purchased Power

The cost of fuel used for electric generation and power purchased for utility customers are recovered through the LPSC-established FAC or related wholesale contract provisions, which enable Cleco Power to pass on to its customers substantially all such charges. For 2016, approximately 75% of Cleco Power’s total fuel cost was regulated by the LPSC.

Fuel and purchased power increased $7.9 million from December 31, 2015. Of this amount, $11.5 million was due to an increase caused by surcharge adjustments, increased environmental expenses, and timing of collections. This was partially offset by a $3.6 million decrease in the mark-to-market value on FTRs.

Cleco Holdings’ Merger Adjustments

As a result of the Merger, Cleco implemented acquisition accounting, which eliminated AOCI at the Cleco consolidated level on the date of the 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 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 will be amortized over the terms of the related debt issuances. In November and December 2016, Cleco Power redeemed $60.0 million and $250.0 million in long-term debt, respectively. As a result, the fair value adjustments for the redeemed long-term debt and the related unamortized debt issuance cost of $19.8 million on Cleco’s Consolidated Balance Sheets were derecognized. The offset was to the respective regulatory assets.

Note 5—Jointly Owned Generation Units

Cleco Power operates 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’s share of the direct expenses of the jointly owned generation units is included in the operating expenses of the consolidated statements of income.

At the date of the Merger, the gross balance of jointly owned generation units at Cleco was adjusted to be net of accumulated depreciation, as no accumulated depreciation existed on the date of the Merger. Since pushdown accounting was not elected at the Cleco Power level, Cleco Power retained its accumulated depreciation. For more information about merger related adjustments, see Note 3—“Business Combinations.”

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At December 31, 2016, the investment in and accumulated depreciation for each generating unit on Cleco and Cleco Power’s Consolidated Balance Sheets were as follows:

Cleco

	SUCCESSOR
	AT DEC. 31, 2016
(THOUSANDS, EXCEPT PERCENTAGES AND MW)	RODEMACHER UNIT 2			DOLET HILLS			TOTAL
Utility plant in service	$	70,136		$	177,201		$	247,337
Accumulated depreciation	$	1,530		$	5,783		$	7,313
Construction work in progress	$	166		$	3,193		$	3,359
Ownership interest percentage		30	%		50	%
Nameplate capacity (MW)		523			650
Ownership interest (MW)		157			325

Cleco Power

	AT DEC. 31, 2016
(THOUSANDS, EXCEPT PERCENTAGES AND MW)	RODEMACHER UNIT 2			DOLET HILLS			TOTAL
Utility plant in service	$	144,316		$	394,698		$	539,014
Accumulated depreciation	$	75,710		$	223,280		$	298,990
Construction work in progress	$	166		$	3,193		$	3,359
Ownership interest percentage		30	%		50	%
Nameplate capacity (MW)		523			650
Ownership interest (MW)		157			325

Note 6—Fair Value Accounting

The amounts reflected in Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2016, and December 31, 2015, for cash equivalents, restricted cash equivalents, accounts receivable, other accounts receivable, and accounts payable approximate fair value because of their short-term nature.

The following tables summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments not measured at fair value in Cleco and Cleco Power’s Consolidated Balance Sheets:

Cleco

	SUCCESSOR				PREDECESSOR
	AT DEC. 31, 2016				AT DEC. 31, 2015
(THOUSANDS)	CARRYING VALUE*		ESTIMATED FAIR VALUE		CARRYING VALUE*		ESTIMATED FAIR VALUE
Long-term debt	$	2,768,149	$	2,754,518	$	1,299,529	$	1,463,989

* The carrying value of long-term debt does not include deferred issuance costs of $11.7 million in 2016 and $9.9 million in 2015.

Cleco Power

	AT DEC. 31, 2016				AT DEC. 31, 2015
(THOUSANDS)	CARRYING VALUE*		ESTIMATED FAIR VALUE		CARRYING VALUE*		ESTIMATED FAIR VALUE
Long-term debt	$	1,262,373	$	1,418,693	$	1,265,529	$	1,429,989

* The carrying value of long-term debt does not include deferred issuance costs of $9.4 million in 2016 and $9.6 million in 2015.

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Fair Value Measurements and Disclosures

Cleco classifies assets and liabilities that are either measured or disclosed at their fair value according to three different levels depending on the inputs used in determining fair value.

The following tables disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured or disclosed on a recurring basis:

Cleco

	CLECO CONSOLIDATED FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
	SUCCESSOR								PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSERVABLE INPUTS (LEVEL 3)		AT DEC. 31, 2015		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	$	66,410	$	—	$	66,410	$	—	$	89,584	$	—	$	89,584	$	—
FTRs		7,884		—		—		7,884		7,673		—		—		7,673
Total assets	$	74,294	$	—	$	66,410	$	7,884	$	97,257	$	—	$	89,584	$	7,673
Liability Description
Long-term debt	$	2,754,518	$	—	$	2,754,518	$	—	$	1,463,989	$	—	$	1,463,989	$	—
FTRs		201		—		—		201		275		—		—		275
Total liabilities	$	2,754,719	$	—	$	2,754,518	$	201	$	1,464,264	$	—	$	1,463,989	$	275

Cleco Power

	CLECO POWER FAIR VALUE MEASUREMENTS AT REPORTING DATE USING:
(THOUSANDS)	AT DEC. 31, 2016		QUOTED PRICES IN ACTIVE MARKETS FOR IDENTICAL ASSETS (LEVEL 1)		SIGNIFICANT OTHER OBSERVABLE INPUTS (LEVEL 2)		SIGNIFICANT UNOBSER VABLEINPUTS (LEVEL 3)		AT DEC. 31, 2015		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	$	65,089	$	—	$	65,089	$	—	$	87,363	$	—	$	87,363	$	—
FTRs		7,884		—		—		7,884		7,673		—		—		7,673
Total assets	$	72,973	$	—	$	65,089	$	7,884	$	95,036	$	—	$	87,363	$	7,673
Liability Description
Long-term debt	$	1,418,693	$	—	$	1,418,693	$	—	$	1,429,989	$	—	$	1,429,989	$	—
FTRs		201		—		—		201		275		—		—		275
Total liabilities	$	1,418,894	$	—	$	1,418,693	$	201	$	1,430,264	$	—	$	1,429,989	$	275

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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:

Cleco

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015
Beginning balance	$	3,458		$	7,398		$	9,949
Unrealized gains (losses)*		3,119			(1,031	)		(1,476	)
Purchases		12,896			2,070			20,319
Settlements		(11,790	)		(4,979	)		(21,394	)
Ending balance	$	7,683		$	3,458		$	7,398

* Unrealized gains (losses) are reported through Accumulated deferred fuel on Cleco and Cleco Power’s Consolidated Balance Sheets.

Cleco Power

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016			2015
Beginning balance	$	7,398		$	9,949
Unrealized gains (losses)*		2,088			(1,476	)
Purchases		14,966			20,319
Settlements		(16,769	)		(21,394	)
Ending balance	$	7,683		$	7,398

* Unrealized gains (losses) are reported through Accumulated deferred fuel on Cleco and Cleco Power’s Consolidated Balance Sheets.

The following table quantifies the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2016:

Cleco

	FAIR VALUE				VALUATION TECHNIQUE		SIGNIFICANT UNOBSERVABLE INPUTS		FORWARD PRICE RANGE
(THOUSANDS, EXCEPT DOLLAR PER MWh)	Assets		Liabilities						Low			High
SUCCESSOR
FTRs at December 31, 2016	$	7,884	$	201		RTO auction pricing		FTR price—per MWh	$	(3.61	)	$	6.04
PREDECESSOR
FTRs at December 31, 2015	$	7,673	$	275		RTO auction pricing		FTR price—per MWh	$	(3.63	)	$	4.51

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, 2016	$	7,884	$	201		RTO auction pricing		FTR price—per MWh	$	(3.61	)	$	6.04
FTRs at December 31, 2015	$	7,673	$	275		RTO auction pricing		FTR price—per MWh	$	(3.63	)	$	4.51

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 and then discounting the price to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return. Cleco has consistently applied the Level 2 fair value technique from fiscal period to

fiscal period. 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 therefore RTO auction prices are used. 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.

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At December 31, 2016, 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 $20.0 million, $23.1 million, and $23.3 million, respectively, at December 31, 2016, and $64.2 million, $9.3 million, and $16.1 million, respectively, at December 31, 2015. 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 $18.7 million, $23.1 million, and $23.3 million, respectively, at December 31, 2016, and $62.0 million, $9.3 million, and $16.1 million, respectively, at December 31, 2015. 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.

Cleco Power’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.

The Level 2 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.

During the years ended December 31, 2016, and 2015, Cleco did not experience any transfers between levels within the fair value hierarchy.

Commodity Contracts

The following table presents 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, 2016, and 2015:

Cleco

	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
	SUCCESSOR			PREDECESSOR
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT DEC. 31, 2016		AT DEC. 31, 2015
Commodity-related contracts
FTRs:
Current	Energy risk management assets	$	7,884	$	7,673
Current	Energy risk management liabilities		201		275
Commodity-related contracts, net		$	7,683	$	7,398

Cleco Power

	DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)	BALANCE SHEET LINE ITEM	AT DEC. 31, 2016		AT DEC. 31, 2015
Commodity-related contracts
FTRs:
Current	Energy risk management assets	$	7,884	$	7,673
Current	Energy risk management liabilities		201		275
Commodity-related contracts, net		$	7,683	$	7,398

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The following table presents the effect of derivatives not designated as hedging instruments on Cleco and Cleco Power’s Consolidated Statements of Income for the years December 31, 2016, 2015, and 2014:

Cleco

		AMOUNT OF GAIN/(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES
		SUCCESSOR			PREDECESSOR
(THOUSANDS)	DERIVATIVES LINE ITEM	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Commodity contracts
FTRs(1)	Electric operations	$	30,915		$	8,563			50,594		$	74,454
FTRs(1)	Power purchased for utility customers		(14,941	)		(5,761	)		(27,509	)		(46,386	)
Total		$	15,974		$	2,802		$	23,085		$	28,068

(1) For the periods January 1, 2016—April 12, 2016, and April 13, 2016—December 31, 2016, unrealized (losses) gains associated with FTRs of $(1.0) million and $3.1 million, respectively, were reported through Accumulated deferred fuel on the balance sheet. For the years ended December 31, 2015, and 2014, unrealized losses associated with FTRs of $1.5 million and $2.7 million, respectively, were reported through Accumulated deferred fuel on the balance sheet.

Cleco Power

		AMOUNT OF GAIN/(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES
		FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	DERIVATIVES LINE ITEM	2016			2015			2014
Commodity contracts
FTRs(1)	Electric operations	$	39,478		$	50,594		$	74,454
FTRs(1)	Power purchased for utility customers		(20,702	)		(27,509	)		(46,386	)
Total		$	18,776		$	23,085		$	28,068

(1) For the years ended December 31, 2016, 2015, and 2014, unrealized gains (losses) associated with FTRs of $2.1 million, $(1.5) million, and $(2.7) million, respectively, were reported through Accumulated deferred fuel on the balance sheet.

At December 31, 2016, and 2015, Cleco Power had no open positions hedged for natural gas. In June 2015, the LPSC approved a long-term natural gas hedging pilot program that requires Cleco Power to establish a proposal for a program that will be designed to provide gas price stability for a minimum of five years. This proposal is currently scheduled to be submitted to the LPSC in the second half of 2017.

Cleco Power purchases the majority of its FTRs in annual auctions facilitated by MISO during the second quarter of each year and may also purchase

additional FTRs in monthly auctions facilitated by MISO. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Cleco Power’s customer load. FTRs represent rights to congestion credits or charges along a path during a given time frame for a certain MW quantity. They are not designated as hedging instruments for accounting purposes. The total volume of FTRs that Cleco Power had outstanding at December 31, 2016, and 2015 was 9.0 million MWh and 8.4 million MWh, respectively.

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Note 7—Debt

Cleco Power’s total indebtedness as of December 31, 2016, and 2015 was as follows:

Cleco Power

	AT DEC. 31,
(THOUSANDS)	2016			2015
Bonds
Senior notes, 6.65%, due 2018	$	—		$	250,000
Senior notes, 3.68%, due 2025		75,000			75,000
Senior notes, 3.47%, due 2026		130,000			—
Senior notes, 4.33%, due 2027		50,000			50,000
Senior notes, 3.57%, due 2028		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
Solid waste disposal facility bonds, 4.70%, due 2036, callable November 1, 2016		—			60,000
Cleco Katrina/Rita’s storm recovery bonds, 4.41%, due 2020		1,115			17,929
Cleco Katrina/Rita’s storm recovery bonds, 5.61%, due 2023		67,600			67,600
Total bonds		1,268,715			1,265,529
Other long-term debt
Barge lease obligations, ending 2017		1,819			4,425
Gross amount of long-term debt		1,270,534			1,269,954
Less: long-term debt due within one year		17,896			16,814
Less: lease obligations classified as long-term debt due within one year		1,819			2,607
Unamortized debt discount		(6,342	)		(6,885	)
Unamortized debt issuance costs		(9,421	)		(9,609	)
Total long-term debt, net	$	1,235,056		$	1,234,039

Cleco’s total indebtedness as of December 31, 2016, and 2015 was as follows:

Cleco

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Total Cleco Power long-term debt, net	$	1,235,056		$	1,234,039
Senior notes, 3.250%, due 2023		165,000			—
Senior notes, 3.743%, due 2026		535,000			—
Senior notes, 4.973%, due 2046		350,000			—
Bank term loan, variable rate, due 2021		300,000			—
Credit facility draws		—			34,000
Unamortized debt issuance costs		(2,261	)		(336	)
Fair value adjustment		155,776			—
Total long-term debt, net	$	2,738,571		$	1,267,703

The principal amounts payable under long-term debt agreements for each year through 2021 and thereafter are as follows:

(THOUSANDS)	CLECO		CLECO POWER
Amounts payable under long-term debt arrangements
For the year ending Dec. 31,
2017	$	17,896	$	17,896
2018	$	19,193	$	19,193
2019	$	20,571	$	20,571
2020	$	11,055	$	11,055
2021	$	300,000	$	—
Thereafter	$	2,250,000	$	1,200,000

At December 31, 2016, Cleco and Cleco Power had $1.8 million of principal amounts payable in 2017 for a capital lease agreement for barges. For more information about the barge lease, see Note 15—“Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Other Commitments—Fuel Transportation Agreement.”

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Cleco Power Debt

Cleco Power had no short-term debt outstanding at December 31, 2016, and 2015.

At December 31, 2016, Cleco Power’s long-term debt outstanding was $1.25 billion, of which $19.7 million was due within one year. The long-term debt due within one year at December 31, 2016, represents $17.9 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments.

On November 1, 2016, Cleco Power redeemed at par $60.0 million of 4.70% Solid Waste Disposal Facility bonds due November 2036. As part of the redemption, Cleco Power paid $1.4 million of accrued interest on the redeemed bonds.

On December 20, 2016, Cleco Power completed the private sale of $130.0 million of 3.47% senior notes due December 16, 2026, and $200.0 million of 3.57% senior notes due December 16, 2028. The proceeds from the issuance and sale of these notes were used to replace cash used to redeem the above mentioned Solid Waste Disposal Facility bonds, to redeem $250.0 million of 6.65% senior notes due 2018 prior to maturity and pay make-whole payments of approximately $19.0 million in connection with such redemption, and for general company purposes.

Cleco Debt

Cleco had no short-term debt outstanding at December 31, 2016, and 2015.

At December 31, 2016, Cleco’s long-term debt outstanding was $2.76 billion, of which $19.7 million was due within one year. The long-term debt due within one year at December 31, 2016, represents $17.9 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments.

In connection with the completion of the Merger, on April 13, 2016, Cleco Holdings entered into a $1.35 billion Acquisition Loan Facility. The Acquisition Loan Facility had a three-year term and a rate of LIBOR plus 1.75% or ABR plus 0.75%. In May and June 2016, Cleco Holdings refinanced the Acquisition Loan Facility with a series of other long-term financings described below.

On May 17, 2016, Cleco Holdings completed the private sale of $535.0 million of 3.743% senior notes due May 1, 2026, and $350.0 million of 4.973% senior notes due May 1, 2046. On May 24, 2016, Cleco Holdings completed the private sale of $165.0 million of 3.250% senior notes due May 1, 2023. On June 28, 2016, Cleco Holdings entered into a $300.0 million variable rate bank term loan due June 28, 2021. Amounts outstanding under the bank term loan bear interest, at Cleco’s option, at a base rate plus 0.625% or LIBOR plus 1.625%. At December 31, 2016, the all-in rate was 2.265%, which was based on the LIBOR rate. The proceeds from the issuance and sale of these notes and term loan were used to repay the $1.35 billion Acquisition Loan Facility. Debt issuance costs of $17.7 million were expensed to merger costs in connection with the repayment of the Acquisition Loan Facility.

Credit Facilities

At December 31, 2016, Cleco had two separate revolving credit facilities, one for Cleco Holdings and one for Cleco Power, with a maximum aggregate capacity of $400.0 million.

At December 31, 2015, Cleco Power had a $300.0 million credit facility. On April 13, 2016, in connection with the completion of the Merger, Cleco Power replaced its existing credit facility. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021.

At December 31, 2016, Cleco Power had no borrowings outstanding under its $300.0 million credit facility. The borrowing costs under Cleco Power’s new credit facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%. Under covenants contained in Cleco Power’s credit facility, Cleco Power is required to maintain total indebtedness equal to or less than 65% of total capitalization. At December 31, 2016, $853.4 million of Cleco Power’s member’s equity was unrestricted. If Cleco Power were to default under its credit facility or any other debt agreements, Cleco Holdings would be considered to be in default under its facility. At December 31, 2016, Cleco Power was in compliance with the covenants in its credit facility. A $2.0 million letter of credit issued to MISO is covered under a standing letter of credit outside of Cleco Power’s credit facility; therefore, it does not

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reduce the borrowing capacity of Cleco Power’s new credit facility.

At December 31, 2015, Cleco Holdings had a $250.0 million credit facility. On April 13, 2016, in connection with the completion of the Merger, Cleco Holdings replaced the existing credit facility with a $100.0 million credit facility. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021.

At December 31, 2016, Cleco Holdings had no borrowings outstanding under its $100.0 million credit facility. The borrowing costs under Cleco Holdings’ new credit facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%. Under covenants contained in Cleco Holdings’ credit facility, Cleco is required to maintain total indebtedness equal to or less than 65% of total capitalization. At December 31, 2016, $634.6 million of Cleco’s member’s equity was unrestricted. At December 31, 2016, Cleco Holdings was in compliance with the covenants of its credit facility.

Note 8—Common Stock

Stock-Based Plan Descriptions and Share Information

Prior to the completion of the Merger, Cleco had two stock-based compensation plans: the ESPP and the LTIP. As a result of the completion of the Merger, the ESPP and the LTIP were terminated. For more information about the Merger, see Note 3—“Business Combinations.”

Employee Stock Purchase Plan

Prior to October 17, 2014, regular, full-time, and part-time employees of Cleco Corporation and its participating subsidiaries, except officers, general managers, and employees who owned 5% or more of Cleco Corporation’s stock, were eligible to participate in the ESPP. No trust or other fiduciary account was established in connection with the ESPP. Shares of common stock were purchased at a 5% discount of the fair market value as of the last trading day of each calendar quarter. A participant could purchase a maximum of 125 shares per offering period. Dividends received on shares were automatically reinvested as required by the dividend reinvestment plan (DRIP) provisions of the ESPP.

A maximum of 734,000 shares of common stock was available to be purchased under the ESPP, subject to adjustment for changes in the capitalization of Cleco Corporation. The Compensation Committee of Cleco Corporation’s Board of Directors monitored the ESPP. The Compensation Committee and the Board of Directors possessed the authority to amend the ESPP, but shareholder approval was required for any amendment that increased the number of shares

covered by the ESPP. As stated above, the ESPP plan was terminated upon completion of the Merger.

Long-Term Incentive Compensation Plan

Prior to the completion of the Merger, stock options, restricted stock, also known as non-vested stock, common stock equivalent units, and stock appreciation rights were available to be granted or awarded to certain officers, key employees, or directors of Cleco Corporation and its affiliates under the LTIP. On December 31, 2009, the 2000 LTIP expired and no further grants or awards were made under this plan. During 2015, all restrictions on non-vested shares previously awarded pursuant to the 2000 LTIP had lapsed.

With shareholder approval, the 2010 LTIP became effective January 1, 2010. Under this plan, a maximum of 2,250,000 shares of Cleco Corporation’s common stock was available to be granted or awarded. During 2015, Cleco granted 9,611 shares of stock to directors of Cleco pursuant to the LTIP. All of these shares vested immediately upon award and were issued from shares previously purchased through Cleco’s common stock repurchase program. As stated above, the LTIP plan was terminated upon completion of the Merger.

Non-Vested Stock and Common Stock Equivalent Units

Prior to the completion of the Merger, Cleco granted non-vested stock to certain officers, key employees, and directors. Because it was only to be settled in shares of Cleco Corporation common stock, non-vested stock was classified as equity. Recipients of non-vested stock had full voting rights of a

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stockholder. At the time restrictions lapsed, the accrued dividend equivalent units were paid to the recipient only to the extent that target shares vested.

In order to vest, the non-vested stock required the satisfaction of a service requirement and a market-based requirement. Recipients of non-vested stock were eligible to receive opportunity instruments if certain market-based measures were exceeded. Cleco also awarded non-vested stock with only a service period requirement to certain employees and directors. These awards required the satisfaction of a predetermined service period in order for the shares to vest.

During the predecessor period January 1, 2016, through April 12, 2016, Cleco granted no shares of non-vested stock pursuant to the LTIP. As a result of the Merger on April 13, 2016, all unvested shares outstanding under the LTIP that were granted prior to January 1, 2015, vested at target and were paid out in cash to plan participants. Unvested shares that were granted during 2015 were prorated to the target amount and paid out in cash to plan participants in accordance with the terms of the Merger Agreement.

A summary of non-vested stock activity during 2016 is presented in the following table:

	PREDECESSOR
	SHARES			WEIGHTED- AVERAGE GRANT- DATE FAIR VALUE
Non-vested at Jan. 1, 2016		269,988		$	48.11
Vested		(217,588	)	$	46.53
Forfeited		(52,400	)	$	54.64
Non-vested at Apr. 12, 2016		—		$	—

The fair value of shares of non-vested stock that vested during the predecessor period January 1, 2016, through April 12, 2016, was $10.1 million. The fair value of shares of non-vested stock that vested during the predecessor years ended December 31, 2015, and 2014 was $3.3 million and $5.6 million, respectively.

The fair value of shares of non-vested stock granted during 2015 and 2014 under the LTIP was estimated on the date of grant and the expense was calculated

using the Monte Carlo simulation model with the assumptions listed in the following table:

	PREDECESSOR
	FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Expected term (in years)(1)		3.0			3.0
Volatility of Cleco stock(2)		15.8	%		17.3	%
Correlation between Cleco stock volatility and peer group		63.1	%		66.5	%
Expected dividend yield		2.9	%		3.0	%
Weighted average fair value (Monte Carlo model)	$	45.60		$	54.58

(1) The expected term was based on the service period of the award.

(2) The volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

Stock-Based Compensation

During 2016, 2015, and 2014, Cleco did not modify any of the terms of outstanding awards. Cleco recognized stock-based compensation expense for these provisions in accordance with the non-substantive vesting period approach.

Prior to the completion of the Merger, Cleco recorded compensation expense for all non-vested stock. Assuming achievement of vesting requirements was probable, stock-based compensation expense of non-vested stock was recorded during the service periods, which were generally three years. All stock-based compensation cost was measured at the grant date based on the fair value of the award and was recognized as an expense in the income statement over the requisite service period of the award. Awards that vest pro rata during the requisite service period that contain only a service condition were defined as having a graded vesting schedule and could have been treated as multiple awards with separate vesting schedules. However, Cleco elected to treat grants with graded vesting schedules as one award and recognized the related

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compensation expense on a straight-line basis over the requisite service period.

In April 2016, Cleco incurred $2.3 million of merger expense due to accelerated vesting of the LTIP shares.

The ESPP did not contain optionality features beyond those listed by the authoritative guidance on stock-based compensation. Therefore, Cleco was not required to recognize a fair-value expense related to the ESPP.

Cleco and Cleco Power reported pretax compensation expense for their share-based compensation plans as shown in the following tables:

Cleco

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016		JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Equity classification
Non-vested stock(1)	$	—	$	3,241	$	6,110	$	6,308
Tax benefit	$	—	$	1,247	$	2,351	$	2,427

(1) For each of the years ended December 31, 2015, and 2014, compensation expense included in Cleco’s Consolidated Statements of Income related to non-forfeitable dividends paid on non-vested stock that was not expected to vest was $0.1 million. For the predecessor period January 1, 2016, through April 12, 2016, compensation expense included in Cleco’s Consolidated Statements of Income related to non-forfeitable dividends paid on non-vested stock that was not expected to vest was less than $0.1 million.

Cleco Power

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016		2015		2014
Equity classification
Non-vested stock	$	997	$	2,000	$	2,004
Tax benefit	$	384	$	770	$	771

The amount of stock-based compensation capitalized in property, plant, and equipment on Cleco’s Consolidated Balance Sheets for the predecessor periods January 1, 2016, through April 12, 2016, and January 1, 2015, through December 31, 2015, was $0.6 million and $0.8 million, respectively. The amount of stock-based compensation capitalized in property, plant, and equipment on Cleco Power’s Consolidated Balance Sheets for the years ended December 31, 2016, and 2015 was $0.6 million and $0.7 million, respectively.

Common Stock Repurchase Program

Prior to the completion of the Merger, Cleco Corporation had a common stock repurchase program that authorized management to repurchase shares of common stock. During the predecessor periods January 1, 2016, through April 12, 2016, and January 1, 2015, through December 31, 2015, no shares of common stock were repurchased. During the predecessor year ended December 31, 2014, 250,000 shares of common stock were repurchased. Upon completion of the Merger on April 13, 2016, the common stock repurchase program was terminated. For more information about the Merger, see Note 3—“Business Combinations.”

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.

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

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contributions to the employee pension plan upon actuarial computations utilizing the projected unit credit method, subject to the IRS’s full funding limitation. Cleco did not make any required or discretionary contributions to the pension plan in 2016 and 2015, nor does it expect to make any in 2017. The required contributions are driven by liability funding target percentages set by law which could cause the required contributions to be uneven among the years. The ultimate amount and timing of the contributions may be affected by changes in the

discount rate, changes in the funding regulations, and actual returns on fund assets. Cleco Power is considered the plan sponsor and Support Group is considered the plan administrator.

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

The employee pension plan and other benefits obligation plan assets and funded status at December 31, 2016, and 2015 are presented in the following table:

	PENSION BENEFITS									OTHER BENEFITS
	SUCCESSOR			PREDECESSOR						SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015
Change in benefit obligation
Benefit obligation at beginning of period	$	499,724		$	480,062		$	498,372		$	42,707		$	43,070		$	44,652
Service cost		6,909			2,563			10,419			1,112			431			1,635
Interest cost		15,088			6,242			20,795			1,237			476			1,607
Plan participants’ contributions		—			—			—			758			300			903
Actuarial loss (gain)		6,242			16,857			(30,483	)		2,292			—			(1,039	)
Expenses paid		(2,025	)		(801	)		(1,995	)		—			—			—
Medicare D		—			—			—			—			—			48
Benefits paid		(13,153	)		(5,199	)		(17,046	)		(3,970	)		(1,570	)		(4,736	)
Benefit obligation at end of period		512,785			499,724			480,062			44,136			42,707			43,070
Change in plan assets
Fair value of plan assets at beginning of period		398,515			383,532			412,803			—			—			—
Actual return on plan assets		20,378			20,983			(10,230	)		—			—			—
Expenses paid		(2,025	)		(801	)		(1,995	)		—			—			—
Benefits paid		(13,153	)		(5,199	)		(17,046	)		—			—			—
Fair value of plan assets at end of period		403,715			398,515			383,532			—			—			—
Unfunded status	$	(109,070	)	$	(101,209	)	$	(96,530	)	$	(44,136	)	$	(42,707	)	$	(43,070	)

The employee pension plan accumulated benefit obligation at December 31, 2016, and 2015 is presented in the following table:

	PENSION BENEFITS
	SUCCESSOR		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Accumulated benefit obligation	$	473,197	$	440,876

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The following table presents the net actuarial gains/losses, transition obligations/assets, and prior service costs 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 at December 31, 2016, and 2015:

	PENSION BENEFITS									OTHER BENEFITS
	SUCCESSOR			PREDECESSOR						SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			APR. 13, 2016 - DEC. 31, 2016		JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015
Net actuarial (gain) loss occurring during period	$	(10,198	)	$	16,056		$	3,128		$	2,292	$	—	$	(1,039	)
Net actuarial loss amortized during period	$	8,138		$	2,798		$	13,828		$	—	$	181	$	866
Prior service (credit) cost amortized during period	$	(51	)	$	(20	)	$	(71	)	$	—	$	34	$	119

The following table presents net gains/losses and prior period 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 2017 for the employee pension plan and other benefits plans for December 31, 2017, 2016, and 2015:

	PENSION BENEFITS									OTHER BENEFITS
	SUCCESSOR						PREDECESSOR			SUCCESSOR				PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2017			AT DEC. 31, 2016			AT DEC. 31, 2015			AT DEC. 31, 2017		AT DEC. 31, 2016		AT DEC. 31, 2015
Net actuarial loss	$	9,647		$	145,542		$	150,620		$	—	$	2,292	$	8,805
Prior service (credit) cost	$	(71	)	$	(274	)	$	(345	)	$	—	$	—	$	363

The components of net periodic pension and other benefits costs for 2016, 2015, and 2014 are as follows:

	PENSION BENEFITS												OTHER BENEFITS
	SUCCESSOR			PREDECESSOR									SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014			APR. 13, 2016 - DEC. 31, 2016		JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Components of periodic benefit costs
Service cost	$	6,909		$	2,563		$	10,419		$	8,050		$	1,112	$	431	$	1,635	$	1,542
Interest cost		15,088			6,242			20,795			19,851			1,237		476		1,607		1,809
Expected return on plan assets		(17,310	)		(6,812	)		(23,382	)		(24,507	)		—		—		—		—
Amortizations
Transition obligation		—			—			—			—			—		—		—		16
Prior period service (credit) cost		(51	)		(20	)		(71	)		(71	)		—		34		119		119
Net loss		8,138			2,798			13,828			6,743			—		181		866		670
Net periodic benefit cost	$	12,774		$	4,771		$	21,589		$	10,066		$	2,349	$	1,122	$	4,227	$	4,156

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During the third quarter of 2016, management finalized its remeasurement of the pension plan as of April 13, 2016, associated with the Merger. On the date of the remeasurement, the discount rate decreased from 4.62% to 4.21%. Prior to the remeasurement, Cleco’s 2016 net periodic benefit cost for the pension plan was expected to be $15.9 million. Due to the remeasurement of the pension plan, Cleco’s 2016 net periodic benefit cost increased to $17.5 million.

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 predecessor period January 1, 2016, through April 12, 2016, was $0.5 million. The expense of the pension plan related to Cleco’s other subsidiaries for the successor period April 13, 2016, through December 31, 2016 was $1.3 million. The amounts for the predecessor periods for 2015, and 2014 were $2.1 million and $1.7 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, 2016, 2015, and 2014 was $3.5 million, $3.6 million, and $3.6 million, respectively. The current and non-current portions of the other benefits liability for Cleco and Cleco Power at December 31, 2016, and 2015 are as follows:

Cleco

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current	$	3,854	$	3,613
Non-current	$	40,196	$	39,457

Cleco Power

(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current	$	3,345	$	3,140
Non-current	$	34,892	$	34,300

In March 2010, the President signed the PPACA, a comprehensive health care law. While all provisions of the PPACA are not effective immediately and the law has been amended since original enactment, management does not expect the provisions to materially impact Cleco’s retiree medical unfunded liability and related expenses. Management will continue to monitor this law and its possible impact.

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
	SUCCESSOR			PREDECESSOR			SUCCESSOR			PREDECESSOR
	AT DEC. 31, 2016			AT DEC. 31, 2015			AT DEC. 31, 2016			AT DEC. 31, 2015
Weighted-average assumptions used to determine the benefit obligation
Discount rate		4.27	%		4.62	%		3.81	%		4.08	%
Rate of compensation increase		3.03	%		3.08	%		N/A			N/A

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	PENSION BENEFITS												OTHER BENEFITS
	SUCCESSOR			PREDECESSOR									SUCCESSOR			PREDECESSOR
	APR. 13, 2016 -DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014			APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Weighted-average assumptions used to determine the net benefit cost
Discount rate		4.21	%		4.62	%		4.21	%		5.14	%		4.08	%		4.08	%		3.76	%		4.46	%
Expected return on plan assets		6.21	%		6.21	%		6.15	%		6.76	%		N/A			N/A			N/A			N/A
Rate of compensation increase		3.03	%		3.03	%		3.08	%		3.17	%		N/A			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 2017 periodic expense, Cleco decreased the expected long-term return on plan assets to 6.08%. Cleco expects pension expense to decrease in 2017 by approximately $2.2 million due to a higher than expected return on assets in 2016 and favorable mortality improvement scale updates, partially offset by a decrease in the discount rate.

Employee pension plan assets may be invested in publicly traded domestic common stocks; U.S. Government, federal agency, and corporate obligations; an international equity fund, commercial real estate funds; and pooled temporary investments. Investments in securities (obligations of U.S. Government, U.S. Government Agencies, and state and local governments, corporate debt, common/

collective trust funds, mutual funds, common stocks, and preferred stock) traded on a national securities exchange are valued at the last reported sales price on the last business day of the year.

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

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, 2016, and December 31, 2015. The following tables disclose the pension plan’s fair value of financial assets measured on a recurring basis:

	SUCCESSOR
(THOUSANDS)	AT DEC. 31, 2016		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	$	6,817	$	—	$	6,817	$	—
Common stock		19,311		19,311		—		—
Obligations of U.S. Government, U.S. Government Agencies, and state and local governments		47,543		—		47,543		—
Mutual funds
Domestic		52,663		52,663		—		—
International		31,191		31,191		—		—
Real estate funds		18,668		—		—		18,668
Corporate debt		185,659		—		185,659		—
Total	$	361,852	$	103,165	$	240,019	$	18,668
Investments measured at net asset value*		38,886
Interest accrual		2,977
Total net assets	$	403,715

* Investments measured at net asset value consist of Common/collective trust.

	PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2015		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	$	4,568	$	—	$	4,568	$	—
Common stock		13,816		13,816		—		—
Obligations of U.S. Government, U.S. Government Agencies, and state and local governments		48,792		—		48,792		—
Mutual funds
Domestic		47,801		47,801		—		—
International		22,853		22,853		—		—
Real estate funds		17,890		—		—		17,890
Corporate debt		182,408		—		182,408		—
Total	$	338,128	$	84,470	$	235,768	$	17,890
Investments measured at net asset value*		42,362
Interest accrual		3,042
Total net assets	$	383,532

* Investments measured at net asset value consist of Hedge fund-of-funds and Common/collective trust.

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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.

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, 2016, and 2015:

(THOUSANDS)
PREDECESSOR
Balance, Dec. 31, 2014	$	18,792
Realized gains		9
Unrealized losses		(148	)
Purchases		679
Sales		(1,442	)
Balance, Dec. 31, 2015	$	17,890
Realized gains		71
Unrealized gains		89
Purchases		26
Sales		(205	)
Balance, Apr. 12, 2016	$	17,871
SUCCESSOR
Balance, Apr. 13, 2016	$	17,871
Realized gains		151
Unrealized gains		226
Purchases		570
Sales		(151	)
Balance, Dec. 31, 2016	$	18,668

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 2016, the return on plan assets was 10.90% compared to an expected long-term return of 6.21%. The 2015 return on pension plan assets was (2.90)% compared to an expected long-term return of 6.15%.

As of December 31, 2016, none of the pension plan participants’ future annual benefits are covered by insurance contracts. In December 2008, Cleco became aware that, through its hedge fund-of-funds manager, a portion of its pension plan assets were invested in the Madoff feeder fund investment, Ascot Fund Limited. In January 2009, Cleco Power elected to liquidate the holdings of the hedge fund-of-funds manager. At December 31, 2016, all investments in the hedge fund-of-funds had been liquidated. Proceeds from the hedge fund-of-funds manager were reallocated to the plan’s other investment managers. The hedge fund-of-funds investment was measured at fair value using the net asset value per share as a practical expedient (or its equivalent) and was not classified in the fair value hierarchy for 2016.

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 assumed rate of return on plan assets, and

• Exceed the annualized total return of a customized index consisting of a mixture of S&P 500 Index, Russell 2500 Index, MSCI EAFE Index, Morgan Stanley Capital International Emerging Markets Index, Barclays Capital Long Credit Index, Barclays Capital Long Government/Credit Index, National Council of Real Estate Investment Fiduciaries Index, and U.S. Treasury Bills plus 5%.

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

Domestic Equity Portfolios

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

• A minimum of 25 stocks should be owned.

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

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

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

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

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

International Equity Portfolios

Developed Markets

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

• A minimum of 30 stocks should be owned.

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

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

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

Emerging Markets

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

• A minimum of 30 individual stocks should be owned.

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

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

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

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

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

Fixed Income Portfolio—Long Government/Credit

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

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

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

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

• Margin purchases or leverage is prohibited.

• The average weighted duration of portfolio security holdings, including derivative exposure, is expected to range within +/- 20% of the Barclays Long Gov/Credit Index duration.

Fixed Income Portfolio—Long Credit

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

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

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

• 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.

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.

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• 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:

• Debt portfolios are exempt from the prohibition on derivative use.

• Execution of target allocation rebalancing may be implemented through short- to intermediate-term use of derivatives overlay strategies. The notional value of derivative positions shall not exceed 20% of the total pension fund’s value at any given time.

The following chart shows the dynamic asset allocation based on the funded ratio at December 31, 2016:

	PERCENT OF TOTAL PLAN ASSETS
	MINIMUM			TARGET			MAXIMUM
Return-seeking
Domestic equity					18	%
International equity					17	%
Real estate					5	%
Total return-seeking		35	%		40	%		45	%
Liability hedging*		55	%		60	%		65	%

* Liability hedging is not target by subcategories.

The assumed health care cost trend rates used to measure the expected cost of other benefits is 5.0% for 2017 and remains at 5.0% thereafter. The rate used for 2016 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	$	19	$	(22	)
Effect on postretirement benefit obligation	$	238	$	(265	)

The projected benefit payments for the employee pension plan and other benefits obligation plan for each year through 2021 and the next five years thereafter are listed in the following table:

(THOUSANDS)	PENSION BENEFITS		OTHER BENEFITS, GROSS
2017	$	20,152	$	3,927
2018	$	21,265	$	3,951
2019	$	22,382	$	4,002
2020	$	23,719	$	4,006
2021	$	24,818	$	3,993
Next five years	$	141,584	$	18,190

SERP

Certain Cleco officers are covered by SERP. 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 three 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 limits of the 401(k) Plan. Two executive officers’ SERP benefits will be 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 will have their annual bonuses set at target rather than actual awards for years 2016 and 2017 for the average incentive award portion of their SERP benefit calculation. In 2014, SERP was closed to new participants; however, with regard to current SERP participants, including former employees or their beneficiaries, all terms of

F-58

SERP will continue, other than as described above. In accordance with the SERP plan document and the Merger Agreement, four executive officers received enhanced benefits, and upon termination of employment, two of these executive officers received accelerated vesting. Management will review 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 designated as the beneficiary for life insurance policies issued on SERP participants. 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 from which the officer retired. Cleco Power is considered the plan sponsor and Support Group is considered the plan administrator.

SERP’s funded status at December 31, 2016, and 2015 is presented in the following table:

	SERP BENEFITS
	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015
Change in benefit obligation
Benefit obligation at beginning of period	$	79,555		$	72,315		$	73,902
Service cost		571			702			2,705
Interest cost		2,275			900			3,056
Actuarial loss (gain)		1,152			—			(4,488	)
Benefits paid		(2,999	)		(1,186	)		(2,860	)
Plan amendments		(2,509	)
Curtailments					3,602
Special/contractual termination benefits					3,222
Benefit obligation at end of period	$	78,045		$	79,555		$	72,315

SERP’s accumulated benefit obligation at December 31, 2016, and 2015 is presented in the following table:

	SERP BENEFITS
	SUCCESSOR		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Accumulated benefit obligation	$	76,194	$	65,840

The following table presents net actuarial gains/losses and prior service costs 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 at December 31, 2016, and 2015:

	SERP BENEFITS
	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015
Net actuarial gain occurring during year	$	(1,345	)	$	—	$	(4,487	)
Net actuarial loss amortized during year	$	1,651		$	574	$	2,973
Prior service (credit) cost amortized during year	$	(50	)	$	17	$	54

The following table presents net gains/losses and prior period service costs/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 2017 for SERP for December 31, 2017, 2016, and 2015:

	SERP BENEFITS
	SUCCESSOR						PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2017			AT DEC. 31, 2016			AT DEC. 31, 2015
Net actuarial loss	$	1,634		$	20,999		$	23,763
Prior service (credit) cost	$	(190	)	$	(2,368	)	$	120

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The components of the net SERP costs for 2016, 2015, and 2014 are as follows:

	SERP BENEFITS
	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Components of periodic benefit costs
Service cost	$	571		$	702	$	2,705	$	2,278
Interest cost		2,275			900		3,056		3,028
Amortizations
Prior period service (credit) cost		(50	)		17		54		54
Net loss		1,651			574		2,973		1,875
Net periodic benefit cost	$	4,447		$	2,193	$	8,788	$	7,235
Curtailment charge	$	—		$	3,602	$	—	$	—
Special/contractual termination benefits	$	—		$	3,222	$	—	$	—
Total benefit cost	$	4,447		$	9,017	$	8,788	$	7,235

There was a remeasurement of SERP at April 13, 2016, to reflect change in control benefits as a result of the Merger. On the date of the remeasurement, the discount rate decreased from 4.60% to 4.15%. This remeasurement resulted in a $3.6 million curtailment charge and $3.2 million of special/contractual termination benefits. The curtailments and special/contractual termination benefits are included in Merger transaction and commitment costs on Cleco’s Consolidated Statements of Income. There was an additional remeasurement of SERP at August 31, 2016, to reflect changes to the plan relating to three executive officers’ SERP benefits being capped as of December 31, 2017, with regard to final compensation. On the date of the remeasurement, the discount rate decreased from 4.15% to 3.47%.

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
	SUCCESSOR			PREDECESSOR
	AT DEC. 31, 2016			AT DEC. 31, 2015
Weighted-average assumptions used to determine the benefit obligation
Discount rate		4.22	%		4.60	%
Rate of compensation increase		5.00	%		5.00	%

	SERP
	SUCCESSOR						PREDECESSOR
	SEPT. 1, 2016 - DEC. 31, 2016			APR. 13, 2016 - AUG. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Weighted-average assumptions used to determine the net benefit cost
Discount rate		3.47	%		4.15	%		4.60	%		4.20	%		5.09	%
Rate of compensation increase		5.00	%		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, 2016, 2015, and 2014 was $1.4 million, $2.2 million, and $1.7 million, respectively.

Liabilities relating to SERP are reported on the individual subsidiaries’ financial statements.The current and non-current portions of the SERP liability

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for Cleco and Cleco Power at December 31, 2016, and 2015 are as follows:

Cleco

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current	$	4,308	$	3,238
Non-current	$	73,738	$	69,049
Cleco Power
(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current	$	885	$	1,000
Non-current	$	15,145	$	21,321

The projected benefit payments for the SERP for each year through 2021 and the next five years thereafter are shown in the following table:

(THOUSANDS)	2017		2018		2019		2020		2021		NEXT FIVE YEARS
SERP	$	4,399	$	4,444	$	4,483	$	4,558	$	4,578	$	23,168

401(k)

Cleco’s 401(k) Plan is intended to provide active, eligible employees with voluntary, long-term savings and investment opportunities. The 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 Plan, employer contributions can be 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 expense for the years ended December 31, 2016, 2015, and 2014 is as follows:

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016		JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
401(k) Plan expense	$	3,554	$	1,593	$	5,029	$	4,730

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, 2016, 2015, and 2014 is as follows:

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016		JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
401(k) Plan expense	$	554	$	319	$	944	$	921

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Note 10—Income Taxes

Cleco

For the successor period April 13, 2016, through December 31, 2016, and the predecessor period for the year ended December 31, 2015, income tax expense was higher than the amount computed by applying the statutory federal rate. For the predecessor period January 1, 2016, through April 12, 2016, and for the predecessor period for the year ended December 31, 2014, income tax expense was lower than the amount computed by applying the statutory federal rate. The differences are as follows:

	SUCCESSOR			PREDECESSOR
(THOUSANDS, EXCEPT FOR %)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Income before tax	$	(46,935	)	$	(492	)	$	211,373		$	221,855
Statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Tax at federal statutory rate	$	(16,427	)	$	(172	)	$	73,981		$	77,649
Increase (decrease)
Plant differences, including AFUDC flowthrough		(881	)		823			1,875			462
Amortization of investment tax credits		(371	)		(124	)		(916	)		(983	)
State income taxes		(4,725	)		(3,078	)		1,117			23
Nondeductible merger costs		(844	)		4,282			—			—
Settlement with taxing authorities		—			—			—			(9,106	)
Return to accrual adjustment		(2,943	)		—			—			—
NMTC		(181	)		(158	)		243			(754	)
Other		3,550			1,895			1,404			(175	)
Total tax (benefit) expense	$	(22,822	)	$	3,468		$	77,704		$	67,116
Effective Rate		48.6	%		(704.9	)%		36.8	%		30.3	%

Information about current and deferred income tax expense is as follows:

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Current federal income tax (benefit) expense	$	(1,062	)	$	1,373		$	1,284		$	11,082
Deferred federal income tax (benefit) expense		(16,715	)		5,297			76,219			71,061
Amortization of accumulated deferred investment tax credits		(371	)		(124	)		(916	)		(983	)
Total federal income tax (benefit) expense	$	(18,148	)	$	6,546		$	76,587		$	81,160
Current state income tax (benefit) expense		(337	)		—			3,233			(6,580	)
Deferred state income tax (benefit) expense		(4,337	)		(3,078	)		(2,116	)		(7,464	)
Total state income tax (benefit) expense	$	(4,674	)	$	(3,078	)	$	1,117		$	(14,044	)
Total federal and state income tax (benefit) expense	$	(22,822	)	$	3,468		$	77,704		$	67,116
Items charged or credited directly to member’s/shareholders’ equity
Federal deferred		14,593			(277	)		3,274			(3,656	)
State deferred		2,441			(45	)		528			(590	)
Total tax expense (benefit) from items charged directly to member’s/shareholders’ equity	$	17,034		$	(322	)	$	3,802		$	(4,246	)
Total federal and state income tax (benefit) expense	$	(5,788	)	$	3,146		$	81,506		$	62,870

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The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2016, and 2015 was comprised of the following:

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Depreciation and property basis differences	$	(943,552	)	$	(948,597	)
Net operating loss carryforward		54,727			12,092
NMTC		89,411			87,544
Fuel costs		(8,802	)		(7,833	)
Other comprehensive income		3,399			15,774
Regulated operations regulatory liability, net		(91,734	)		(90,122	)
Postretirement benefits other than pension		22,733			11,561
Merger fair value adjustments		(124,254	)		—
Other		(34,983	)		(5,522	)
Accumulated deferred federal and state income taxes, net	$	(1,033,055	)	$	(925,103	)

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, 2016, and 2015, Cleco had a deferred tax asset resulting from NMTC carryforwards of $97.5 million and $96.5 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

As of December 31, 2016, Cleco had a federal net operating loss carryforward of $89.9 million and a state net operating loss carryforward of $201.1 million. The federal and state net operating loss carryforwards will begin to expire in 2031. Cleco considers it more likely than not that these income

tax losses will be utilized to reduce future payments of income taxes and Cleco expects to utilize the entire net operating loss carryforward within the statutory deadlines.

Cleco Power

For the years ended December 31, 2016, and 2014 income tax expense was lower than the amount computed by applying the statutory rate. For the year ended December 31, 2015, income tax expense was higher than the amount computed by applying the statutory federal rate to income before tax. The differences are as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT FOR %)	2016			2015			2014
Income before tax	$	57,497		$	220,644		$	231,290
Statutory rate		35.0	%		35.0	%		35.0	%
Tax at federal statutory rate	$	20,124		$	77,225		$	80,952
Increase (decrease):
Plant differences, including AFUDC flowthrough		(58	)		1,875			462
Amortization of investment tax credits		(494	)		(916	)		(983	)
State income taxes		(2,573	)		1,501			351
Settlement with taxing authorities		—			—			(2,320	)
Return to accrual adjustment		(2,646	)		—			—
Other		4,016			(391	)		(1,488	)
Total taxes	$	18,369		$	79,294		$	76,974
Effective Rate		31.9	%		35.9	%		33.3	%

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Information about current and deferred income tax expense is as follows:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016			2015			2014
Current federal income tax (benefit) expense	$	(1,211	)	$	33,138		$	(197	)
Deferred federal income tax expense		22,647			45,572			83,676
Amortization of accumulated deferred investment tax credits		(494	)		(916	)		(983	)
Total federal income tax expense	$	20,942		$	77,794		$	82,496
Current state income tax (benefit) expense		(418	)		3,397			(4,161	)
Deferred state income tax benefit		(2,155	)		(1,897	)		(1,361	)
Total state income tax (benefit) expense	$	(2,573	)	$	1,500		$	(5,522	)
Total federal and state income taxes	$	18,369		$	79,294		$	76,974
Items charged or credited directly to members’ equity
Federal deferred		1,976			106			(1,137	)
State deferred		319			17			(184	)
Total tax expense (benefit) from items charged directly to member’s equity	$	2,295		$	123		$	(1,321	)
Total federal and state income tax expense	$	20,664		$	79,417		$	75,653

The balance of accumulated deferred federal and state income tax assets and liabilities at

December 31, 2016, and 2015 was comprised of the following:

(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Depreciation and property basis differences	$	(941,166	)	$	(944,675	)
Net operating loss carryforward		(362	)		18
Fuel costs		(8,802	)		(7,833	)
Other comprehensive income		8,021			9,878
Regulated operations regulatory liability, net		(91,734	)		(90,122	)
Postretirement benefits other than pension		1,288			(3,853	)
Other		(35,837	)		(6,944	)
Accumulated deferred federal and state income taxes, net	$	(1,068,592	)	$	(1,043,531	)

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, 2016, and 2015, Cleco and Cleco Power had no interest payable related to uncertain tax positions. The interest payable reflects the amount of interest anticipated to be paid to or received from taxing authorities. These amounts do not include any offset for amounts that may be recovered from customers under the existing rate orders. The amounts expected to be recoverable from Cleco Power’s customers under existing rate orders for settled positions at December 31, 2016, and 2015, are $2.5 million and $1.3 million, respectively. For the years ended December 31, 2016, 2015, and 2014, Cleco and Cleco Power had no interest expense related to uncertain tax positions.

At December 31, 2016, and 2015, Cleco had no liability for unrecognized tax benefits. The total

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liability for unrecognized tax benefits for Cleco at December 31,2014 is shown in the following table:

Cleco

(THOUSANDS)	LIABILITY FOR UNRECOGNIZED TAX BENEFITS
PREDECESSOR
Balance, Jan. 1, 2014	$	5,071
Reduction for tax positions of current period		—
Additions for tax positions of prior years		—
Reduction for tax positions of prior years		—
Reduction for settlement with tax authority		(5,071	)
Reduction for lapse of statute of limitations		—
Balance, Dec. 31, 2014	$	—

At December 31, 2016, 2015, and 2014, Cleco Power had no liability for unrecognized tax benefits.

The federal income tax years that remain subject to examination by the IRS are 2012, 2013, 2014, and 2015. The IRS has concluded its audit for the years 2010 through 2014.

Beginning with the 2013 tax year, Cleco entered into the IRS’s Compliance Assurance Process which allows taxpayers to work collaboratively with an IRS team to identify and resolve potential tax issues before the federal tax return is filed each year. Cleco must apply for admission to the program each year. Cleco has been approved for the Compliance Assurance Process through the 2017 tax year.

The state income tax years that remain subject to examination by the Louisiana Department of Revenue are 2014 and 2015. In August 2014, Cleco reached a settlement for tax years 2001 through 2010. In August 2015, Cleco reached a settlement for tax years 2011 through 2013. The favorable impact from the settlement was reflected in various line items in the financial statements.

At December 31, 2016, and 2015, Cleco had no liability for uncertain tax positions. The settlement of open tax years could involve the payment of additional taxes, the adjustment of deferred taxes, and/or the recognition of tax benefits, which may have an effect on Cleco’s effective tax rate.

Cleco classifies income tax penalties as a component of other expenses. For the years ended December 31, 2016, and 2015, no penalties were recognized. For the year ended December 31, 2014, $0.1 million of penalties was recognized.

Note 11—Disclosures about Segments

Cleco

Cleco’s reportable segment is based on its method of internal reporting, which disaggregates business units by its first-tier subsidiary. As a result of the Coughlin transfer from Evangeline to Cleco Power in March 2014, Midstream no longer meets the requirements to be disclosed as a separate reportable segment. Management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to Cleco Power’s financial statements. As a result, Cleco’s segment reporting disclosures were not retrospectively adjusted to reflect the transfer. For more information, see Note 18—“Coughlin Transfer.” Beginning in April 2014, the remaining operations of Midstream are included as Other in the following table, along with the holding company, a shared services subsidiary, two transmission

interconnection facility subsidiaries, and an investment subsidiary.

Cleco Power, the 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 financial results of Cleco’s segment is presented on an accrual basis. Management evaluates the performance of its segment and allocates resources to it based on segment profit and the requirements to implement new strategic initiatives and projects to meet current business objectives. Material

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intercompany transactions occur on a regular basis. These intercompany transactions relate primarily to

joint and common administrative support services provided by Support Group.

SEGMENT INFORMATION

	SUCCESSOR APR. 13, 2016—DEC. 31, 2016												PREDECESSOR JAN. 1, 2016—APR. 12, 2016
(THOUSANDS)	CLECO POWER			OTHER			ELIMINATIONS			TOTAL			CLECO POWER			OTHER			ELIMINATIONS			TOTAL
Revenue
Electric operations	$	810,075		$	(7,482	)	$	(1	)	$	802,592		$	281,154		$	—		$	—		$	281,154
Other operations		50,080			1,482			—			51,562			18,493			587			—			19,080
Electric customer credits		(1,149	)		—			—			(1,149	)		(364	)		—			—			(364	)
Affiliate revenue		621			35,602			(36,223	)		—			263			15,024			(15,287	)		—
Operating revenue, net	$	859,627		$	29,602		$	(36,224	)	$	853,005		$	299,546		$	15,611		$	(15,287	)	$	299,870
Depreciation and amortization	$	102,444		$	7,296		$	(1	)	$	109,739		$	43,698		$	377		$	1		$	44,076
Merger transaction and commitment costs	$	151,501		$	23,195		$	—		$	174,696		$	—		$	34,928		$	(16	)	$	34,912
Interest charges	$	54,606		$	35,246		$	(86	)	$	89,766		$	21,840		$	295		$	(12	)	$	22,123
Interest income	$	652		$	275		$	(87	)	$	840		$	208		$	69		$	(12	)	$	265
Federal and state income tax expense (benefit)	$	5,376		$	(28,198	)	$	—		$	(22,822	)	$	12,993		$	(9,525	)	$	—		$	3,468
Net income (loss)	$	17,580		$	(41,692	)	$	(1	)	$	(24,113	)	$	21,548		$	(25,508	)	$	—		$	(3,960	)
Additions to property, plant, and equipment	$	143,790		$	654		$	—		$	144,444		$	42,353		$	39		$	—		$	42,392
Equity investment in investee	$	18,672		$	—		$	—		$	18,672
Goodwill	$	1,490,797		$	—		$	—		$	1,490,797
Total segment assets	$	5,758,245		$	614,959		$	(30,060	)	$	6,343,144

	PREDECESSOR FOR THE YEAR ENDED DEC. 31, 2015
(THOUSANDS)	CLECO POWER			OTHER			ELIMINATIONS			TOTAL
Revenue
Electric operations	$	1,142,389		$	—		$	—		$	1,142,389
Other operations		67,109			2,078			(1	)		69,186
Electric customer credits		(2,173	)		—			—			(2,173	)
Affiliate revenue		1,142			57,323			(58,465	)		—
Operating revenue, net	$	1,208,467		$	59,401		$	(58,466	)	$	1,209,402
Depreciation and amortization	$	147,839		$	1,739		$	1		$	149,579
Merger transaction costs	$	—		$	4,592		$	(1	)	$	4,591
Interest charges	$	76,560		$	1,149		$	282		$	77,991
Interest income	$	725		$	(111	)	$	281		$	895
Federal and state income tax expense (benefit)	$	79,294		$	(1,590	)	$	—		$	77,704
Net income (loss)	$	141,350		$	(7,681	)	$	—		$	133,669
Additions to property, plant, and equipment	$	156,357		$	462		$	—		$	156,819
Equity investment in investee	$	16,822		$	—		$	—		$	16,822
Total segment assets	$	4,233,337		$	21,471		$	68,546		$	4,323,354

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	PREDECESSOR FOR THE YEAR ENDED DEC. 31, 2014
(THOUSANDS)	CLECO POWER			OTHER			ELIMINATIONS			TOTAL
Revenue
Electric operations	$	1,225,960		$	—		$	—		$	1,225,960
Tolling operations		—			5,467			(5,467	)		—
Other operations		64,893			2,163			(1	)		67,055
Electric customer credits		(23,530	)		—			—			(23,530	)
Affiliate revenue		1,326			56,031			(57,357	)		—
Operating revenue, net	$	1,268,649		$	63,661		$	(62,825	)	$	1,269,485
Depreciation and amortization	$	144,026		$	2,479		$	—		$	146,505
Merger transaction costs	$	—		$	17,848		$	—		$	17,848
Interest charges	$	74,673		$	(1,538	)	$	471		$	73,606
Interest income	$	1,707		$	(410	)	$	471		$	1,768
Federal and state income tax expense (benefit)	$	76,974		$	(9,858	)	$	—		$	67,116
Net income (loss)	$	154,316		$	424		$	(1	)	$	154,739
Additions to property, plant, and equipment	$	206,607		$	1,029		$	—		$	207,636
Equity investment in investees	$	14,532		$	8		$	—		$	14,540
Total segment assets	$	4,232,942		$	248,043		$	(112,567	)	$	4,368,418

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 12—Regulation and Rates

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 first complaint, filed in November 2013, is for the period November 2013 through February 2015. On September 29, 2016, FERC issued a Final Order in response to the first complaint establishing a 10.32% ROE.

The second complaint, filed in February 2015, is for the period February 2015 through May 2016. In June 2016, an ALJ issued an initial decision in the second rate case docket recommending a 9.70% base ROE. A binding FERC order on the second ROE complaint is expected in the second quarter of 2017.

As of December 31, 2016, Cleco Power had $3.3 million accrued for ROE reductions, including accrued interest. On February 13, 2017, $1.2 million of refunds relating to the first complaint were submitted to MISO.

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 the 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 is ultimately subject to LPSC approval. Cleco Power must file annual monitoring reports no later than October 31 for the 12-month period ending June 30. Cleco Power was scheduled to file an application with the LPSC for a new FRP by June 30, 2017. However, as part of the merger approval process, Cleco Power agreed not

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to file an application for a new FRP or request an increase in base rates until June 30, 2019, with anticipated new rates being effective July 1, 2020.

In October 2015, Cleco Power filed its monitoring report for the 12-month period ended June 30, 2015, which indicated that $0.2 million was due to be returned to eligible customers. On July 27, 2016, the LPSC Staff issued their report indicating agreement with Cleco Power’s refund calculation for the 12-month period ended June 30, 2015. The $0.2 million was refunded to eligible customers in September 2016. On October 31, 2016, Cleco Power filed its monitoring report for the 12-month period ended June 30, 2016, which indicated that no refund was due as a result of the FRP, and $0.3 million was due as a result of the cost of service savings from the Merger Commitments. On December 28, 2016, Cleco Power received its first set of data requests pertaining to the monitoring report and has filed responses. On February 2, 2017, Cleco Power received a second set of data requests. Cleco Power is in the process of preparing responses to these requests. For more information on Merger Commitments, see “—Merger Commitments.”

Merger Commitments

On March 28, 2016, the LPSC approved the Merger. The LPSC’s written order approving the Merger was issued on April 7, 2016. Approval of the Merger was conditioned upon certain commitments, including $136.0 million of customer rate credits. On April 28, 2016, the LPSC voted to issue credits equally to eligible customers with service as of June 30, 2016, beginning in July 2016. As of December 31, 2016, Cleco Power had issued $121.5 million of customer rate credits. Also included in the 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 for economic development in Cleco Power’s service territory to be administered by the LED, and $6.0 million of charitable contributions to be disbursed over five years.

In addition, the Merger Commitments included $1.2 million of annual estimated cost of service savings expected as a result of the Merger. The cost savings is not subject to the target ROE or any sharing mechanism in the current FRP and will continue until Cleco Power files for a new FRP in 2019. The cost savings will be refunded to customers annually beginning in September 2017. As of December 31, 2016, Cleco Power had $0.9 million accrued for the cost savings refund. A report on the status of the Merger Commitments must be filed annually by October 31 for the 12-month period ended June 30. On October 31, 2016, Cleco Power filed the annual Merger Commitment status report for the period ended June 30, 2016.

Other

On April 8, 2016, the LPSC issued Docket No. R-34026 to investigate 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 customers. Cleco Power filed a motion to intervene in this proceeding along with other Louisiana utilities. On April 8, 2016, the LPSC also issued Docket No. R-34029 to investigate tax structure issues for all LPSC-jurisdictional utilities to consider whether only the state and federal taxes included in a utility’s retail rate 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. On October 4, 2016, Cleco received the first set of data requests from the LPSC Staff for each of the above mentioned dockets. Cleco has filed responses to the non-confidential requests and is waiting on the completion of a confidentiality agreement to respond to the confidential requests. Cleco anticipates the completion of this agreement in the second quarter of 2017.

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 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.

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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, 2016, consisted of its equity investment of $18.7 million. During 2016, Cleco Power made $2.5 million of cash contributions to its equity investment in Oxbow as a result of the expected transition from the Dolet Hills mine to the Oxbow mine in the second quarter of 2017. During 2016, Cleco Power received $0.6 million from Oxbow as a return of investment.

The following table presents the components of Cleco Power’s equity investment in Oxbow:

INCEPTION TO DATE (THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Purchase price	$	12,873		$	12,873
Cash contributions		6,399			3,949
Dividend received		(600	)		—
Total equity investment in investee	$	18,672		$	16,822

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 DEC. 31, 2016		AT DEC. 31, 2015
Oxbow’s net assets/liabilities	$	37,345	$	33,645
Cleco Power’s 50% equity	$	18,672	$	16,822
Cleco Power’s maximum exposure to loss	$	18,672	$	16,822

The following tables contain summarized financial information for Oxbow:

(THOUSANDS)	AT DEC. 31, 2016		AT DEC. 31, 2015
Current assets	$	886	$	2,794
Property, plant, and equipment, net		25,864		23,749
Other assets		10,971		7,220
Total assets	$	37,721	$	33,763
Current liabilities	$	376	$	118
Partners’ capital		37,345		33,645
Total liabilities and partners’ capital	$	37,721	$	33,763

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016		2015		2014
Operating revenue	$	5,459	$	3,991	$	2,248
Operating expenses		5,459		3,991		2,248
Income before taxes	$	—	$	—	$	—

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

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

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Note 14—Operating Leases

Cleco maintains operating leases in its ordinary course of business activities. For the years ended December 31, 2016, 2015, and 2014, operating lease expense of $9.0 million, $9.4 million, and $9.4 million was recognized, respectively. The following table is a summary of expected operating lease payments for Cleco and Cleco Power:

(THOUSANDS)	CLECO HOLDINGS		CLECO POWER		TOTAL
Year ending Dec. 31,
2017	$	315	$	6,505	$	6,820
2018		313		2,939		3,252
2019		—		2,823		2,823
2020		—		2,801		2,801
2021		—		2,396		2,396
Thereafter		—		3,301		3,301
Total operating lease payments	$	628	$	20,765	$	21,393

Cleco Power leases utility systems from two municipalities and one non-municipal public body.

The first municipal lease has a term of 10 years and expires on August 11, 2021. The second municipal lease has a term of 10 years and expires on May 13, 2018. The non-municipal lease has a term of 27 years and expires on July 31, 2039. Each utility system lease contains provisions for extensions.

Cleco Power has leases for 231 railcars for coal transportation. One lease for 115 railcars expires on March 31, 2021. The other lease for 116 railcars expires on March 31, 2017 and management is evaluating future options. Cleco Power pays a monthly rental fee per car. The railcar leases do not contain contingent rent payments.

Cleco Power leases three towboats to push the barges that deliver solid fuels to the plant site. The lease agreement for these towboats expires on August 31, 2017. Cleco Power pays a fixed amount for the towboats that is adjusted annually.

Cleco and Cleco Power’s remaining leases provide for office and operating facilities, office equipment, tower rentals, and vehicles.

Note 15—Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees

Litigation

Devil’s Swamp

In October 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study (RI/FS) from the EPA pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (also known as the Superfund statute) for a facility known as the Devil’s Swamp Lake site located just northwest of Baton Rouge, Louisiana. The special 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. 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 on March 8, 2004, based on the release of PCBs to fisheries and wetlands located on the site, but no final listing decision has yet been made. The PRPs began discussing a potential proposal to the EPA in February 2008. The EPA

issued a Unilateral Administrative Order to two PRP’s, Clean Harbors, Inc. and Baton Rouge Disposal, to conduct an RI/FS in December 2009. The Tier 1 part of the study was completed in June 2012. Field activities for the Tier 2 investigation were completed in July 2012. The draft Tier 2 remedial investigation report was submitted in December 2014. In 2015, remedial investigation activities included the collection and analysis of sediment, crawfish, and fish tissue samples. After reviewing the sample analysis, in August 2015, the Louisiana Department of Health and Hospitals updated the advisory for the area to advise that fish and crawfish from the area should not be eaten. The final Tier 2 remedial investigation report was made public in December 2015. Currently, the study/remedy selection task continues, and there is no record of a decision. Therefore, management is unable to determine how significant Cleco’s share of the costs associated with the RI/FS and possible response action at the site, if any, may be and whether this will have a material impact on the results of operations, financial condition, or cash flows of the Registrants.

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Merger

In connection with the 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 the Cleco Corporation’s Board of Directors breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process, agreeing to the Merger at a price that allegedly undervalued Cleco, and failing to disclose material information about the 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 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).

On November 14, 2014, the plaintiff in theBraunstein action moved for a dismissal of the action without prejudice, and that motion was granted on November 19, 2014. On December 3, 2014, the Court consolidated the remaining three actions and appointed interim co-lead counsel. On December 18, 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 names Cleco Corporation, its directors, Cleco Partners, and Merger Sub as defendants. The Consolidated Amended Petition alleges, 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 Merger. The Consolidated Amended Petition further alleges 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 theButler andCashen actions name Cleco Corporation, its directors, Cleco Partners, Merger Sub, MIRA, bcIMC, and John Hancock Financial as defendants. TheCreative Life Services action names Cleco Corporation, its directors, Cleco Partners, Merger Sub, MIRA, and Macquarie Infrastructure Partners III, L.P., as defendants. On December 11, 2014, the plaintiff in theButler action filed an Amended Class Action Petition for Damages. Each petition alleges, among other things, that members of Cleco Corporation’s Board of Directors breached their fiduciary duties to Cleco’s shareholders by approving the Merger Agreement because it allegedly does 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. TheButler andCreative Life Services petitions also allege that the directors breached their fiduciary duties by failing to disclose material information about the 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. On December 23, 2014, the directors and Cleco filed declinatory exceptions in each action on the basis that each action was improperly brought in

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Orleans Parish and should either be transferred to the Ninth Judicial District Court for Rapides Parish or dismissed. On December 30, 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. On January 23, 2015, the Court in theCreative 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. On February 5, 2015, the plaintiffs inButler and Cashen also consented to the dismissal of their cases from Orleans Parish so they could be transferred to the Ninth Judicial District Court for Rapides Parish.

On February 25, 2015, the Ninth Judicial District Court for Rapides Parish held a hearing on a motion for preliminary injunction filed by plaintiffsMoore,L’Herisson, andTrahan seeking to enjoin the shareholder vote at the Special Meeting of Shareholders held on February 26, 2015, for approval of the Merger Agreement. Following the hearing, the Court denied the plaintiffs’ motion. On June 19, 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 Ninth Judicial District Court for Rapides Parish. Cleco filed exceptions seeking dismissal of the amended petition on July 24, 2015. 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.

On March 21, 2016, the plaintiffs filed their Third Consolidated Amended Verified Derivative Petition for Damages and Preliminary and Permanent Injunction. On May 13, 2016, the plaintiffs filed their Fourth Verified Consolidated Amended Class Action Petition. This 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 on September 15, 2016. On September 26, 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 to the Louisiana Third Circuit Court of Appeal on November 9, 2016. A briefing schedule has not yet been set.

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. On January 21, 2016, Cleco appealed the District Court’s denial of its exception by filing with the Third Circuit Court of Appeal for the State of Louisiana. On June 30, 2016, the Third Circuit Court of Appeal for the State of Louisiana denied the request to have the case dismissed. On July 29, 2016, Cleco filed a writ to the Louisiana Supreme Court seeking a review of the District Court’s denial of Cleco’s exception. On November 15, 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. On May 16, 2016, the District Court lifted the stay at the request of Gulf Coast. Cleco believes the allegations of the petition are contradicted by the written documents executed by Gulf Coast and are otherwise without merit and that it has substantial meritorious defenses to the claims alleged by Gulf Coast.

LPSC Audits

Fuel Audit

Generally, the cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through the LPSC-

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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. On February 3, 2016, the LPSC initiated an audit of Cleco Power’s fuel and purchased power expenses for the period January 2014 through December 2015. The total amount of fuel expense included in the audit was $582.6 million. On January 19, 2017, the LPSC Staff issued its audit report which recommended no disallowance of fuel costs. Management expects the report to be approved by the LPSC in the second quarter of 2017. Cleco Power currently has FAC filings for 2016 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.

Environmental Audit

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides for 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. On February 3, 2016, the LPSC initiated an audit of Cleco Power’s environmental costs for the period November 2010 through December 2015. The total amount of environmental costs included in this audit was $81.2 million. On December 1, 2016, the LPSC Staff issued its audit report which recommended a disallowance of environmental costs of less than $0.1 million. The report was approved by the LPSC on February 17, 2017. Cleco Power currently has EAC filings for 2016 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.

Cleco Power began incurring additional environmental compliance expenses in the second

quarter of 2015 for reagents associated with compliance with 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. On April 15, 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 24, 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. These expenses are also eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC.

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 current 12.38% ROE used in MISO’s transmission rates to a proposed 6.68%. The first complaint, filed in November 2013, is for the period November 2013 through February 2015. In December 2015, an ALJ issued an initial decision recommending a 10.32% ROE. On September 29, 2016, FERC issued a Final Order confirming the ALJ’s recommendation of a 10.32% ROE.

In February 2015, the second ROE complaint was filed for the period February 2015 through May 2016. In June 2016, an ALJ issued an initial decision in the second rate case docket recommending a 9.70% base ROE. A binding FERC order on the second ROE complaint is expected in the second quarter of 2017.

In November 2014, the MISO transmission owners committee, in 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. The collection of the adder is delayed until the resolution of the ROE complaint proceeding.

As of December 31, 2016, Cleco Power had $3.3 million accrued for a reduction to the ROE, including

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accrued interest. On February 13, 2017, $1.2 million of refunds relating to the first complaint were submitted to MISO. Management believes a reduction in the ROE, as well as any additional refund, will not have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.

Other

Cleco is involved in various litigation matters, including regulatory, environmental, and administrative proceedings before various courts, regulatory commissions, arbitrators, and governmental agencies regarding matters arising in the ordinary course of business. The liability Cleco may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued. Management regularly analyzes current information and, as of December 31, 2016, believes the probable and reasonably estimable liabilities based on the eventual disposition of these matters is $4.8 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 standing 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 these 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 facility in 2005. At December 31, 2016, the remaining indemnifications relate to environmental matters that may have been present prior to closing. These remaining indemnifications have no limitations to time. The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million. Currently, management does not expect to be required to pay Entergy Louisiana and Entergy Gulf States under 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. At December 31, 2016, the remaining indemnifications relate to the fundamental organizational structure of Acadia. These remaining indemnifications have no limitations as to time or maximum potential future payments. Currently, 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. Currently, 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, 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.

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Previously, Cleco Power recorded a liability of $3.8 million related to the amended agreement with an offsetting regulatory asset. Management determined that it does not expect to be required to pay DHLC under this guarantee. As a result of this determination, the liability and the offsetting regulatory asset were remeasured to zero during the second quarter of 2016. 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 $106.5 million; however, the Amended Lignite Mining Agreement does not contain a cap. The projection is based on the forecasted loan and lease obligations to be incurred by DHLC, primarily for purchases of equipment. Cleco Power has the right to dispute the incurrence of loan and lease obligations through the review of the mining plan before the incurrence of such loan and lease obligations. The Amended Lignite Mining Agreement 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.

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.

Long-Term Purchase Obligations

Cleco Holdings had no unconditional long-term purchase obligations at December 31, 2016. Cleco Power has several unconditional long-term purchase obligations related to the purchase of petroleum coke, limestone, and energy delivery facilities. The aggregate amount of payments required under such obligations at December 31, 2016, is as follows:

YEAR ENDING DEC. 31,	(THOUSANDS)
2017	$	56,482
2018		14,905
2019		3,688
Total long-term purchase obligations	$	75,075

Payments under these agreements for the years ended December 31, 2016, 2015, and 2014 were $72.9 million, $89.7 million, and $90.4 million, respectively.

Other Commitments

NMTC Fund

In 2008, Cleco Holdings and US Bancorp Community Development (USBCDC) formed the NMTC Fund. Cleco Holdings has a 99.9% membership interest in the NMTC Fund and USBCDC has a 0.1% interest. The purpose of the NMTC Fund is to invest in projects located in qualified active low-income communities that are underserved by typical debt capital markets. These investments are designed to generate NMTCs and Historical Rehabilitation tax credits. The NMTC Fund was later amended to include renewable energy investments. The majority of the energy investments qualify for grants under Section 1603 of the ARRA. The tax benefits received from the NMTC Fund reduce the federal income tax obligations of Cleco Holdings. In total, Cleco Holdings contributed $285.5 million of equity contributions to the NMTC Fund and will receive at least $303.8 million in the form of tax credits, tax losses, capital gains/losses, earnings, and cash over the life of the investment, which ends in 2018. The $18.3 million difference between equity contributions and total benefits received will be recognized over the life of the NMTC Fund as net tax benefits are delivered.

Due to the right of offset, the investment and associated debt are presented on Cleco’s Consolidated Balance Sheets in the line item titled Tax credit fund investment, net. At December 31, 2016, and 2015 the amount of the liability component contained in the net asset was $0.6 million and zero, respectively. The liability at December 31, 2016, is expected to be paid in the first quarter of 2017. The amount of tax benefits delivered in excess of capital contributions as of December 31, 2016, was $17.3 million. The amount of tax benefits delivered but not utilized as of December 31, 2016, was $116.2 million and is reflected as a deferred tax asset.

By using the cost method for investments, the gross investment amortization expense will be recognized over a ten-year period, with two years remaining under the new amendment. The basis of the

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investment is reduced by the grants received under Section 1603 of the ARRA, which allow certain projects to receive a federal grant in lieu of tax credits, and other cash. Periodic amortization of the investment and the deferred taxes generated by the basis reduction temporary difference are included as components of income tax expense.

Fuel Transportation Agreement

In October 2007, Cleco Power entered into an agreement with Savage Services that met the accounting definition of a capital lease for barges in order to transport petroleum coke and limestone to Madison Unit 3. On December 28, 2012, Cleco Power entered into an amended agreement for 42 dedicated barges. The amended agreement continues to meet the accounting definition of a capital lease.

Under the amended agreement, the barge lease rate contains both fixed and variable components, of which the latter is adjusted annually per the Producer Price Index (PPI) for executory costs. The initial term of this agreement is from the date of the amendment until August 31, 2017. The term of this agreement will automatically renew for successive periods of two years each unless written notice is provided by either party. The amended agreement contains a provision for early termination upon the occurrence of any one of four specified cancellation events. Cleco is evaluating future options related to its fuel transportation agreement with Savage Services.

Under both the original agreement and the amended agreement, if the barges are idle, the lessor is required to attempt to sublease the barges to third parties, with the revenue reducing Cleco Power’s lease payment. During the year ended December 31, 2016, Cleco Power paid approximately $3.7 million in lease payments and received less than $0.1 million revenue from subleases. During the year ended December 31, 2015, Cleco Power paid approximately $3.7 million in lease payments and received $0.5 million in revenue from subleases.

The following is an analysis of leased property under capital leases by major classes:

	AT DEC. 31,
CLASSES OF PROPERTY (THOUSANDS)	2016		2015
Barges	$	11,350	$	11,350
Less: accumulated amortization		9,729		7,296
Net capital leases	$	1,621	$	4,054

The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2016:

(THOUSANDS)
Year ending December 31, 2017	$	2,480
Less: executory costs		620
Net minimum lease payments		1,860
Less: amount representing interest		41
Present value of net minimum lease payments	$	1,819
Current liabilities	$	1,819

During the years ended December 31, 2016, and 2015, Cleco Power incurred immaterial amounts of contingent rent under the barge agreement related to the increase in the PPI.

Other

Cleco has accrued for liabilities related to third parties, employee medical benefits, and AROs. For more information on AROs, see Note 2—“Summary of Significant Accounting Policies—AROs” and Note 4—“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. On April 8, 2016, taking into consideration the

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anticipated completion of the Merger, S&P and Moody’s downgraded Cleco Holdings’ credit rating to BBB- (stable) and Baa3 (stable), respectively. On April 8, 2016, taking into consideration the anticipated completion of the Merger, S&P and Moody’s credit ratings were maintained at Cleco Power at BBB+ (stable) and A3 (stable), respectively. Any downgrade of credit ratings would result in additional fees and higher interest rates under its bank credit facilities and, potentially, other debt agreements.

Changes in the regulatory environment or market forces could cause Cleco to determine its assets have suffered an other-than-temporary decline in value, whereby an impairment would be required and

Cleco’s financial condition could be materially adversely affected.

Cleco Power is a participant 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 a higher LMP. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power’s pricing zones. Cleco Power uses FTRs to mitigate transmission congestion risk. Changes to anticipated transmission paths may result in an unexpected increase in energy costs to Cleco Power.

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. In March, 2014, Coughlin was transferred to Cleco Power. Until the transfer in 2014, Midstream provided electric power plant operations and maintenance expertise, primarily to Evangeline.

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, 2016, 2015, and 2014.

At December 31, 2016, Cleco Holdings had accounts receivable of less than $0.1 million due from Cleco Group in relation to merger costs paid on behalf of Cleco Group. At December 31, 2016, Cleco Holdings had no accounts payable due to Cleco Group. At December 31, 2015, Cleco had no affiliate balances that were payable to or receivable from non-consolidated affiliates.

During the successor period April 13, 2016, through December 31, 2016, Cleco Holdings received $100.7 million of equity contributions from Cleco Group and made $88.8 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. In March 2014, Coughlin was transferred to Cleco Power. Prior to the transfer, charges from affiliates also included power purchased from Evangeline. 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

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management; and other administrative services. For information on the transfer of Coughlin, see Note 18—“Coughlin Transfer.”

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)	2016		2015			2014
Support Group
Other operations	$	46,116	$	53,079		$	50,801
Maintenance	$	2,255	$	1,807		$	2,091
Taxes other than income taxes	$	10	$	(3	)	$	(9	)
Other expenses	$	106	$	403		$	339
Evangeline
Purchased power expense	$	—	$	—		$	5,467

The majority of the services provided by Cleco Power relates to the lease of office space to Support Group. Cleco Power charges affiliates the higher of management’s estimated fair market value or fully loaded costs for goods and services provided in accordance with service agreements.

The following table is a summary of revenue received from affiliates included in Cleco Power’s Consolidated Statements of Income:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016		2015		2014
Affiliate revenue
Support Group	$	884	$	1,142	$	1,322
Evangeline		—		—		4
Total affiliate revenue	$	884	$	1,142	$	1,326
Other income
Cleco Holdings	$	19	$	3	$	30
Support Group		—		—		10
Evangeline		—		—		9
Diversified Lands		—		10		14
Perryville		6		—		5
Attala		6		—		5
Total other income	$	31	$	13	$	73
Total	$	915	$	1,155	$	1,399

Cleco Power had the following affiliate receivable and payable balances associated with the service agreements:

	AT DEC. 31, 2016				AT DEC. 31, 2015
(THOUSANDS)	ACCOUNTS RECEIVABLE		ACCOUNTS PAYABLE		ACCOUNTS RECEIVABLE		ACCOUNTS PAYABLE
Cleco Holdings	$	3	$	119	$	653	$	564
Support Group		1,402		7,071		1,254		6,034
Other(1)		1		—		1		—
Total	$	1,406	$	7,190	$	1,908	$	6,598

(1) Represents Attala and Perryville in 2016 and Attala, Diversified Lands, and Perryville in 2015.

During 2016, 2015, and 2014, Cleco Power made $110.0 million, $135.0 million, and $115.0 million of distribution payments to Cleco Holdings, respectively. During 2016, Cleco Power received equity contributions from Cleco Holdings of $50.0 million cash. Cleco Power received no equity contributions from Cleco Holdings in 2015 and received a $138.1 million non-cash equity contribution relating to the transfer of Coughlin in 2014.

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 2016 and 2015:

	FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)	2016		2015
Support Group	$	1,771	$	2,055

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Note 17—Intangible Assets 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 have a life of 12 years, but may have a life of up to 15 years depending on the time period required to collect the required amount from Cleco Power’s customers. The intangible asset’s expected amortization expense is based on the estimated collections from Cleco Power’s customers. At the end of its life, the asset will have no residual value. At the date of the 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 on the date of the Merger. During the years ended December 31, 2016, 2015, and 2014, Cleco Katrina/Rita recognized amortization expense of $16.5 million, $15.7 million, and $15.4 million, respectively, based on actual collections.

As a result of the 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. For the successor period April 13, 2016, through December 31, 2016, Cleco recognized amortization expense of $0.2 million on the trade name intangible asset. The intangible assets related to the power supply agreements are being amortized over the remaining life of each applicable contract ranging between 2 years and 19 years. For the successor period April 13, 2016, through December 31, 2016, Cleco recognized a reduction of revenue of $7.5 million on the intangible assets for the power supply agreements.

The following tables summarize the balances for intangible assets subject to amortization for Cleco and Cleco Power as of December 31, 2016, and 2015:

Cleco

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Cleco Katrina/Rita right to bill and collect storm recovery charges	$	70,594		$	177,537
Power supply agreements		86,726			—
Trade name		5,100			—
Gross carrying amount		162,420			177,537
Accumulated amortization		(19,786	)		(102,574	)
Net intangible assets subject to amortization	$	142,634		$	74,963

Cleco Power

(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Cleco Katrina/Rita right to bill and collect storm recovery charges	$	177,537		$	177,537
Accumulated amortization		(119,064	)		(102,574	)
Net intangible assets subject to amortization	$	58,473		$	74,963

The following tables summarize the amortization expense related to intangible assets expected to be recognized in Cleco and Cleco Power’s Statements of Income:

Cleco

EXPECTED AMORTIZATION EXPENSE	(THOUSAND)
For the year ending Dec. 31,
2017	$	28,704
2018	$	29,564
2019	$	31,087
2020	$	9,935
2021	$	9,935
Thereafter	$	33,409

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Cleco Power

EXPECTED AMORTIZATION EXPENSE	(THOUSANDS)
For the year ending Dec. 31,
2017	$	18,009
2018	$	19,312
2019	$	21,152

On April 13, 2016, in connection with the completion of the Merger, Cleco recognized goodwill of $1.49 billion. Management has assigned goodwill to

Cleco’s reportable segment, Cleco Power. For more information about Cleco’s policy on goodwill, see Note 2—“Summary of Significant Accounting Policies—Goodwill.”

For more information about the Merger related adjustments, see Note 3—“Business Combinations.”

Note 18—Coughlin Transfer

In October 2012, Cleco Power announced that Evangeline was the winning bidder in Cleco Power’s 2012 long-term RFP for up to 800 MW to meet long-term capacity and energy needs. In December 2012, Cleco Power and Evangeline executed definitive agreements to transfer ownership and control of

Coughlin from Evangeline to Cleco Power. In March 2014, Coughlin was transferred to Cleco Power with a net book value of $176.0 million. Cleco Power finalized the rate treatment of Coughlin as part of its FRP extension proceeding before the LPSC in June 2014.

Note 19—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 (LOSS) GAIN			NET (LOSS) GAIN ON CASH FLOW HEDGES			TOTAL AOCI
PREDECESSOR
Balances, Dec. 31, 2013	$	(19,725	)	$	(6,151	)	$	(25,876	)
Other comprehensive loss before reclassifications
Postretirement benefit adjustments incurred during the year		(9,022	)		—			(9,022	)
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss		2,021			—			2,021
Reclassification of net loss to interest charges		—			212			212
Net current-period other comprehensive (loss) income		(7,001	)		212			(6,789	)
Balances, Dec. 31, 2014	$	(26,726	)	$	(5,939	)	$	(32,665	)
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year		2,790			—			2,790
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss		3,079			—			3,079
Reclassification of net loss to interest charges		—			211			211
Net current-period other comprehensive income		5,869			211			6,080
Balances, Dec. 31, 2015	$	(20,857	)	$	(5,728	)	$	(26,585	)
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss		587			—			587
Reclassification of net loss to interest charges		—			60			60
Net current-period other comprehensive income		587			60			647

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(THOUSANDS)	POSTRETIREMENT BENEFIT NET (LOSS) GAIN			NET (LOSS) GAIN ON CASH FLOW HEDGES			TOTAL AOCI
Balances, Apr. 12, 2016	$	(20,270	)	$	(5,668	)	$	(25,938	)
SUCCESSOR(1)
Balances, Apr. 13, 2016	$	—		$	—		$	—
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year		2,304			—			2,304
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net gain		(804	)		—			(804	)
Net current-period other comprehensive income		1,500			—			1,500
Balances, Dec. 31, 2016	$	1,500		$	—		$	1,500

(1) As a result of the Merger, AOCI was reduced to zero on April 13, 2016, as required by acquisition accounting.

Cleco Power

(THOUSANDS)	POSTRETIREMENT BENEFIT NET (LOSS) GAIN			NET (LOSS) GAIN ON CASH FLOW HEDGES			TOTAL AOCI
Balances, Dec. 31, 2013	$	(9,026	)	$	(6,151	)	$	(15,177	)
Other comprehensive loss before reclassifications
Postretirement benefit adjustments incurred during the year		(3,344	)		—			(3,344	)
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss		1,021			—			1,021
Reclassification of net loss to interest charges		—			212			212
Net current-period other comprehensive (loss) income		(2,323	)		212			(2,111	)
Balances, Dec. 31, 2014	$	(11,349	)	$	(5,939	)	$	(17,288	)
Other comprehensive loss before reclassifications
Postretirement benefit adjustments incurred during the year		(1,232	)		—			(1,232	)
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss		1,217			—			1,217
Reclassification of net loss to interest charges		—			211			211
Net current-period other comprehensive (loss) income		(15	)		211			196
Balances, Dec. 31, 2015	$	(11,364	)	$	(5,728	)	$	(17,092	)
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year		3,913			—			3,913
Amounts reclassified from accumulated other comprehensive loss
Amortization of postretirement benefit net loss		(454	)		—			(454	)
Reclassification of net loss to interest charges		—			211			211
Net current-period other comprehensive income		3,459			211			3,670
Balances, Dec. 31, 2016	$	(7,905	)	$	(5,517	)	$	(13,422	)

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Note 20 —Miscellaneous Financial Information (Unaudited)

Cleco

Quarterly information for Cleco for 2016 and 2015 is shown in the following tables:

	2016
	PREDECESSOR					SUCCESSOR
	1ST QUARTER		2ND QUARTER			2ND QUARTER			3RD QUARTER		4TH QUARTER
(THOUSANDS)			APR. 1-APR. 12			APR. 13-JUNE 30
Operating revenue, net	$	266,968	$	32,903		$	243,502		$	342,860	$	266,642
Operating income (loss)	$	50,192	$	(29,832	)	$	(110,148	)	$	93,143	$	53,299
Net income (loss)	$	19,368	$	(23,328	)	$	(81,914	)	$	39,621	$	18,180
Contribution from member	$	—	$	—		$	100,720		$	—	$	—
Distributions to member	$	—	$	—		$	28,000		$	28,000	$	32,765

	2015
	PREDECESSOR
(THOUSANDS)	1ST QUARTER		2ND QUARTER		3RD QUARTER		4TH QUARTER
Operating revenue, net	$	295,457	$	289,074	$	345,468	$	279,403
Operating income	$	62,722	$	69,884	$	102,572	$	52,162
Net income	$	26,922	$	30,234	$	54,663	$	21,850

Cleco Power

Quarterly information for Cleco Power for 2016 and 2015 is shown in the following tables:

	2016
(THOUSANDS)	1ST QUARTER		2ND QUARTER			3RD QUARTER		4TH QUARTER
Operating revenue, net	$	266,682	$	278,343		$	345,131	$	269,017
Operating income (loss)	$	52,265	$	(81,841	)	$	99,420	$	59,156
Net income (loss)	$	20,879	$	(61,229	)	$	52,572	$	26,906
Contribution from parent	$	—	$	50,000		$	—	$	—
Distributions to parent	$	25,000	$	10,000		$	50,000	$	25,000

	2015
(THOUSANDS)	1ST QUARTER		2ND QUARTER		3RD QUARTER		4TH QUARTER
Operating revenue, net	$	295,271	$	288,885	$	345,189	$	279,122
Operating income	$	65,670	$	70,243	$	103,966	$	54,321
Net income	$	28,605	$	31,813	$	58,661	$	22,270
Distributions to parent	$	25,000	$	35,000	$	40,000	$	35,000

F-82

CLECO HOLDINGS (Parent Company Only) SCHEDULE I

Condensed Statements of Income

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016- DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Operating expenses
Administrative and general	$	375		$	319		$	1,891		$	1,534
Merger transaction costs		23,211			34,912			4,591			17,848
Other operating expense		(382	)		624			490			178
Total operating expenses		23,204			35,855			6,972			19,560
Operating loss		(23,204	)		(35,855	)		(6,972	)		(19,560	)
Equity income from subsidiaries, net of tax		9,357			21,789			141,636			162,331
Interest, net		(35,151	)		(286	)		(1,731	)		(303	)
Other income		1,948			702			17			2,457
Other expense		—			—			(1,142	)		(158	)
(Loss) income before income taxes		(47,050	)		(13,650	)		131,808			144,767
Federal and state income tax benefit		(22,937	)		(9,690	)		(1,861	)		(9,972	)
Net (loss) income	$	(24,113	)	$	(3,960	)	$	133,669		$	154,739

The accompanying notes are an integral part of the Condensed Financial Statements.

F-83

CLECO HOLDINGS (Parent Company Only) SCHEDULE I

Condensed Statements of Comprehensive Income

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016- DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Net (loss) income	$	(24,113	)	$	(3,960	)	$	133,669	$	154,739
Other comprehensive income (loss), net of tax
Postretirement benefits gain (loss) (net of tax expense of $938, $367, and $3,670 and tax benefit of $4,378, respectively)		1,500			587			5,869		(7,001	)
Net gain on cash flow hedges (net of tax expense of $0, $37, $132, and $132, respectively)		—			60			211		212
Total other comprehensive income (loss), net of tax		1,500			647			6,080		(6,789	)
Comprehensive (loss) income, net of tax	$	(22,613	)	$	(3,313	)	$	139,749	$	147,950

The accompanying notes are an integral part of the Condensed Financial Statements.

F-84

CLECO HOLDINGS (Parent Company Only) SCHEDULE I

Condensed Balance Sheets

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	AT DEC. 31, 2016			AT DEC. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	1,377		$	2,236
Accounts receivable - affiliate		7,070			7,669
Other accounts receivable		395			—
Taxes receivable, net		—			14,746
Cash surrender value of trust-owned life insurance policies		57,207			53,821
Total current assets		66,049			78,472
Equity investment in subsidiaries		3,223,920			1,516,310
Tax credit fund investment, net		11,888			13,741
Accumulated deferred federal and state income taxes, net		140,577			123,690
Other deferred charges		1,351			—
Total assets	$	3,443,785		$	1,732,213
Liabilities and member’s equity/shareholders’ equity
Liabilities
Current liabilities
Accounts payable	$	3,424		$	908
Accounts payable—affiliate		14,521			5,389
Taxes payable, net		13,998			—
Other current liabilities		19,566			10,975
Total current liabilities		51,509			17,272
Postretirement benefit obligations		4,280			5,848
Other deferred credits		1,100			587
Long-term debt		1,340,133			33,665
Total liabilities		1,397,022			57,372
Commitments and contingencies (Note 5)
Member’s equity/Shareholders’ equity
Member’s equity/Common shareholders’ equity
Membership interest/Common stock(1)		2,069,376			456,412
(Accumulated deficit)/Retained earnings		(24,113	)		1,245,014
Accumulated other comprehensive income (loss)		1,500			(26,585	)
Total member’s equity/common shareholders’ equity		2,046,763			1,674,841
Total liabilities and member’s equity/shareholders’ equity	$	3,443,785		$	1,732,213

(1) At December 31, 2015, shareholders’ equity included $418.5 million of premium on common stock, $61.1 million of common stock, and $23.2 million of treasury stock. At December 31, 2015, Cleco Holdings had 100,000,000 shares of common stock authorized, 61,058,918 shares of common stock issued, and 60,482,468 shares of common stock outstanding, par value $1 per share. At December 31, 2015, Cleco Holdings had 576,450 shares of treasury stock.

The accompanying notes are an integral part of the Condensed Financial Statements.

F-85

CLECO HOLDINGS (Parent Company Only) SCHEDULE I

Condensed Statements of Cash Flows

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Operating activities
Net cash provided by operating activities	$	36,811		$	34,904		$	128,909		$	108,754
Investing activities
Contributions to tax credit fund		—			—			(9,966	)		(55,315	)
Return of equity investment in tax credit fund		901			476			2,128			2,579
Contribution to subsidiary		(50,000	)		—			—			—
Premiums paid on trust-owned life insurance		—			—			(3,607	)		(2,831	)
Net cash (used in) provided by investing activities		(49,099	)		476			(11,445	)		(55,567	)
Financing activities
Draws on credit facility		—			3,000			57,000			97,000
Payments on credit facility		—			(10,000	)		(80,000	)		(45,000	)
Issuance of long-term debt		1,350,000			—			—			—
Repayment of long-term debt		(1,350,000	)		—			—			—
Payment of financing costs		(3,755	)		—			—			—
Repurchase of common stock		—			—			—			(12,449	)
Dividends paid on common stock		(572	)		(24,579	)		(97,283	)		(95,044	)
Contribution from member		100,720			—			—			—
Distributions to member		(88,765	)		—			—			—
Other financing		—			—			(14	)		—
Net cash provided by (used in) financing activities		7,628			(31,579	)		(120,297	)		(55,493	)
Net (decrease) increase in cash and cash equivalents		(4,660	)		3,801			(2,833	)		(2,306	)
Cash and cash equivalents at beginning of period		6,037			2,236			5,069			7,375
Cash and cash equivalents at end of period	$	1,377		$	6,037		$	2,236		$	5,069
Supplementary cash flow information
Interest paid, net of amount capitalized	$	26,264		$	126		$	130		$	189
Income taxes paid, net	$	4,263		$	1		$	1,464		$	15,013
Supplementary non-cash investing and financing activity
Non-cash contribution to subsidiary, net of tax	$	—		$	—		$	—		$	142,880
Non-cash distribution from subsidiary, net of tax	$	—		$	—		$	33,661		$	138,080

The accompanying notes are an integral part of the Condensed Financial Statements.

F-86

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, 2016, Cleco Holdings’ restricted net assets of consolidated subsidiaries were $1.09 billion and exceeded 25% of its total consolidated net assets. Cleco Holdings’ only major, first-tier subsidiary is Cleco Power. Cleco Power contains the LPSC-jurisdictional generation, transmission, and distribution electric utility operations serving Cleco’s traditional retail and wholesale customers.

Prior to March 2014, when Evangeline owned and operated Coughlin, Midstream was also considered a first-tier subsidiary of Cleco Corporation. Subsequent to the transfer of Coughlin from Evangeline to Cleco Power in March 2014, Midstream was no longer considered a first-tier subsidiary.

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—Business Combinations

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 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. At the effective time of the Merger, each outstanding share of Cleco Corporation common stock, par value $1.00 per share (other than shares that were owned

by Cleco Corporation, Cleco Partners, Merger Sub, or any other direct or indirect wholly owned subsidiary of Cleco Partners or Cleco Corporation), were cancelled and converted into the right to receive $55.37 per share in cash, without interest, with all dividends payable before the effective time of the Merger.

For more information regarding the Merger see Part II, Item 8, “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 3—Business Combinations.”

Note 3—Debt

At December 31, 2016, and 2015, Cleco Holdings had no short-term debt outstanding.

At December 31, 2016, Cleco Holding’s long-term debt outstanding was $1.34 billion, of which none was due within one year.

In connection with the completion of the Merger, on April 13, 2016, Cleco Holdings entered into a $1.35 billion Acquisition Loan Facility. The Acquisition Loan Facility had a three-year term and a rate of LIBOR plus 1.75% or ABR plus 0.75%. In May and June 2016, Cleco Holdings refinanced the Acquisition Loan Facility with a series of other long-term financings described below.

On May 17, 2016, Cleco Holdings completed the private sale of $535.0 million of 3.743% senior notes due May 1, 2026, and $350.0 million of 4.973% senior notes due May 1, 2046. On May 24, 2016, Cleco Holdings completed the private sale of $165.0 million of 3.250% senior notes due May 1, 2023. On June 28, 2016, Cleco Holdings entered into a $300.0 million variable rate bank term loan due June 28, 2021. Amounts outstanding under the bank term loan bear interest, at Cleco’s option, at a base rate plus 0.625% or LIBOR plus 1.625%. At December 31, 2016, the all-in rate was 2.265%, which was based on the LIBOR rate. The proceeds from the issuance and sale of these notes and term loan were used to repay the $1.35 billion Acquisition Loan Facility. Debt issuance costs of $17.7 million were expensed to

F-87

merger costs in connection with the repayment of the Acquisition Loan Facility.

The principal amounts payable under long-term debt agreements for each year through 2021 and thereafter are as follows:

(THOUSANDS)
Amounts payable under long-term debt arrangements
For the year ending Dec. 31,
2017	$	—
2018	$	—
2019	$	—
2020	$	—
2021	$	300,000
Thereafter	$	1,050,000

At December 31, 2015, Cleco Holdings had a $250.0 million credit facility. On April 13, 2016, in connection with the completion of the Merger, Cleco Holdings replaced the existing credit facility with a $100.0 million credit facility. The new credit facility has similar terms as the previous facility, including restricted financial covenants, and expires in 2021. At December 31, 2016, Cleco Holdings had no borrowings outstanding under its $100.0 million credit facility. 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 December 31, 2016, Cleco Holdings was in compliance with the covenants in its credit facility.

Note 4—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 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 2016, 2015, and 2014:

	SUCCESSOR		PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016		JAN. 1, 2016 - APR. 12, 2016		FOR THE YEAR ENDED DEC. 31, 2015		FOR THE YEAR ENDED DEC. 31, 2014
Cleco Power	$	85,000	$	25,000	$	135,000	$	115,000
Perryville		150		200		500		975
Attala		100		125		350		750
Total	$	85,250	$	25,325	$	135,850	$	116,725

During the predecessor period January 1, 2014, through December 31, 2014, Cleco Holdings made a $138.1 million non-cash contribution to Cleco Power related to the transfer of Coughlin from Evangeline to Cleco Power. During the predecessor periods January 1, 2015, through December 31, 2015, and January 1, 2016, through April 12, 2016, Cleco Holdings made no contributions to affiliates. During the successor period April 13, 2016, through December 31, 2016, Cleco Holdings made a contribution of $50.0 million to Cleco Power. During the successor period April 13, 2016, through December 31, 2016, Cleco Holdings received $100.7 million of equity contributions from Cleco Group and made $88.8 million of distribution payments to Cleco Group.

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Note 5—Income Taxes

Cleco Holdings’ (Parent Company Only) Condensed Statements of Income reflect income tax expense (benefit) for the following line items:

	SUCCESSOR			PREDECESSOR
(THOUSANDS)	APR. 13, 2016 - DEC. 31, 2016			JAN. 1, 2016 - APR. 12, 2016			FOR THE YEAR ENDED DEC. 31, 2015			FOR THE YEAR ENDED DEC. 31, 2014
Federal and state income tax benefit	$	(22,937	)	$	(9,690	)	$	(1,861	)	$	(9,972	)
Equity income from subsidiaries—Federal and state income tax expense	$	115		$	13,158		$	79,565		$	77,088

Note 6—Commitments and Contingencies

For information regarding commitments and contingencies related to Cleco Holdings, see Part II, Item 8, “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 15—

Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees.”

F-89

CLECO SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD		ADDITIONS CHARGED TO COSTS AND EXPENSES		UNCOLLECTIBLE ACCOUNT WRITE OFFS LESS RECOVERIES		BALANCE AT END OF PERIOD(1)
Allowance for Uncollectible Accounts
SUCCESSOR
Period Apr. 13, 2016 to Dec. 31, 2016	$	3,336	$	4,348	$	485	$	7,199
PREDECESSOR
Period Jan. 1, 2016 to Apr. 12, 2016	$	2,674	$	1,163	$	501	$	3,336
Year Ended Dec. 31, 2015	$	922	$	2,986	$	1,234	$	2,674
Year Ended Dec. 31, 2014	$	849	$	1,980	$	1,907	$	922

(1) Deducted in the consolidated balance sheet

(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD		ADDITIONS		DEDUCTIONS		BALANCE AT END OF PERIOD(1)
Unrestricted Storm Reserve
SUCCESSOR
Period Apr. 13, 2016 to Dec. 31, 2016	$	2,536	$	71	$	—	$	2,607
PREDECESSOR
Period Jan. 1, 2016 to Apr. 12, 2016	$	2,801	$	—	$	265	$	2,536
Year Ended Dec. 31, 2015	$	3,322	$	—	$	521	$	2,801
Year Ended Dec. 31, 2014	$	1,236	$	4,133	$	2,047	$	3,322
Restricted Storm Reserve
SUCCESSOR
Period Apr. 13, 2016 to Dec. 31, 2016	$	16,515	$	870	$	—	$	17,385
PREDECESSOR
Period Jan. 1, 2016 to Apr. 12, 2016	$	16,177	$	338	$	—	$	16,515
Year Ended Dec. 31, 2015	$	14,916	$	1,261	$	—	$	16,177
Year Ended Dec. 31, 2014	$	17,646	$	1,414	$	4,144	$	14,916

(1) Included in the consolidated balance sheet

F-90

CLECO POWER SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

(THOUSANDS)	BALANCE AT BEGINNING OF PERIOD		ADDITIONS CHARGED TO COSTS AND EXPENSES		UNCOLLECTIBLE ACCOUNT WRITE-OFFS LESS RECOVERIES		BALANCE AT END OF PERIOD(1)
Allowance for Uncollectible Accounts
Year Ended Dec. 31, 2016	$	2,674	$	5,511	$	986	$	7,199
Year Ended Dec. 31, 2015	$	922	$	2,986	$	1,234	$	2,674
Year Ended Dec. 31, 2014	$	849	$	1,980	$	1,907	$	922

(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, 2016	$	2,801	$	71	$	265	$	2,607
Year Ended Dec. 31, 2015	$	3,322	$	—	$	521	$	2,801
Year Ended Dec. 31, 2014	$	1,236	$	4,133	$	2,047	$	3,322
Restricted Storm Reserve
Year Ended Dec. 31, 2016	$	16,177	$	1,208	$	—	$	17,385
Year Ended Dec. 31, 2015	$	14,916	$	1,261	$	—	$	16,177
Year Ended Dec. 31, 2014	$	17,646	$	1,414	$	4,144	$	14,916

(1) Included in the consolidated balance sheet

F-91

Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of officers and directors.

Under Section 1315 of the Louisiana Limited Liability Company Law (the “LLCL”), a limited liability company may, through its articles of organization or operating agreement, eliminate or limit the personal liability of its members, if management is reserved to the members, or managers, if management is reserved to the managers, for monetary damages for the breach of a member’s or a manager’s fiduciary duty. However, Section 1315 does not allow for the elimination or limitation of liability for the amount of a financial benefit received by a member or manager to which the individual is not entitled or for an intentional violation of a criminal law.

Section 1315 of the LLCL further permits a limited liability company to indemnify its members or managers for judgments, settlements, penalties, fines, or expenses incurred because an individual is or was a member or manager.

The operating agreement of the Company provides for the indemnification, to the fullest extent of the law, of the member, each of the managers, and each officer from any liability, loss, or damage by reason of any act performed or omitted to be performed by any such person in connection with the business of the Company, except (i) with respect to any such person other than an officer or the independent manager, in the case that such action or inaction by constituted fraud or a willful material breach of such person’s obligations under the operating agreement, and (ii) with respect to an officer or the independent manager, only in the case that such person reasonably determined at the time of action or inaction that his or her course of conduct was in, or not opposed to, the best interests of the Company and, with respect to any criminal action or proceeding, had no reasonable cause to believe such person’s conduct was unlawful.

The operating agreements of the Company further provides for the indemnification of any employee or agent to the same extent by the adoption of a resolution by the Company’s Board of Managers, in its discretion.

Item 21. Exhibits and financial statement schedules.

(a) See Exhibit Index immediately following the signature pages.

Item 22. Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes to supply by means of apost-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-1

The undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, apost-effective amendment to this registration statement:

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or most recentpost-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each suchpost-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initialbona fide offering thereof; and

(3) To remove from registration by means of apost-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness.Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

II-2

SIGNATURES

Pursuant to the requirements of the Securities Act, the Registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Pineville, State of Louisiana.

	CLECO CORPORATE HOLDINGS LLC
By:	/s/ Peggy Scott
	(Peggy Scott)
	(Chairperson and Interim Chief Executive Officer)

Date: March 17, 2017

Pursuant to the requirements of the Securities Act, this registration statement has been signed below by the following persons in the capacities and on the dates indicated.

SIGNATURE	TITLE	DATE
/s/ Peggy Scott (Peggy Scott)	Chairperson and Interim Chief Executive Officer (Principal Executive Officer)	March 17, 2017
/s/ Terry L. Taylor (Terry L. Taylor)	Chief Financial Officer (Principal Financial Officer)	March 17, 2017
/s/ Tonita Laprarie (Tonita Laprarie)	Controller and Chief Accounting Officer (Principal Accounting Officer)	March 17, 2017
	MANAGERS* David Agnew Andrew Chapman Richard Dinneny Mark Fay Richard Gallot, Jr. Christopher Leslie David R. Gilchrist Recep Kendircioglu Steven Turner Bruce Wainer Lincoln Webb

*BY:	/s/ Terry L. Taylor	March 17, 2017
	(Terry L. Taylor, as Attorney-in-Fact)

II-3

EXHIBIT INDEX

		SEC FILE OR REGISTRATION NUMBER	REGISTRATION STATEMENT OR REPORT	EXHIBIT NUMBER
2(a)	Agreement and Plan of Merger, dated as of October 17, 2014, by and among the Company, Como 1 L.P. and Como 3 Inc.	1-15759	8-K(10/20/14)	2.1
3(a)	Articles of Entity Conversion of Cleco Corporate Holdings LLC, dated as of April 13, 2016	1-15759	8-K(4/19/16)	3.1
3(b)	Limited Liability Company Agreement of Cleco Corporate Holdings LLC, dated as of April 13, 2016	1-15759	8-K(4/19/16)	3.2
4(a)(1)	Indenture of Mortgage dated as of July 1, 1950, between Cleco Power (as successor) and First National Bank of New Orleans, as Trustee	1-05663	10-K(1997)	4(a)(1)
4(a)(2)	Eighteenth Supplemental Indenture dated as of December 1, 1982, to Exhibit 4(a)(1)	1-05663	10-K(1993)	4(a)(8)
4(a)(3)	Nineteenth Supplemental Indenture dated as of January 1, 1983, to Exhibit 4(a)(1)	1-05663	10-K(1993)	4(a)(9)
4(a)(4)	Twenty-Sixth Supplemental Indenture dated as of March 15, 1990, to Exhibit 4(a)(1)	1-05663	8-K(3/15/90)	4(a)(27)
4(b)(1)	Indenture between Cleco Power (as successor) and Bankers Trust Company, as Trustee, dated as of October 1, 1988	33-24896	S-3(10/11/88)	4(b)
4(b)(2)	Agreement Appointing Successor Trustee dated as of April 1, 1996, by and among Central Louisiana Electric Company, Inc., Bankers Trust Company, and The Bank of New York	333-02895	S-3(4/29/96)	4(a)(2)
4(b)(3)	First Supplemental Indenture, dated as of December 1, 2000, between Cleco Utility Group Inc. and the Bank of New York	333-52540	S-3/A(1/26/01)	4(a)(2)
4(b)(4)	Second Supplemental Indenture, dated as of January 1, 2001, between Cleco Power LLC and The Bank of New York	333-52540	S-3/A(1/26/01)	4(a)(3)
4(b)(5)	Seventh Supplemental Indenture, dated as of July 6, 2005, between Cleco Power LLC and the Bank of New York Trust Company, N.A.	1-05663	8-K(7/6/05)	4.1
4(b)(6)	Eighth Supplemental Indenture, dated as of November 30, 2005, between Cleco Power LLC and the Bank of New York Trust Company, N.A.	1-05663	8-K(11/28/05)	4.1
4(b)(7)	Ninth Supplemental Indenture, dated as of June 3, 2008, between Cleco Power LLC and The Bank of New York Trust Company, N.A.	1-05663	8-K(6/2/08)	4.1

II-4

4(b)(8)	Tenth Supplemental Indenture, dated as of November 13, 2009, between Cleco Power LLC and The Bank of New York Mellon Trust Company, N.A. (as successor trustee)	1-05663	8-K(11/12/09)	4.1
4(b)(9)	Eleventh Supplemental Indenture, dated as of November 15, 2010, between Cleco Power LLC and The Bank of New York Mellon Trust Company, N.A. (as successor trustee)	1-05663	8-K(11/15/10)	4.1
4(c)(1)	Indenture of Mortgage dated May 17, 2016 between Cleco Corporate Holdings LLC and Wells Fargo Bank, N.A.	1-15759	8-K(5/17/16)	4.1
4(c)(2)	First Supplemental Indenture dated May 17, 2016 between Cleco Corporate Holdings LLC and Wells Fargo Bank, N.A	1-15759	8-K(5/17/16)	4.2
4(c)(3)	Second Supplemental Indenture dated May 17, 2016 between Cleco Corporate Holdings LLC and Wells Fargo Bank, N.A	1-15759	8-K(5/17/16)	4.3
4(c)(4)	Third Supplemental Indenture dated May 24, 2016 between Cleco Corporate Holdings LLC and Wells Fargo Bank, N.A	1-15759	8-K(5/24/16)	4.2
4(d)	Registration Rights Agreement dated May 17, 2016 between Cleco Corporate Holdings LLC and Mizuho Securities USA Inc., Scotia Capital (USA) Inc., SMBC Nikko Securities America, Inc. and Other Initial Purchasers	1-15759	8-K(5/17/16)	4.4
4(e)	Agreement Under Regulation S-K Item 601(b)(4)(iii)(A)	1-05663	10-Q(9/99)	4(c)
*5(a)	Opinion of Locke Lord LLP.
*5(b)	Opinion of Baker, Donelson, Bearman, Caldwell & Berkowitz, PC.
10(a)(1)	Supplemental Executive Retirement Plan Amended and Restated January 1, 2009	1-15759	10-K(2008)	10(f)(4)
10(a)(2)	Supplemental Executive Retirement Plan (Amended and Restated January 1, 2009), Amendment No. 1	1-15759	8-K(12/9/08)	10.3
10(a)(3)	Cleco Corporation Supplemental Executive Retirement Plan Amendment, effective October 28, 2011	1-15759	10-Q(9/11)	10.2
10(a)(4)	Cleco Corporation Supplemental Executive Retirement Plan Amended and Restated effective January 1, 2009, Amendment No. 3	1-15759	10-K(2014)	10(c)(10)
10(a)(5)	Supplemental Executive Retirement Trust dated December 13, 2000	1-15759	10-K(2003)	10(e)(1)(c)

II-5

10(a)(6)	Supplemental Executive Retirement Plan Participation Agreement between Cleco Corporation and Dilek Samil	1-15759	10-K(2002)	10(z)(1)
10(a)(7)	Supplemental Executive Retirement Plan Participation Agreement between Cleco Corporation and Michael H. Madison	1-15759	10-K(2004)	10(v)(3)
10(b)(1)	Cleco Corporation Executive Severance Plan, effective October 28, 2011	1-15759	10-Q(9/11)	10.1
10(b)(2)	Cleco Corporation Executive Severance Plan (As amended and restated) Amendment No. 1	1-15759	8-K(10/24/14)	10.1
10(b)(3)	Cleco Corporation Executive Severance Plan (As amended and restated) Amendment No. 2	1-15759	8-K(12/23/14)	10.1
10(b)(4)	Cleco Corporation Executive Severance Plan (As amended and restated) Amendment No. 3	1-15759	10-Q(6/15)	10.1
10(b)(5)	Executive Employment Agreement, dated April 21, 2011, by and between Cleco Corporation and Bruce A. Williamson	1-15759	8-K(4/27/11)	10.1
10(b)(6)	Cleco Corporation Executive Severance Plan Adjustment to Severance Benefits Agreement between Cleco Corporation and Thomas R. Miller dated March 29, 2016	1-15759	8-K(4/1/16)	10.1
10(b)(7)	Cleco Corporation Executive Severance Plan Adjustment to Severance Benefits Agreement between Cleco Corporation and Wade A. Hoefling dated March 29, 2016	1-15759	8-K(4/1/16)	10.2
10(b)(8)	Cleco Corporation Executive Severance Plan Adjustment to Severance Benefits Agreement between Cleco Corporation and Judy P. Miller dated March 29, 2016	1-15759	8-K(4/1/16)	10.4
10(b)(9)	Letter Agreement, dated March 29, 2016, between Bruce A. Williamson and Cleco Corporation	1-15759	8-K(4/1/16)	10.3
10(c)	401(k) Savings and Investment Plan Trust Agreement dated as of August 1, 1997, between UMB Bank, N.A. and Cleco	1-05663	10-K(1997)	10(m)
10(d)(1)	Cleco Corporation Pay for Performance Plan	1-15759	10-K(2011)	10(g)(4)
10(d)(2)	Cleco Corporation Pay for Performance Plan, As Amended and Restated December 3, 2012	1-15759	10-K(2012)	10(f)(5)
10(e)(1)	Cleco Corporation Deferred Compensation Plan	333-59696	S-8(4/27/01)	4.3
10(e)(2)	First Amendment to Cleco Corporation Deferred Compensation Plan	1-15759	10-K(2008)	10(n)(5)
10(e)(3)	Cleco Corporation Deferred Compensation Plan, Corrective Section 409A Amendment	1-15759	8-K(12/9/08)	10.2

II-6

10(e)(4)	Deferred Compensation Trust dated January 2001	1-15759	10-K(2003)	10(u)
10(e)(5)	Cleco Corporation Deferred Compensation Plan Amendment, effective October 28, 2011	1-15759	10-Q(9/11)	10.5
10(e)(6)	Form of Cleco Corporate Holdings LLC Retention Bonus Plan for calendar years 2016 and 2017	1-15759	8-K(7/5/16)	10.1
10(f)(1)	Note Purchase Agreement dated May 8, 2012 by and among Cleco Power LLC and the Purchasers listed on the signature pages thereto	1-05663	8-K(05/09/12)	10.1
10(f)(2)	Term Loan Agreement dated March 20, 2013, by and among Cleco Power LLC, as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent	1-15759	8-K(3/26/13)	10.1
10(f)(3)	Amended and Restated Credit Agreement dated as of October 16, 2013, among Cleco Corporation, various financial institutions, and JPMorgan Chase Bank, N.A., as administrative agent	1-15759	8-K(10/17/13)	10.1
10(f)(4)	Note Purchase Agreement dated November 13, 2015 by and among Cleco Power LLC and the Purchasers listed on the signature pages thereto	1-15759	8-K(11/13/15)	10.1
10(f)(5)	Note Purchase Agreement dated December 20, 2016 by and among Cleco Power LLC and the Purchasers listed on the signature pages thereto	1-05663	8-K(12/21/16)	10.1
10(f)(6)	Credit Agreement, dated as of April 13, 2016, by and among Cleco Corporation Holdings LLC, Mizuho Bank, Ltd., as administrative agent, and the lenders from time to time party thereto	1-15759	8-K(4/19/16)	10.1
10(f)(7)	Term Loan Credit Agreement, dated as of June 28, 2016, by and among Cleco Corporate Holdings LLC, Mizuho Bank, Ltd., as administrative agent, and the lenders from time to time party thereto	1-15759	8-K(7/1/16)	10.1
10(g)	Acadia Power Partners, LLC – Third Amended and Restated Limited Liability Company Agreement dated February 23, 2010	1-15759	10-K(2010)	10(j)
10(h)	Form of the Cleco Corporation 2014 Recovery Agreement Pay for Performance Plan, effective December 22, 2014	1-15759	8-K(12/23/14)	10.2
10(i)(1)	Form of Board of Managers Services Agreement, dated as of April 13, 2016	1-15759	8-K(4/19/16)	10.3
10(i)(2)	Form of Consulting Agreement, by and between Cleco Corporation and each of Thomas R. Miller, Wade A. Hoefling, and Judy P. Miller, dated as of April 13, 2016	1-15759	10-Q(3/16)	10.9

II-7

10(j)	Cleco Corporate Holdings LLC Separation Agreement by and between Cleco Power LLC, including its parent, Cleco Corporate Holdings LLC, and each of their respective subsidiaries and affiliates and Keith D. Crump	1-15759	10-K(2016)	10(j)
10(k)	Interim Executive Employment Agreement, effective February 8, 2017, by and between Peggy Scott and Cleco Group LLC	1-15759	10-K(2016)	10(k)
*12	Computation of Ratios of Earnings to Fixed Charges
*21	Subsidiaries of the Registrant
*23(a)	Consent of Locke Lord LLP.	Included in Exhibit 5(a).
*23(b)	Consent of Baker, Donelson, Bearman, Caldwell & Berkowitz, PC.	Included in Exhibit 5(b).
*23(c)	Consent of PricewaterhouseCoopers LLP with respect to the financial statements and the financial statement schedules as of December 31, 2016 and for the period April 13, 2016 to December 31, 2016 for Cleco Corporate Holdings.
*23(d)	Consent of PricewaterhouseCoopers LLP with respect to the financial statements and the financial statement schedules for the period January 1, 2016 to April 12, 2016 for Cleco Corporation.
*23(e)	Consent of PricewaterhouseCoopers LLP with respect to the financial statements and the financial statement schedule as of December 31, 2016 and for the year ended December 31, 2016 for Cleco Power.
*23(f)	Consent of Deloitte & Touche LLP with respect to the financial statements and the financial statement schedules as of December 31, 2015 and 2014 and for each of the two years ended in the period December 31, 2015 and 2014 for Cleco Corporate Holdings.
*23(g)	Consent of Deloitte & Touche LLP with respect to the financial statements and the financial statement schedules as of December 31, 2015 and 2014 and for each of the two years ended in the period December 31, 2015 and 2014 for Cleco Power.
*24	Power of Attorney from each Manager of Cleco Corporate Holdings LLC whose signature is affixed to this Registration Statement onForm S-4

II-8

*25(a)	Statement of Eligibility of Wells Fargo Bank, N.A. with respect to the Indenture relating to the 2026 Notes on Form T-1.
*25(b)	Statement of Eligibility of Wells Fargo Bank, N.A. with respect to the Indenture relating to the 2046 Notes on Form T-1.
*99.1	Form of Letter of Transmittal.
*99.2	Form of Notice of Guaranteed Delivery.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase
*101.DEF	XBRL Taxonomy Extension Definition Linkbase
*101.LAB	XBRL Taxonomy Extension Label Linkbase
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase

* Filed herewith.

II-9