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

May 27, 2020

Registration Statement No. 333-

UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549

Form

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
491172-1445282

(State or other jurisdictionOther Jurisdiction of
incorporationIncorporation or organization)
Organization)

4911
(Primary Standard Industrial


Classification Code)

72-1445282
(I.R.S. Employer
Identification No.)

2030 Donahue Ferry Road


Pineville, Louisiana 71360-5226


(318) 484-7400


(Address, Including ZIPZip Code, and Telephone Number,


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

Julia E. Callis

Chief Compliance Officer and

Jeremy Kliebert
Associate General Counsel


2030 Donahue Ferry Road


Pineville, Louisiana 71360-5226


(318) 484-7400


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


Including Area Code, of Agent for Service)

with a copy to:

Michelle A. Earley, Esq.

David F.
Timothy S. Taylor Esq.

600 Congress Avenue

Suite 2200

Austin, TX 78701-3055

(512) 305-4700


Jamie L. Yarbrough
Baker Botts L.L.P.
910 Louisiana Street
Houston, Texas 77002-4995
(713) 229-1234

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 statement 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, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer
 ☐
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
 ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐
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

 

 

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)
3.375% Senior Notes due 2029
$300,000,000
100%
$300,000,000
$38,940.00
(1)
This registration fee has been calculated pursuant to Rule 457(f)(2) under the Securities Act of 1933, as amended.

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

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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

May 27, 2020

Prospectus

LOGO


Cleco Corporate Holdings LLC

Offer to Exchange


up to $535,000,000 3.743%$300,000,000 3.375% Senior Secured Notes due 2026

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

2029
which have been registered under the Securities Act and


for
up to $350,000,000 4.973%$300,000,000 3.375% Senior Secured Notes due 2046

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

2029
which have not been registered under the Securities Act


The Exchange Offer

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,p.m., New York City time, on     , 2017,2020, unless we extend the exchange offer. We currently do not intend to extend the expiration date.date of the exchange offer.

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

We will not receive any proceeds from the exchange offer.

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

The Exchange Notes

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.tradable and will not contain provisions relating to additional interest relating to our registration obligations.

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

Broker-Dealers

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer must acknowledge by way of the letter of transmittal that it will deliver a prospectus in connection with any resale of suchthe Exchange Notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, asuch 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,until    , 2020, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

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

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

YOU SHOULD READ THIS ENTIRE DOCUMENT AND THE ACCOMPANYING LETTER OF TRANSMITTAL AND RELATED DOCUMENTS AND ANY AMENDMENTS OR SUPPLEMENTS CAREFULLY BEFORE MAKING YOUR DECISION TO PARTICIPATE IN THE EXCHANGE OFFER.
The date of this prospectus is    , 2017

2020


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.

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iv

NON-GAAP FINANCIAL MEASURES

v

v

35

CAPITALIZATION

36

37

71

86

87

88

91

92

131

132

133

DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS

142

144

177

179

185

186

186

WHERE YOU CAN FIND MORE INFORMATION

186

188

F-1
This prospectus is part of a registration statement we filed with the SEC. In making your decision whether to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the letter of transmittal accompanying this prospectus. We have not authorized any person to provide you with additional or different information. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. If you receive any unauthorized information, you must not rely on it. This prospectus may only be used where it is legal to exchange the Outstanding Notes for the Exchange Notes, and this prospectus is not an offer to exchange or a solicitation to exchange the Outstanding Notes for the Exchange Notes where such an offer, solicitation or exchange would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.
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i


CERTAIN DEFINITIONS

In this prospectus, except as the context otherwise requires or as otherwise noted, “Cleco,” the “Company,” the “Issuer”,“Issuer,” “we,” “us” and “our” refer to Cleco Corporate Holdings LLC and its subsidiaries, except with respect to the Outstanding Notes and the Exchange Notes, in which case such terms refer only to Cleco Corporate Holdings LLC; the term “Outstanding Notes” refers to theCleco’s outstanding 3.743%3.375% Senior Secured Notes due 2026 and the outstanding 4.973% Senior Secured Notes due 2046;2029; the term “Exchange Notes” refers to the 3.743%Cleco’s 3.375% Senior Secured Notes due 20262029 registered under the Securities Act and the 4.973% Senior Secured Notes due 2046 registered under the Securities Act;offered hereby; and the term “Notes” refers to both the Outstanding Notes and the Exchange Notes. Certain other defined terms shall have the meanings set forth below:

DEFINED TERM
DEFINITION

ABBREVIATION OR ACRONYM

2016 Merger

DEFINITION

401(k) Savings PlanCleco Power 401(k) Savings and Investment Plan
ABRAlternate Base Rate which is the greater of the prime rate, the federal funds effective rate plus 0.50%, or LIBOR plus 1.0%
AcadiaAcadia Power Partners, LLC, previously a wholly owned subsidiary of Midstream. Acadia Power Partners, LLC was dissolved effective August 29, 2014.
Acadia Unit 1Cleco Power’s 580-MW, combined cycle power plant located at the Acadia Power Station in Eunice, Louisiana
Acadia Unit 2Entergy Louisiana’s 580-MW, combined cycle power plant located at the Acadia Power Station in Eunice, Louisiana, which is operated by Cleco Power
AFUDCAllowance for Funds Used During Construction
ALJAdministrative Law Judge
Amended Lignite Mining AgreementAmended and restated lignite mining agreement effective December 29, 2009
AMIAdvanced Metering Infrastructure
AOCIAccumulated Other Comprehensive Income (Loss)
AROAsset Retirement Obligation
ARRAAmerican Recovery and Reinvestment Act of 2009
AttalaAttala Transmission LLC, a wholly owned subsidiary of Cleco Holdings
bcIMCBritish Columbia Investment Management Corporation
Brame Energy CenterA facility consisting of Nesbitt Unit 1, Rodemacher Unit 2, and Madison Unit 3
CAAClean Air Act
CCRCoal combustion by-products or residual
CEOChief Executive Officer
ClecoCleco Holdings and its subsidiaries
Cleco GroupCleco Group LLC, a wholly owned subsidiary of Cleco Partners
Cleco HoldingsCleco Corporate Holdings LLC
Cleco Katrina/RitaCleco Katrina/Rita Hurricane Recovery Funding LLC, a wholly owned subsidiary of Cleco Power
Cleco PartnersCleco 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 PowerCleco Power LLC and its subsidiaries, a wholly owned subsidiary of Cleco Holdings
CO2Carbon dioxide
CoughlinCleco Power’s 775-MW, combined-cycle power plant located in St. Landry, Louisiana
CPPClean Power Plan
CSAPRCross-State Air Pollution Rule
DHLCDolet Hills Lignite Company, LLC, a wholly owned subsidiary of SWEPCO

ii


ABBREVIATION OR ACRONYM

DEFINITION

Diversified LandsDiversified Lands LLC, a wholly owned subsidiary of Cleco Holdings
Dodd-Frank ActDodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOEU.S. Department of Energy
Dolet HillsA 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.
EACEnvironmental Adjustment Clause
EBITDAEarnings (losses) before Interest, Taxes, Depreciation, and Amortization
EGUElectric Generating Unit
Entergy Gulf StatesEntergy Gulf States Louisiana, L.L.C.
Entergy LouisianaEntergy Louisiana, LLC
EPAU.S. Environmental Protection Agency
EROElectric Reliability Organization
ESPPEmployee Stock Purchase Plan
EvangelineCleco Evangeline LLC, a wholly owned subsidiary of Midstream
FACFuel Adjustment Clause
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FTRFinancial Transmission Right
FRPFormula Rate Plan
GAAPGenerally Accepted Accounting Principles in the U.S.
GO ZoneGulf Opportunity Zone Act of 2005 (Public Law 109-135)
IRPIntegrated Resource Plan
IRSInternal Revenue Service
ISOIndependent System Operator
kWhKilowatt-hour(s)
LDEQLouisiana Department of Environmental Quality
LEDLouisiana Economic Development
LIBORLondon Interbank Offered Rate
LMPLocational Marginal Price
LPSCLouisiana Public Service Commission
LTIPLong-Term Incentive Compensation Plan
Madison Unit 3A 641-MW generating unit at Cleco Power’s plant site in Boyce, Louisiana
MATSMercury 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 AgreementAgreement and Plan of Merger, dated as of October 17, 2014, by and among Cleco Partners, Merger Sub, and Cleco Corporation
2016 Merger Commitments
Cleco Partners’, Cleco Group’s, Cleco Holdings’, and Cleco Power’s 77 commitments to the LPSC as defined in Docket No. U-33434 of which a performance report must be filed annually by October 31 for the 12 months ending June 30
401(k) Plan
Cleco Power 401(k) Savings and Investment Plan
ABR
Alternate Base Rate which is the greater of the prime rate, the federal funds effective rate plus 0.50%, or LIBOR plus 1.0%
Acadia
Acadia Power Partners, LLC, previously a wholly owned subsidiary of Midstream. Acadia Power Partners, LLC was dissolved effective August 29, 2014
Acadia Unit 1
Cleco Power’s 580-MW, combined cycle power plant located at the Acadia Power Station in Eunice, Louisiana
Acadia Unit 2
Entergy Louisiana’s 580-MW, combined cycle power plant located at the Acadia Power Station in Eunice, Louisiana, which is operated by Cleco Power
ADIT
Accumulated Deferred Income Tax
AFUDC
Allowance for Funds Used During Construction
Amended Lignite
Mining Agreement
Amended and restated lignite mining agreement effective December 29, 2009
Acquisition Term Loan Facility
A term loan facility in an aggregate principal amount of $100 million entered into in connection with the closing of the Cleco Cajun Transaction
AMI
Advanced Metering Infrastructure
AOCI
Accumulated Other Comprehensive Income (Loss)
ARO
Asset Retirement Obligation
Attala
Attala Transmission LLC, a wholly owned subsidiary of Cleco Holdings
BCI
British Columbia Investment Management Corporation
Brame Energy Center
A facility consisting of Nesbitt Unit 1, Rodemacher Unit 2, and Madison Unit 3
Bridge Facility
A bridge term loan facility in an aggregate principal amount of $300 million entered into in connection with the closing of the Cleco Cajun Transaction
CAA
Clean Air Act
CCR
Coal combustion by-products or residual
CECL
Current Expected Credit Losses
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DEFINED TERM
DEFINITION
CEO
Chief Executive Officer
CFO
Chief Financial Officer
CIP
Critical Infrastructure Protection
Cleco
Cleco Holdings and its subsidiaries
Cleco Cajun
Cleco Cajun LLC (formerly Cleco Energy LLC, a wholly owned subsidiary of Cleco Holdings) and its subsidiaries
Cleco Cajun Transaction
The transaction between Cleco Cajun and NRG Energy in which Cleco Cajun acquired all the membership interest in South Central Generating, which closed on February 4, 2019, pursuant to the Purchase and Sale Agreement, which includes the Cottonwood Sale Leaseback
Cleco Corporation
Pre-2016 Merger entity that was converted to a limited liability company and changed its name to Cleco Corporate Holdings LLC on April 13, 2016
Cleco Group
Cleco Group LLC, a wholly owned subsidiary of Cleco Partners
Cleco Holdings
Cleco Corporate Holdings LLC, a wholly owned subsidiary of Cleco Group
Cleco Katrina/Rita
Cleco Katrina/Rita Hurricane Recovery Funding LLC, a wholly owned subsidiary of Cleco Power
Cleco Partners
Cleco Partners L.P., a Delaware limited partnership that is owned by a consortium of investors, including funds or investment vehicles managed by MIRA, BCI, John Hancock Financial, and other infrastructure investors
Cleco Power
Cleco Power LLC and its subsidiaries, a wholly owned subsidiary of Cleco Holdings
Como 1
Como 1, L.P., currently known as Cleco Partners
CO2
Carbon dioxide
Consent Decree
The Consent Decree, entered March 5, 2013, in Civil Action No. 09-100-JJB-DLD, United States District Court for the Middle District of Louisiana, by and among the EPA, the LDEQ, and Louisiana Generating relating to Big Cajun II, Unit 1 located in New Roads, Louisiana
Cottonwood Energy
Cottonwood Energy Company LP, a wholly owned subsidiary of Cleco Cajun. Prior to the closing of the Cleco Cajun Transaction on February 4, 2019, Cottonwood Energy was an indirect subsidiary of South Central Generating
Cottonwood Plant
Cleco Cajun’s 1,263-MW, natural-gas-fired generating station located in Deweyville, Texas
Cottonwood Sale Leaseback
A lease agreement executed and delivered between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy pursuant to which NRG Energy will lease back the Cottonwood Plant and will operate it until no later than May 2025
Coughlin
Cleco Power’s 775-MW, combined-cycle power plant located in St. Landry, Louisiana
COVID-19
Novel coronavirus disease 2019 and the related global outbreak that was subsequently declared a pandemic by the World Health Organization in March 2020
CPP
Clean Power Plan
CSAPR
Cross-State Air Pollution Rule
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DEFINED TERM
DEFINITION
DHLC
Dolet Hills Lignite Company, LLC, a wholly owned subsidiary of SWEPCO
Diversified Lands
Diversified Lands LLC, a wholly owned subsidiary of Cleco Holdings
Dolet Hills
A facility consisting of Dolet Hills Power Station, the Dolet Hills mine, and the Oxbow mine
Dolet Hills Power Station
A 650-MW generating unit at Cleco Power’s plant site in Mansfield, Louisiana. Cleco Power has a 50% ownership interest in the capacity of Dolet Hills
EAC
Environmental Adjustment Clause
EAF
Equivalent Availability Factor
EBITDA
Earnings before interest, taxes, depreciation, and amortization
EGU
Electric Generating Unit
EFORd
Equivalent Forced Outage Rate on demand
EMT
Executive Management Team
Entergy Gulf States
Entergy Gulf States Louisiana, LLC
Entergy Louisiana
Entergy Louisiana, LLC
EPA
United States Environmental Protection Agency
ERO
Electric Reliability Organization
Evangeline
Cleco Evangeline LLC, a wholly owned subsidiary of Midstream
FAC
Fuel Adjustment Clause
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings, a credit rating agency
FTR
Financial Transmission Right
FRP
Formula Rate Plan
GAAP
Generally Accepted Accounting Principles in the United States
GO Zone
Gulf Opportunity Zone Act of 2005 (Public Law 109-135)
IRC
Internal Revenue Code of 1986, as amended
IRP
Integrated Resource Plan
IRS
Internal Revenue Service
ISO
Independent System Operator
kV
Kilovolt
kWh
Kilowatt-hour(s)
LCFC
Lost Contribution to Fixed Cost
LDEQ
Louisiana Department of Environmental Quality
LIBOR
London Interbank Offered Rate
LMP
Locational Marginal Price
Louisiana Generating
Louisiana Generating, LLC, a wholly owned subsidiary of South Central Generating
LPSC
Louisiana Public Service Commission
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DEFINED TERM
DEFINITION
LTIP
Long-Term Incentive Compensation Plan
LTSA
Long-Term Parts and Service Agreement between Cottonwood Energy and a third party, dated January 19, 2001, that Cleco Cajun assumed as a result of the Cleco Cajun Transaction to provide maintenance services related to the Cottonwood Plant
Madison Unit 3
A 641-MW generating unit at Cleco Power’s plant site in Boyce, Louisiana
MATS
Mercury and Air Toxics Standards
Merger Agreement
Agreement and Plan of Merger, dated as of October 17, 2014, by and among Cleco Partners, Merger Sub, and Cleco Corporation relating to the 2016 Merger
Merger Sub
Cleco MergerSub Inc., previously an indirect wholly owned subsidiary of Cleco Partners that was merged with and into Cleco Corporation, with Cleco Corporation surviving the 2016 Merger, and Cleco Corporation converting to a limited liability company and changing its name to Cleco Holdings
Midstream
Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco Holdings
MIP
MIRA
Macquarie Infrastructure Partners Inc.
MIRA
Macquarie Infrastructure and Real Assets Inc.
MISO
Midcontinent Independent System Operator, Inc.
MMBtu
Million
One million British thermal units
Moody’s
Moody’s Investors Service, a credit rating agency
MSCI EAFE Index
MW
Morgan Stanley Capital International Europe, Australia, Far East Index

iii


Megawatt(s)

ABBREVIATION OR ACRONYM

MWh

DEFINITION

Megawatt-hour(s)
MW
N/A
Megawatt(s)
Not Applicable
MWh
NAAQS
Megawatt-hour(s)
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NMTC
New Markets Tax Credit
NMTC FundUSB NMTC Fund 2008-1 LLC was formed to invest in projects qualifying for New Markets Tax Credits and Solar Projects
NOAANational 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 oxidesoxide
NYSE
NRG Energy
New York Stock Exchange
NRG Energy, Inc.
Oxbow
NRG South Central
NRG South Central Generating LLC
Other Benefits
Includes medical, dental, vision, and life insurance for Cleco’s retirees
Oxbow
Oxbow Lignite Company, LLC, 50% owned by Cleco Power and 50% owned by SWEPCO
PCB
Polychlorinated biphenyl
Perryville
Perryville Energy Partners, L.L.C., a wholly owned subsidiary of Cleco Holdings
PPA
ppb
Power Purchase Agreement
PPACAPatient Protection and Affordable Care Act, as amended
ppb
Parts per billion
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DEFINED TERM
DEFINITION
Predecessor
Pre-merger activity of Cleco. Cleco has accounted for the merger2016 Merger transaction by applying the acquisition method of accounting. The predecessor period is not comparable to the successor period.period
RFP
Purchase and Sale Agreement
Request for Proposal
Purchase and Sale Agreement, dated as of February 6, 2018, by and among NRG Energy, South Central Generating, and Cleco Cajun
Registrants
Cleco Holdings and/or Cleco Power
Rodemacher Unit 2
A 523-MW generating unit at Cleco Power’s plant site in Boyce, Louisiana. Cleco Power has a 30% ownership interest in the capacity of Rodemacher Unit 2.2
ROE
Return on Equity
RTO
ROIC
Return on Invested Capital
ROU
Right of Use
RTO
Regional Transmission Organization
S&P
Standard & Poor’s Ratings Services, a credit rating agency
SEC
SAIDI
U.S. Securities and Exchange Commission
System Average Interruption Duration Index
SERP
Supplemental Executive Retirement Plan
SO2
Sulfur dioxide
SPP
South Central Generating
Southwest Power Pool
South Central Generating LLC, formerly NRG South Central Generating LLC
SPP RE
SSR
Southwest Power Pool Regional Entity
System Support Resource
Successor
START
Strategic Alignment and Real-Time Transformation
STIP
Short-Term Incentive Plan
Successor
Post-merger activity of Cleco. Cleco has accounted for the merger2016 Merger transaction by applying the acquisition method of accounting. The successor period is not comparable to the predecessor period.period
Support Group
Cleco Support Group LLC, a wholly owned subsidiary of Cleco Holdings
SWEPCO
Southwestern Electric Power Company, an electric utility subsidiary of American Electric Power Company, Inc.
TCJA
Federal tax legislation commonly referred to as the Tax Cuts and Jobs Act of 2017
Teche Unit 3
A 359-MW generating unit at Cleco Power’s plant site in Baldwin, Louisiana

vi

PRESENTATION

TABLE OF FINANCIALCONTENTS

WHERE YOU CAN FIND MORE INFORMATION

The Issuer

We have filed with the Commission a registration statement on Form S-4 under the Securities Act with respect to the Exchange Notes offered hereby. For further information with respect to us and the Exchange Notes offered hereby, we refer you to the registration statement, including the exhibits and schedules filed therewith.
We have not authorized anyone to provide you with information other than that provided in this prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should not assume that the information in this prospectus is accurate as of any date other than the date of this prospectus.
This prospectus contains summaries of certain agreements that we have entered into in connection with the issuance and sale of the Outstanding Notes isand the exchange offer, such as the indenture that will govern the Exchange Notes. The descriptions contained in this prospectus of these agreements do not purport to be complete and are subject to, or qualified in their entirety by reference to, the definitive agreements. Copies of the definitive agreements will be made available without charge to you in response to a written request to us. Any such request should be directed to us at Cleco Corporate Holdings LLC, P.O. Box 5000, Pineville, Louisiana 71361-5000, Telephone: (318) 484-7400, Attention: Corporate Secretary.
We file reports and other information with the Commission. The Commission also maintains a Louisiana limited liability company.website on the Internet that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission, and such website is located at http://www.sec.gov. You may request a copy of these filings at no cost, by writing or calling us at the following address: Cleco Corporate Holdings LLC, successorP.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 Cleco Corporation, was converted fromrequest any documents, you should do so no later than   , 2020 in order to receive them before the expiration of the exchange offer.
Pursuant to the indenture under which the Exchange Notes will be issued (and the Outstanding Notes were issued), we have agreed that, whether or not we are required to do so by the rules and regulations of the Commission, for so long as any of the Notes remain outstanding, we (not including our subsidiaries) will furnish to the holders of the Notes copies of all quarterly and annual financial information that would be required to be contained in a Louisiana corporation to a Louisiana limited liability company in connectionfiling with the Transactions (as defined herein). The consolidated financial information priorCommission on Forms 10-Q and 10-K if we were required to April 13, 2016 (the effective datefile such forms and all current reports that would be required to be filed with the Commission on Form 8-K if we were required to file such reports, in each case within the time periods specified in the Commission’s rules and regulations. In addition, following the consummation of the conversion) included in this prospectus is historical financialexchange offer, whether or not required by the rules and regulations of the Commission, we will file a copy of all such information of Cleco Corporation and its consolidated subsidiaries.

iv


NON-GAAP FINANCIAL MEASURES

We refer toreports with the term Adjusted EBITDA in various places in this prospectus. We define Adjusted EBITDA asCommission for public availability within 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 acceptedtime periods specified 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 financialCommission’s rules and operating performance. We believe that Adjusted EBITDA,regulations (unless the Commission will not accept such 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 expensesfiling) 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 cashinformation available to us to invest in our business. We compensate for these limitations by relying primarily on our GAAP resultsecurities analysts 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.prospective investors upon request.

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FORWARD-LOOKING STATEMENTS

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

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

the result of the exchange offer;
the COVID-19 pandemic and its effect on Cleco, Cleco’s operations, business, and financial condition, and the communities it serves, United States and world financial markets and supply chains, potential regulatory actions, changes in customer and stakeholder behaviors, and impacts on and modifications to Cleco’s operations, business, and financial condition relating thereto;
the effects of the Cleco Cajun Transaction and the 2016 Merger on April 13, 2016, on theCleco’s business relationships, operating results, and business generallygenerally;
the ability to successfully remediate underlying causes of Cleco and Cleco Power;identified material weaknesses in internal control over financial reporting;

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

theCleco Power’s ability to recover fuel costs through the fuel adjustment clause;FAC;

the ability to successfully integrate the assets acquired in the Cleco Cajun Transaction into Cleco’s operations;
factors affecting utility operations, such as unusual weather conditions or other natural phenomena; catastrophic weather-related damage caused by hurricanes and other storms or severe drought conditions; pandemic illnesses, specifically COVID-19; unexpected delays in capital projects; unscheduled generation outages; unanticipated maintenance or repairs; unanticipated changes to fuel costs or fuel supply costs, shortages, solid fuel shortages,and natural gas 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’sCleco’s commitments and obligations to markets for generation resources and reliance on third-party fuel transportation and transmission services;

global and domestic economic conditions, including the negative impact of COVID-19, the ability of customers to continue paying their utility bills, related growth and/or down-sizing of businesses in ourCleco’s service area, monetary fluctuations, changes in commodity prices and inflation rates;
political uncertainty in the United States, including uncertainty relating to the United States. federal government budget and debt ceiling, and volatility and disruption in global capital and credit markets;
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the ability of the lignite reserves at Dolet Hills to provide sufficient fuel to the Dolet Hills Power Station until at least 2036;to meet projected dispatch needs;

Cleco Power’sthe timing and costs associated with the potential early closure of Dolet Hills, including the ability to recover those costs;
Cleco’s ability to maintain its right to sell wholesale power at market-based rates within its control area;

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

reliability of Cleco Power’sCleco’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,CCRs, greenhouse gases, and energy efficiency that could limit or terminate the operation of certainCleco’s generating units, increase costs, or reduce customer demand for electricity;

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

financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board,FASB, the SEC, Federal Energy Regulatory Commission,FERC, the LPSC, or similar entities with regulatory or accounting oversight;

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

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changes in commodity prices and transportation costs;
legal, environmental, and regulatory delays and other obstacles associated with acquisitions, reorganizations, investments in joint ventures, or other capital projects;

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

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

changes in federal, state, or local laws (including the TCJA and other tax laws), changes in tax rates, disallowances of tax positions, or changes in other regulatingregulatory 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 IssuerCleco Holdings in certain instances, as agreed to as parta result of the regulatory2016 Merger Commitments;
Cleco’s ability to remain in compliance with the commitments made to the LPSC in connection with the Merger;Cleco Cajun Transaction;

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

acts of terrorism, cyber-attacks,cyber attacks, data security breaches or other attempts to disrupt ourCleco’s 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;ability to successfully modify or transition Cleco’s legacy enterprise business applications into new systems;

our credit ratings and those of Cleco Holdings and Cleco Power;

Cleco Holdings’ and Cleco Power’s ability to remain in compliance with their respective debt covenants;
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the availability or cost of capital resulting from changes in global markets, ourCleco’s business or financial condition, interest rates, or market perceptions of the electric utility industry and energy-related industries;

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

other factors we discuss in this prospectus.

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

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SUMMARY

This summary highlights certain information about our business and about this offeringthe exchange of Outstanding Notes for Exchange Notes in the Exchange Notes.exchange offer. This is a summary of information contained elsewhere in this prospectus, is not complete and does not contain all of the information that may be important to you. You should read the following summary together with the more detailed information and consolidated financial statements and the notes to those statements included in this prospectus. Unless the context otherwise requires, inYou should read carefully this prospectus, “we,” “us” and “our” refer to Cleco and its consolidated subsidiaries;including 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 registeredmatters set forth under the Securities Act andcaption “Risk Factors,” before making a decision whether to participate in 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.

exchange offer.

Overview

Cleco is a regional energypublic utility holding company that conducts substantially all of its business operations through its primary subsidiary, holds investments in several subsidiaries, including:
Cleco Power, LLC (“which is a wholly owned subsidiary of Cleco Power”), whichthat engages primarily in the generation, transmission, distribution and sales of electricity. Cleco Power is a regulated electric utility company that, as of March 31, 2020, owns nine10 generating units with a total nameplate capacity of 3,3103,360 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi.

Mississippi; and

Cleco Cajun (f/k/a Cleco Energy LLC), which is a wholly owned unregulated subsidiary of Cleco that owns eight generating assets with a rated capacity of 3,555 MW, and supplies wholesale power and capacity to nine Louisiana cooperatives, three municipalities across Arkansas, Louisiana and Texas and one investor-owned utility. Seven of the generating assets are managed by Cleco, while the Cottonwood plant in Texas is temporarily leased to NRG Energy. Cleco acquired these assets from NRG Energy in February 2019. See “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations” for more information.
Since a substantial portion of our operations are primarily conducted through Cleco Power, oura primary source of funds for the repayment of our indebtedness, including the Exchange Notes, is distributions and dividends from Cleco Power, which is subject to numerous restrictions on its ability to make such distributions and dividends, including from state corporate law, Cleco Power’s indentures and credit agreements, and state and local regulations. Cleco Power has also made certain regulatory commitments whichthat 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 connectionCleco MergerSub Inc., previously an indirect, wholly owned subsidiary of Cleco Partners, merged with and into Cleco Corporation, with Cleco Corporation surviving the Merger (as defined below),merger. Thereafter, Cleco Corporation converted into a limited liability company organized under the laws of the State of Louisiana and changed its name to Cleco Corporate Holdings LLC.LLC, a direct, wholly owned subsidiary of Cleco is a public utility holding company which holds investments in several subsidiaries, includingGroup and an indirect, wholly owned subsidiary of Cleco Power. Substantially all of our operations are conducted through Cleco Power.Partners. See “Business — General” for more information. Cleco, subject to certain limited exceptions, is exempt from regulation as a public utility holding company pursuant to provisions of the Public Utility Holding Company Act of 2005, as amended.
Cleco’s principal executive office is located at 2030 Donahue Ferry Road, Pineville, Louisiana 71360, and its telephone number is (318) 484-7400. Cleco’s website is located atwww.cleco.com. www.cleco.com. Cleco’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other filings with the SEC are available, free of charge, through Cleco’s website after those reports or filings are filed or furnished to the SEC. Information on Cleco’s website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
Recent Developments
COVID-19
On March 11, 2020, the World Health Organization declared the current COVID-19 outbreak to be a global pandemic, and on March 13, 2020, the United States declared a national emergency. In response to these declarations and the rapid spread of COVID-19, federal, state and local governments have imposed varying
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degrees of restrictions on business and social activities to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory. Cleco has modified some of its business operations, as these restrictions have significantly impacted many sectors of the economy, including record levels of unemployment, with businesses, nonprofit organizations, and governmental entities modifying, curtailing, or ceasing normal operations. Cleco has also modified certain business practices to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. For example, since March 13, 2020, Cleco temporarily closed all customer service offices, temporarily suspended disconnects and late fees, restricted access to its administrative offices, implemented remote work arrangements, prohibited all non-critical travel for Cleco business, prohibited in-person gatherings of more than 10 people at Cleco work locations, and required all meetings to be held virtually or via telephone.
Cleco provides a critical service to its customers which means that it is paramount that it keeps its employees who operate its business safe and informed and has taken and continues to take and update precautions for that purpose. In addition, Cleco assessed and updated its existing business continuity plans for its business units in the context of the COVID-19 pandemic. The Merger

LPSC has issued a moratorium on disconnects of customers for non-payment, and accordingly Cleco has taken steps to assure its customers that disconnections for non-payment as well as late fees are temporarily suspended. Cleco is also working with its suppliers to understand the potential impacts to its supply chain. This is a rapidly evolving situation and could lead to extended disruption of economic activity in Cleco’s service territory. Cleco will continue to monitor developments affecting its workforce, customers, and suppliers and take additional precautions as Cleco believes are warranted.

The first priority in Cleco’s response to this crisis has been the health and safety of its employees and those of its customers and other business counterparties. Cleco has implemented preventative measures and developed corporate response plans to minimize unnecessary risk of exposure and prevent infection, while supporting its customers’ operations to the best of its ability in the circumstances. Cleco has an Emergency (Crisis) Response Team for health, safety, and environmental matters and personnel issues, and has established a Pandemic Plan Team to address various impacts of COVID-19 as they have been developing. This team provides leadership and guidance for planning, risk management, and any policy changes. The team ensures that areas of Cleco plan, manage, and safely execute the pandemic plan set forth by management. Cleco employees are required to report daily to their manager or supervisor any changes to the employee’s health, the employee’s family’s health, and travel plans. This is reported to the Pandemic Plan Team at a minimum of three times per week. The results are then communicated on a weekly update call to all employees. Proper measures are taken for any employee at risk of having COVID-19 and measures are taken to protect any employees with which the at-risk employee had been in contact. Cleco also has modified certain business practices, including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences, to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other federal, state, and local governmental and regulatory authorities. Cleco is continuing to address concerns to protect the health and safety of its employees and those of its customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, Cleco, its suppliers, and other business counterparties to experience operational delays.
In addition, Cleco has implemented certain measures that it believes will provide financial flexibility and maintain liquidity. On October 17, 2014,March 23, 2020, Cleco Holdings made an $88.0 million draw on its credit facility, and Cleco Power made a $150.0 million draw on its credit facility. While Cleco continues to assess the Company (throughCOVID-19 situation, at this time Cleco cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the markets will have on its predecessor,business, cash flows, liquidity, financial condition, and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities,
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including the LPSC and FERC, Cleco’s customers and suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding certain risks associated with the COVID-19 pandemic, see “Risk Factors — COVID-19.”
Credit Facility Amendments
On May 15, 2020, Cleco Corporation)Holdings entered into amendments to its revolving credit facility and its two outstanding term loan facilities (collectively, the “Cleco Holdings Amendments”). Also, on May 15, 2020, Cleco Power entered into an 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. Pursuantamendment 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.



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-yearits revolving credit facility (the “Revolving Credit Facility”)“Cleco Power Amendment” and, a $1,350.0 million acquisition loantogether with the Cleco Holdings Amendments, the “Amendments”). The Amendments extend the terms of each 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 borrowingsthrough June 28, 2022. The current borrowing costs under the Revolving Credit Facilityamended Cleco Holdings revolving credit facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. Cleco Holdings’ amended $300.0 million term loan bears interest at an interest rate of LIBOR plus 1.875% and Acquisition Loan Facility, the offeringCleco Holdings’ amended $30.0 million term loan bears interest at an interest rate of LIBOR plus 1.875%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and saleadditional interest of 0.50% under any of the Outstanding Notes,Cleco Holdings Amendments. The current borrowing costs under the amended Cleco Power revolving credit facility are equal to LIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees of 0.150%. If Cleco Power’s credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of 0.125% under the application of the proceeds therefrom and the other transactions described above as the “Transactions.”

Cleco Power Amendment. The Amendments also include customary LIBOR-transition provisions.
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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:

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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”).



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.



SUMMARY OF THE EXCHANGE OFFER

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

General

In connection with the private offering of the Outstanding Notes, we entered into a registration rights agreement with the initial purchasers of the Outstanding Notes in which we agreed, 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:

$535.0General
In connection with the private offering of the Outstanding Notes, we entered into a registration rights agreement with the initial purchasers of the Outstanding Notes in which we agreed to deliver this prospectus to you and to use our reasonable best efforts to complete an exchange offer for the Outstanding Notes.
Exchange Offer
We are offering to exchange $300.0 million aggregate principal amount of outstanding 3.743% Senior SecuredOutstanding Notes due 2026 which have not been registered under the Securities Act (“2026 Outstanding Notes”) for up to $535.0$300.0 million aggregate principal amount of 3.743% Senior SecuredExchange Notes. The Outstanding Notes due 2026 which have been registered undermay be exchanged only in denominations of $2,000 and integral multiples of $1,000.
Resale of the Exchange Notes
Based on the position of the staff of the Division of Corporation Finance of the Commission in certain interpretive letters issued to third parties in other transactions, we believe that the Exchange Notes acquired in the exchange offer may be freely traded without compliance with the provisions of the Securities Act, (“2026 Exchange Notes”, and together with the 2026 Outstanding Notes, the “2026 Notes”), andif:

$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 ofyou are acquiring the Exchange Notes

Based on in the positionordinary course 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:your business,

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


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

you are not our affiliate as defined in Rule 405 of the Securities Act.
If you fail to satisfy any of these conditions, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the Exchange Notes.
Broker-dealers that acquired Outstanding Notes directly from us, but not as a result of market-making activities or other trading activities, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the Exchange Notes. See “Plan of Distribution.”
Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer in exchange for Outstanding Notes that it acquired as a result of market-making or other trading activities must
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deliver a prospectus in connection with any resale of the Exchange Notes and provide us with a signed acknowledgement of this obligation.

Expiration Date
The exchange offer will expire at 5:00 p.m., New York City time, on , 2020, unless we decide to extend it.
Conditions to the Exchange Offer
The exchange offer is subject to limited, customary conditions, which we may waive.
Procedures for Tendering Outstanding Notes
If you are not our affiliate as defined in Rule 405wish to accept the exchange offer, you must deliver to the exchange agent, before the expiration of the Securities Act.exchange offer:


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



Broker-dealers that acquired Outstanding Notes directly from us, but not as a result of market-making activitiestransmittal 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 acquiredtendered electronically, an agent’s message from The Depository Trust Company (“DTC”), Euroclear Bank S.A./N.V., as a result of market-making or other trading activities must deliver a prospectus in connection with any resaleoperator 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 System (“Euroclear”), Euroclear or Clearstream Banking, société anonyme (“Clearstream”), stating that the tendering participant agrees to be bound by the letter of transmittal and the terms of the exchange offer,

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

all other documents required by the letter of transmittal.
If you hold Outstanding Notes through DTC, Euroclear or Clearstream, you must comply with their standard procedures for electronic tenders, by which you will agree to be bound by the letter of transmittal.
By signing, or by agreeing to be bound by, the letter of transmittal, you will be representing to us that:

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

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

you are not our affiliate as defined under Rule 405 of the Securities Act.
See “The Exchange Offer — Procedures for Tendering.”
Guaranteed Delivery Procedures for Tendering Outstanding Notes
None.
Special Procedures for Beneficial Holders
If you beneficially own Outstanding Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender in the exchange offer, you should contact that
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registered holder promptly and instruct that person to tender on your behalf. If you wish to tender in the exchange offer on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Notes, either arrange to have the Outstanding Notes registered in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.
Acceptance of Outstanding Notes and Delivery of Exchange Notes
We will accept any Outstanding Notes that are properly tendered for exchange before 5:00 p.m., New York City time, on the day the exchange offer expires. The Exchange Notes will be delivered promptly after expiration of the exchange offer.
Exchange Date
We will notify the exchange agent of the date of acceptance of the Outstanding Notes for exchange.
Withdrawal Rights
If you tender your Outstanding Notes for exchange in the exchange offer and later wish to withdraw them, you may do so at any time before 5:00 p.m., New York City time, on the day the exchange offer expires.
Consequences of Failure to Exchange Outstanding Notes
Outstanding Notes that are not tendered in the exchange offer or are not accepted for exchange will continue to bear legends restricting their transfer. You will not be able to sell the Outstanding Notes unless:

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

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

the transaction requires neither an exemption from nor registration under the requirements of the Securities Act.
After the completion of the exchange offer, we will no longer have any obligation to register the Outstanding Notes, except in limited circumstances.
Accrued Interest on the Outstanding Notes
Any interest that has accrued on an Outstanding Note before its exchange in the exchange offer will be payable on the Exchange Note on the first interest payment date after the completion of the exchange offer.
United States Federal Income Tax Consequences
The exchange of the Outstanding Notes for the Exchange Notes generally will not be a taxable event for United States federal income tax purposes. See “Certain United States Federal Income Tax Consequences.”
Exchange Agent
Regions Bank
Use of Proceeds
We will not receive any cash proceeds from the exchange offer. See “Use of Proceeds.”
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Registration Rights Agreement
When we issued the Outstanding Notes on September 11, 2019, we entered into a registration rights agreement with the initial purchasers of the Outstanding Notes. Under the terms of the exchange offer,

yourregistration rights agreement, we agreed to use our reasonable best efforts to file and to cause to become effective a registration statement within 365 days after the closing of the issuance of the Outstanding Notes, eitherwith respect to an offer to exchange the Outstanding Notes for other freely tradable notes issued by tendering them in physical form orus and that are registered with the Commission and that have substantially identical terms as the Outstanding Notes by timely confirmation of book-entry transfer through DTC, Euroclear or Clearstream, and

all other documents required bycertain specified dates. Under 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 distributionterms of the Exchangeregistration rights agreement, we may become obligated to pay additional interest on the Outstanding Notes and

you are not our affiliate as defined under Rule 405depending on the effective date of the Securities Act.registration statement, of which this prospectus forms a part. See “Registration Rights Agreement.”

Accounting Treatment


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 fromWe will not recognize any gain or loss for accounting purposes upon the requirementscompletion of the Securities Act is available to you,exchange offer in accordance with GAAP. See “The Exchange Offer — Accounting Treatment.”
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we register the resale of Outstanding Notes under the Securities Act, or

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

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



Accrued Interest on the Outstanding Notes

Any interest that has accrued on an Outstanding Note before its exchange in 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.”



SUMMARY OF THE TERMS OF THE EXCHANGE NOTES

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

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

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

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

Issuer

Cleco Corporate Holdings LLC (successor to Cleco Corporation)

Notes Offered

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

Issuer
Cleco Corporate Holdings LLC
Notes Offered
$535 million300,000,000 aggregate principal amount of 20263.375% Senior Notes due 2029.
Interest Rate
The Exchange Notes bear interest at 3.375% per annum.
Maturity Date
The Exchange Notes will mature on September 15, 2029.
Interest Payment Dates
Interest is payable on the Exchange Notes semi-annually in arrears on March 15 and September 15 of each year. No interest will be paid on either the Exchange Notes or the Outstanding Notes at the time of exchange. Interest on the Exchange Notes will accrue from March 15, 2020. Assuming the Exchange Notes are issued prior to September 15, 2020, holders of Outstanding Notes that are accepted for exchange in the exchange offer will be deemed to have waived the right, if any, to receive any payment in respect of interest accrued on the Outstanding Notes from March 15, 2020 until the date of the issuance of the Exchange Notes. Holders of the Exchange Notes will receive the same interest payments that they would have received had their Outstanding Notes not been accepted for exchange in the exchange offer.

$350 million aggregateOptional Redemption
At any time and from time to time prior to June 15, 2029, we may, at our option, redeem the Exchange Notes in whole or in part, at a redemption price equal to the greater of (a) 100% of the principal amount of 2046the Exchange Notes then outstanding to be redeemed and (b) the applicable “make-whole” amount based on United States treasury rates as specified in this prospectus under “Description of the Exchange Notes — Optional Redemption,” plus, in each case, accrued and unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date.
At any time and from time to time on or after June 15, 2029, we may redeem the Exchange Notes at our option in whole or in part by paying 100% of the principal amount to be redeemed plus accrued and
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unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date. For additional information, please see “Description of the Exchange Notes — Optional Redemption.”
Ranking
The Exchange Notes will be the Issuer’s senior unsecured obligations and will:

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.



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 the Issuer to the extent of the value of the collateral securing such indebtedness;

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

be structurally subordinated to all existing and future indebtedness and other liabilities (including trade payables) of the Issuer’s subsidiaries, including Cleco Power and Cleco Cajun.
As of March 31, 2020, the Issuer had $1.77 billion of senior unsecured and unsubordinated indebtedness;indebtedness outstanding, including outstanding borrowings of $88.0 million under its revolving credit facility, and no secured indebtedness. As of March 31, 2020, our subsidiaries had $1.53 billion of indebtedness outstanding, including outstanding borrowings of $150.0 million under Cleco Power’s revolving credit facility. At March 31, 2020, Cleco had two separate revolving credit facilities, one for the Issuer in the amount of $175.0 million and one for Cleco Power in the amount of $300.0 million.

be effectively subordinatedChange of Control
Upon the occurrence of a Change of Control Repurchase Event, each holder of the Exchange Notes will have the right, at the holder’s option, to require us to repurchase all existingor any part of the holder’s Exchange Notes at a purchase price in cash equal to 101% of the principal thereof, plus accrued and future secured indebtedness of oursunpaid interest, including additional interest, if any, to the extentdate of such purchase in accordance with the procedures set forth in the indenture. See “Description of the valueExchange 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 collateral securingpayment of the principal of, and accrued interest on, the Exchange Notes, see “Description of the Exchange Notes — Events of Default.”
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Reopening of Exchange Notes
We may from time to time, without the consent of the existing holders of the Outstanding Notes or the Exchange Notes, “reopen” the Exchange Notes which means we can create and issue additional Exchange Notes (any such indebtedness;

Exchange Notes, “Additional Notes”) having the same terms and conditions as the Exchange Notes in all respects (except for the offering price and issue date); provided that such Additional Notes are fungible with the previously issued and outstanding Exchange Notes for United States federal income tax purposes. Additional Notes will be senior in rightconsolidated with, and form a single series with, the previously outstanding Exchange Notes for all purposes under the indenture.
No Guarantees or Credit Support
The obligations to pay the principal of, payment topremium, if any, and interest on the Exchange Notes are solely the obligations of the Issuer, and none of Cleco Partners, the members of the consortium that own Cleco Partners, or any of our future subordinated indebtedness;subsidiaries or other affiliates will guarantee or provide any credit support for the Exchange Notes.
Minimum Denominations
$2,000 and integral multiples of $1,000 in excess thereof.

Book-Entry Delivery and Settlement
The Exchange Notes will be structurally subordinated to all existingissued in fully registered book-entry form and future indebtednesswill be represented by one or more global certificates, which will be deposited with or on behalf of DTC and other liabilities (including trade payables)registered in the name of DTC’s nominee. Beneficial interests in global certificates will be shown on, and transfers thereof will be effected only through, records maintained by DTC and its direct and indirect participants, and your interest in any global certificate may not be exchanged for certificated Exchange Notes, except in limited circumstances described herein. See “Description of the Issuer’s subsidiaries, including Cleco Power.Exchange Notes — Book-Entry Delivery and Settlement.”

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.”

Certain Covenants
The indenture governing the Exchange Notes contains certain covenants that, among other things, restrict our ability to merge, consolidate or transfer or lease all or substantially all of our assets or create or incur liens. These covenants are subject to important exceptions and qualifications as described in this prospectus under the caption “Description of the Exchange Notes — Certain Covenants.”
No Public Market
We do not intend to list the Exchange Notes on any securities exchange or automated dealer quotation system. The Exchange Notes will be new securities for which there currently is no public market.
Trustee
Regions Bank
Governing Law
The Exchange Notes and the indenture will be governed by the laws of the State of New York.
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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.”

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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.

Use of Proceeds
The issuance of the Exchange Notes will not provide us with any new proceeds. We are making the exchange offer solely to satisfy our obligations under the registration rights agreement.
Risk Factors
You should refer to the section entitled “Risk Factors” for a discussion of material risks that you should carefully consider before deciding to invest in the Exchange Notes.
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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.



SUMMARY CONSOLIDATED FINANCIAL INFORMATION

The following table shows summary consolidated financial information at the dates and for the periods indicated. The issuersummary consolidated balance sheets 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.

Thesubsidiaries (the “Successor” or the “Company”) as of December 31, 2019, 2018, 2017 and 2016 and related summary consolidated financial informationstatements of income and cash flows for the five years ended December 31, 2019, 2018 and 2017 and for the period April 13, 2016 isto December 31, 2016 are derived from our audited consolidated financial statements included in this prospectus. ThisThe summary consolidated balance sheet of Cleco Corporation and its subsidiaries (the “Predecessor”) as of December 31, 2015 and related summary consolidated statements of income and cash flows for the period January 1, 2016 to April 12, 2016 and for the year ended December 31, 2015 are derived from the Predecessor’s audited consolidated financial statements not included in this prospectus.

The summary consolidated balance sheets of the Company as of March 31, 2020 and related summary consolidated statements of income and cash flows for the three months ended March 31, 2020 and March 31, 2019 have been derived from our unaudited condensed consolidated financial statements included in this prospectus. The unaudited financial data presented have been prepared on a basis consistent with our audited consolidated financial statements. In the opinion of management, such unaudited financial data reflect all adjustments, consisting only of normal and recurring adjustments necessary for a fair presentation of the results for those periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.
The summary consolidated financial information is only a summary. Youprovided below should be 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.”
 
Successor
Predecessor
 
For the Three Months
Ended March 31,
Fiscal Year Ended
December 31,
Apr. 13 –
Dec. 31,
Jan. 1 –
Apr. 12,
Fiscal Year
Ended
December
31,
 
2020
2019
2019
2018
2017
2016
2016
2015
 
(in thousands)
Income statement data:
 
 
 
 
 
 
 
 
Operating revenue, net
$347,572
$344,186
$1,639,605
$1,231,044
$1,175,646
$853,005
$299,870
$1,209,402
Operating expenses
292,907
293,600
1,324,711
986,487
910,419
808,096
276,060
922,063
Operating income
54,665
50,586
314,894
244,557
265,227
44,909
23,810
287,339
Net income (loss)
6,328
20,557
152,665
94,437
138,080
(24,113)
(3,960)
133,669
Cash flow statement data:
 
 
 
 
 
 
 
 
Net cash provided by operating activities
60,206
108,129
430,119
317,761
265,428
69,890
129,780
361,022
Net cash used in investing activities
(65,413)
(892,661)
(1,115,423)
(288,160)
(203,554)
(135,261)
(41,658)
(167,951)
Net cash (used in) provided by financing activities
226,796
770,599
687,813
(41,717)
20,757
(5,999)
(40,885)
(169,248)
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  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.
 
Successor
Predecessor
 
As of
March 31,
As of December 31,
 
2020
2019
2018
2017
2016
2015
 
(in thousands unless otherwise indicated)
Balance sheet and other data:
 
 
 
 
 
 
Cash and cash equivalents
350,231
116,292
110,175
119,040
23,077
68,246
Total assets
7,676,195
7,476,298
6,436,814
6,278,382
6,343,144
4,323,354
Long-term debt and finance lease, net (1)
3,113,239
3,064,679
2,874,485
2,836,105
2,738,571
1,267,703
Member’s equity
2,649,748
2,643,006
2,124,740
2,096,357
2,046,763
1,674,841
(1)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.



(2)Represents long-term debt plus fair value of long-term debt related to the 2016 Merger adjustments, net of unamortized discount, and debt issuance costs and excludes current portions of long-term debt.amounts due within one year.
(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
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RISK FACTORS
The exchange offer 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 replacedinvestment 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.



RISK FACTORS

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

The risks and uncertainties described below are not the only ones that we face. Additional risks and uncertainties, including those generally affecting the industry in which we operate, risks that are unknown to us or that we currently deem immaterial and risks and uncertainties generally applicable to companies that have recently undertaken transactions similar to the exchange offer, may also impair our business, the value of your investment and our ability to pay interest on, and repay or refinance, the Exchange Notes.
If any of the following risks or uncertainties actually were to occur, our business, financial condition, results of operations or cash flow could be affected materially and adversely. In that case, you could lose all or part of your investment in or fail to achieve the expected return on the Exchange Notes.
RISKS RELATED TO THE EXCHANGE OFFER

Holders who

If you fail to tender and exchange your Outstanding Notes, you will continue to hold Outstanding Notes subject to existing transfer restrictions and the market value of your unexchanged Outstanding Notes may be adversely affected because they may be more difficult to sell.
If you fail to exchange theiryour 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 Outstandingfor Exchange Notes in the exchange offer, you will continue to be subject to the existing transfer restrictions on transfer applicable to theyour Outstanding Notes. The restrictions on transfer of your Outstanding Notes arise because we issuedIn general, the Outstanding Notes under exemptionsmay not be offered or sold unless the offer and sale are registered or exempt from or in transactions not subject to, the registration requirements ofunder the Securities Act and applicable state securities laws. In general, you may onlyExcept in connection with the exchange offer or sellas required by 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. Weregistration rights agreement, we do not planintend to register the offer and sale of any Outstanding Notes under the Securities Act.

Furthermore, we have not conditioned the exchange offer on receiptor any resales of any minimum or maximum principal amount of Outstanding Notes. As Outstanding Notes are tendered and accepted in the exchange offer, the principal amount

Any tenders 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 seewill reduce the discussions below underprincipal amount of the captions “The Exchange Offer—ConsequencesOutstanding Notes. Due to the corresponding reduction in liquidity, this may have an adverse effect upon, and increase the volatility of, Failure to Properly Tenderthe market price of any Outstanding Notes inthat you continue to hold following completion of the Exchange” and “Material United States Federal Income Tax Considerations.”

exchange offer.

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

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

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

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

any other documents required by the letter of transmittal.

Therefore, holders of Outstanding Notes who would like to tender Outstanding Notes in exchange for Exchange Notes should be sure to allow enough time for the necessary documents to be timely received by the exchange agent. We are not required to notify you of defects or irregularities in tenders of Outstanding Notes for exchange. Outstanding notesNotes 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—Offer — Procedures for Tendering” and “The Exchange Offer—Offer — Consequences of Failures to Properly Tender Outstanding Notes in the Exchange.”
The exchange offer may be cancelled or delayed.
Our obligation to accept Outstanding Notes tendered in the exchange offer is subject to certain closing conditions. Please read “The Exchange Offer — Conditions to the Exchange Offer.” We may, at our option and in our sole discretion, assert or waive these conditions. Even if the exchange offer is completed, the exchange
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offer may not be completed on the schedule described in this prospectus. Accordingly, holders participating in the exchange offer may have to wait longer than expected to receive their Exchange Notes, during which time those holders of Outstanding Notes will not be able to effect transfers of their Outstanding Notes tendered for exchange.
Some holders who exchange their Outstanding Notes may be deemed to be underwriters, and these holders will be required to comply with the registration and prospectus delivery requirements in connection with any resale transaction.
If you exchange your Outstanding Notes in the exchange offer for the purpose of participating in a distribution of the Exchange Notes, you may be deemed to have received restricted securities. If you are deemed to have received restricted securities youand, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Any broker-dealer that will receive Exchange Notes for its own account in exchange for Outstanding Notes that were acquired as a result of market-making activities or other trading activities may be a statutory underwriter and must deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such Exchange Notes.

RISKS RELATING TO THE EXCHANGE NOTES

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

The Exchange Notes will be structurally subordinated to indebtedness and other liabilities of Cleco Power, Cleco Cajun and our other subsidiaries. As of DecemberMarch 31, 2016,2020, our subsidiaries had $1.53 billion of indebtedness outstanding, including outstanding borrowings of $150.0 million under the Cleco Power and its subsidiariesrevolving credit facility. At March 31, 2020, Cleco Power had approximately $1,254.8a $300.0 million of debt outstanding.revolving credit facility. Any right that we have pursuant to our equity interest in Cleco Power and Cleco Cajun to receive any assets of Cleco Powersuch subsidiary upon the liquidation or reorganization of Cleco Power,such subsidiary, and the consequent rights of holders of the Exchange Notes to realize proceeds from the sale of Cleco Power’ssuch subsidiary’s assets, will effectively be subordinated to the claims of Cleco Power’ssuch subsidiary’s creditors, including trade creditors. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our subsidiaries, including Cleco Power and Cleco PowerCajun, such subsidiary will pay the holders of its indebtedness and its trade creditors before it will be able to distribute any of its assets to us on account of our equity interest in 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. Becausesuch subsidiary.

Although 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 indesignated as “Senior,” a holder’s right ofto receive 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.

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 andany future secured indebtednessdebt of oursCleco, to the extent of the value of the collateral securing such indebtedness; (c)therefor.

The Exchange Notes will be general senior in right of payment to any of our future subordinated indebtedness;unsecured obligations and (d)therefore will be structurallyeffectively subordinated to all existing andCleco’s future secured indebtedness, and other liabilities (including trade payables)to the extent of the Issuer’s subsidiaries, including Cleco Power.

It may be difficult to realize the value of the Collateral securingcollateral therefor. If Cleco defaults on the Exchange Notes.

TheNotes or certain other indebtedness, or becomes bankrupt, liquidates or reorganizes, any secured creditors could use the value of the collateral agent’s abilitysecuring that debt to foreclosesatisfy their secured indebtedness before a holder of the Exchange Notes would receive any payment on the Collateral on behalfExchange Notes. If the value of such collateral is not sufficient to pay any secured indebtedness in full, Cleco’s secured creditors would share the value of Cleco’s other assets, if any, with holders of the Exchange Notes 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 other claims against us which rank equally with the Exchange Notes would be prohibited from foreclosing upon or disposingNotes.

As of March 31, 2020, Cleco Holdings had $1.77 billion of indebtedness, including outstanding borrowings of $88.0 million under its revolving credit facility, and no secured indebtedness. At March 31, 2020, Cleco Holdings had a debtor’s property without prior bankruptcy court approval.

$175.0 million revolving credit facility.

The indenture permits us to incur additional debt.

The indenture governing the Exchange Notes does not place any limitation on the amount of debt that may be incurred by usCleco or any of our subsidiaries, including Cleco Power or Cleco Power.Cajun. We may therefore incur a significant amount of additional debt, including secured debt secured equallydebt. Cleco Power and ratably by the Collateral, as described under “Description of the Exchange Notes—Security.” Cleco PowerCajun may also incur additional debt, which could affect itstheir 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.

15

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,

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

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:

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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.

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

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

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 repurchaseand the holders of the Exchange Notes or requiresrequire 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 Facilitiesthe senior unsecured credit facilities may not allow us to repurchase the Exchange Notes or otherwise refinance such indebtedness to satisfy our obligations.

Our principal equityholder’s interests may conflict with yours.

Parent

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

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

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

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

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

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

Substantially all

A substantial portion of our existing indebtedness will mature prior to the maturity date of the Exchange Notes. Additionally, upon approval of the Cleco Cajun Transaction, Cleco made a commitment to the LPSC to repay by December 31, 2024 $400.0 million of Cleco Holdings’ debt, of which $63.3 million is required to be repaid
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in 2020. Therefore, we will be required to repay substantially alla substantial portion 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

RISK RELATING TO OUR BUSINESS AND OPERATIONS

Corporate StructureStructural Risks

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

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

HedgingOperational Risks
COVID-19
Cleco faces risks related to COVID-19 and Risk Management Activities

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

The recent outbreak of COVID-19 is a rapidly evolving situation that is adversely affecting current global economic activities and conditions. An extended slowdown of economic growth, decreased demand for commodities and/or material changes in governmental or regulatory policy in the United States could result in lower growth and reduced demand for and usage of electricity in Cleco’s service territory as businesses and facilities continue to close or remain closed. The ability of Cleco’s customers, contractors, and suppliers to meet their obligations to Cleco, Powerincluding payment obligations, could also be negatively affected under the current economic conditions.
The LPSC has issued a moratorium on disconnects of customers for non-payment. Accordingly, Cleco has taken steps to assure customers that disconnections for non-payment and late fees are temporarily suspended, which in turn could negatively impact Cleco’s revenue. Additionally, the LPSC, in response to a federal mandate or otherwise, could impose restrictions on the rates Cleco charges to provide its services, including the inability to implement approved rates, or delay actions with respect to Cleco’s rate cases and filings. In addition, the COVID-19 outbreak may affect Cleco’s ability to timely satisfy regulatory requirements such as recordkeeping and/or timely reporting requirements. As the EPA and many state environmental agencies have issued enforcement discretion policies for such issues, it is subjectunclear whether the effect of any possible noncompliance due to market risk associatedCOVID-19 will be material.
In the event a substantial portion of Cleco’s workforce were to be impacted by COVID-19 for an extended period of time, Cleco may face challenges with fuel cost hedgesrespect to its services or operations and FTRs.it may not be able to execute its capital plan as anticipated. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines,
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Annually,

shelter-in-place orders, and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, Cleco, Power receives Auction Revenue Rights,its suppliers, and other business counterparties to experience operational delays. Cleco has modified certain business and workforce practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access Cleco’s facilities or customer sites could adversely affect its operations. Also, Cleco has a limited number of highly skilled employees for some of its operations. If a large proportion of Cleco’s employees in those critical positions were to contract COVID-19 at the same time, Cleco would rely upon its business continuity plans in an effort to continue operations at its facilities, but there is no certainty that such measures will be sufficient to mitigate the adverse impact to Cleco’s operations that could result from shortages of highly skilled employees.
As many of Cleco’s employees and third-party service providers work remotely in accordance with government mandates, Cleco faces heightened cyber-security risks related to unauthorized system access, aggressive social engineering tactics, and adversaries attacking the information technology systems, network infrastructure, technology and facilities used to conduct its businesses. Cleco will continue to monitor developments affecting its employees, customers, and operations.
While the impact on Cleco’s business from the recent outbreak of COVID-19 is unknown at this time and difficult to predict, various aspects of its business could be adversely affected by COVID-19. While there are many unknowns as to the duration and severity of the COVID-19 outbreak, as of the date of this prospectus, it has caused significant volatility in global markets and has had an adverse impact on the operations of some of Cleco’s customers and suppliers, which can be convertedcould affect Cleco’s operations and its ability to FTRs. FTRs provideaccess capital. The continued spread of COVID-19 and efforts to contain COVID-19, such as the imposition of additional quarantines or closures or reduced operations of businesses and other institutions, could result in an economic slowdown, which could adversely affect customer demand and consumption, cause delayed payments or uncollectible accounts, disrupt supply chains and markets, cause potential delays in the timing of completion of capital projects, or cause other unpredictable events. These impacts could ultimately result in a downgrade of Cleco’s credit ratings. Any of the foregoing events or other unforeseen consequences of COVID-19 could have a material adverse effect on the results of operations, financial hedgecondition, cash flows, or liquidity of Cleco.
Cleco Cajun
The success of the Cleco Cajun Transaction depends, in part, on Cleco’s ability to manage the riskacquired business, realize anticipated benefits, and continue an effective integration process.
On February 4, 2019, Cleco acquired all of congestion costthe membership interests of South Central Generating upon the closing of the Cleco Cajun Transaction. The success of the Cleco Cajun Transaction will depend, in part, on Cleco’s ability to manage and operate an unregulated business through service to nine electric Louisiana cooperative customers and other wholesale customers. Additionally, the integration process may result in the Day-Ahead following challenges, among others:
unanticipated challenges integrating financial and accounting, information technology, communications and other systems;
potential inconsistencies in procedures, practices, policies, controls, and standards;
possible differences in compensation arrangements, management perspectives, and corporate culture; and
meeting LPSC commitments relating to the transaction.
Even with the successful integration of the businesses, Cleco may not achieve the expected results or economic benefits. Any of the factors addressed above could decrease or delay the projected neutral or accretive effect of the Cleco Cajun Transaction. Failure to fully realize the anticipated benefits could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
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Transmission Constraints
Transmission constraints could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Energy Market. FTRs represent rightsprices in the MISO market are based on LMP, which includes a component directly related to congestion credits or charges alongon the transmission system. Pricing zones with greater transmission congestion may have a path during a given timeframe for a certain MW quantity.higher LMP. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power may purchase additional FTRs to further hedge its congestion cost risk.

and Cleco Cajun’s pricing zones. Cleco Power and Cleco Cajun are awarded and/or purchase FTR’s in auctions facilitated by MISO. However, insufficient FTR allocations or increased FTR costs due to negative congestion flows may enter into fuel cost hedge positionsresult in an unexpected increase in energy costs to mitigate the volatility inCleco’s customers. For Cleco Power, if a disallowance of additional fuel costs passed throughassociated with congestion is ordered by the LPSC resulting in a refund to its retail customers. When these positions close, actual gainsCleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or losses are deferredcash flows of Cleco.

Future Electricity Sales
Cleco Power’s future electricity sales and includedcorresponding base revenue and cash flows and Cleco Cajun’s future wholesale revenue and cash flows could be negatively affected by adverse macroeconomic conditions.
Adverse macroeconomic conditions resulting in low economic growth can negatively impact the FACbusinesses of Cleco Power’s residential, commercial, wholesale, and industrial customers, and Cleco Cajun’s wholesale customers resulting in decreased power consumption, which causes a corresponding decrease in base revenue for Cleco Power and revenue for Cleco Cajun. Reduced production or the month the physical contract settles. Recoveryshutdown of any of these FACcustomers’ facilities could substantially reduce Cleco Power’s base revenue and Cleco Cajun’s revenue.
Energy conservation, energy efficiency efforts, and other factors that reduce energy demand could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Regulatory and legislative bodies have proposed or introduced requirements and incentives to reduce energy consumption. Conservation and energy efficiency programs are designed to reduce energy demand. Future electricity sales could be impacted by customers switching to alternative sources of energy, such as solar and wind, on-site power generation, and retail customers purchasing less electricity due to increased conservation efforts or expanded energy efficiency measures. Declining usage could result in an under-recovery of fixed costs at Cleco Power’s rate regulated business. An increase in energy conservation, energy efficiency efforts, and other efforts that reduce energy demand could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Technology and Terrorism Threats
The operational and information technology systems on which Cleco relies to conduct its business and serve customers could fail to function properly due to technological problems, cyber attacks, physical attacks on Cleco’s assets, acts of terrorism, severe weather, solar events, electromagnetic events, natural disasters, the age and condition of information technology assets, human error, or other reasons that could disrupt Cleco’s operations and cause Cleco to incur unanticipated losses and expense.
The operation of Cleco’s extensive electrical systems relies on evolving operational and information technology systems and network infrastructures that are becoming extremely complex as new technologies and systems are implemented to more safely and reliably deliver electric services. Cleco’s business is highly dependent on its ability to process and monitor, on a real-time daily basis, a large number of tasks and transactions, many of which are highly complex. The failure of Cleco’s operational and information technology systems and networks due to a physical or cyber attack, or other event would significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; result in damage to Cleco’s assets or operations, or those of third parties; and subject Cleco to claims by customers or third parties, any of which could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Cleco’s systems, including its financial information, operational, advanced metering, and billing systems, require constant maintenance, monitoring, security patches, modification or configuration of systems, and update and upgrade of systems, which can be costly and increase the risk of errors and malfunction. Any disruptions or deficiencies in existing systems, or disruptions, delays, or deficiencies in the modification, transition to, or
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implementation of new systems, could result in increased costs, the inability to track or collect revenues and the diversion of management’s and employees’ attention and resources, and could adversely affect the effectiveness of Cleco’s control environment, and/or its ability to accurately or timely file required regulatory reports.
Despite implementation of security and mitigation measures, all of Cleco’s technology systems and those of Cleco’s vendors are vulnerable to inoperability, impaired operations, or failures due to cyber or physical attacks on the facilities and equipment needed to operate the technology systems, viruses, human errors, acts of war or terrorism, and other events. If Cleco’s or its vendor’s information technology systems or network infrastructure were to fail, Cleco might be unable to fulfill critical business functions and serve its customers, which could have a material adverse effect on the financial conditions, results of operations, or cash flows of Cleco.
In addition, in the ordinary course of its business, Cleco collects and retains sensitive information including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data could subject Cleco to both penalties for violation of applicable privacy laws and claims from third parties, or harm Cleco’s reputation. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
Cleco’s Generation, Transmission, and Distribution Facilities
Cleco’s generation facilities are susceptible to unplanned outages, significant maintenance requirements, and interruption of fuel deliveries.
The operation of power generation facilities involves many risks, including breakdown or failure of equipment, fuel supply interruption, and performance below expected levels of output or efficiency. Aging equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to operate at peak efficiency, or to comply with environmental permits. Newer equipment can also be subject to unexpected failures. Accordingly, Cleco may incur more frequent unplanned outages, higher than anticipated operating and maintenance expenditures, higher replacement costs of purchased power, increased fuel costs, MISO related costs, and the loss of potential revenue related to competitive opportunities. The costs of such repairs, maintenance, and purchased power may not be fully recoverable in rates and could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Cleco’s generating facilities are fueled primarily by coal, natural gas, petroleum coke, and lignite. The deliverability of these fuel sources may be disallowedconstrained due to such factors as parthigher demand, decreased regional supply, production shortages, weather-related disturbances, railroad constraints, waterway levels, labor strikes, or lack of transportation capacity. If suppliers are unable to deliver the contracted volume of fuel and associated inventories are depleted, Cleco Power may be unable to operate generating units which may cause Cleco Power to operate at higher overall energy costs, which would increase the cost to customers. Cleco Power’s fuel and MISO-procured/settled energy expenses, which are recovered from its customers through the FAC, are subject to refund until either a prudency review or a periodic fuel audit is conducted by the LPSC. In June 2015, the LPSC approved a long-term
Competition for access to other natural resources, particularly oil and natural gas, hedging pilot program requiringcould negatively impact Cleco Power’s ability to access its lignite reserves. Placement of drilling rigs and pipelines for developing oil and gas reserves can preclude access to lignite in the same areas. Additionally, Cleco Power could be indirectly liable for the impacts of other companies’ activities on lands that have been mined and reclaimed by Cleco Power. Access to establishlignite reserves or the liability for impacts on reclaimed lands may not be recoverable in rates and could have a proposalmaterial adverse effect on the results of operations, financial condition, or cash flows of Cleco.
The construction of, and capital improvements to, power generation and transmission and distribution facilities involve substantial risks. Should construction or capital improvement efforts be significantly more expensive than planned, the financial condition, results of operations, or liquidity of Cleco could be materially affected.
Cleco’s ability to complete construction of, or capital improvements to, power generation and transmission and distribution facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include engineering and project execution risk and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as set forth under their contracts, changes in the scope and timing
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of projects, inaccurate cost estimates, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel or material costs, changes in the economy, changes in laws or regulations, including environmental compliance requirements, and other events beyond the control of Cleco may materially affect the schedule and cost of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Cleco could incur additional costs including termination payments, face increased risk of potential write-off of the investment in the project, or Cleco Power may not be able to recover such costs in rates. Furthermore, failure to maintain various levels of generating unit availability or transmission and distribution reliability may result in various disallowances of Cleco Power’s investments.
Weather Sensitivity
The operating results of Cleco are affected by weather conditions and may fluctuate on a long-term naturalseasonal basis.
Weather conditions directly influence the demand for electricity, particularly with respect to residential customers. In Cleco’s service territory, demand for power typically peaks during the hot summer months. As a result, Cleco’s financial results may fluctuate on a seasonal basis. In addition, Cleco has sold less power and, consequently, earned less income when weather conditions were milder. Unusually mild weather in the future could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Severe weather, including hurricanes and winter storms, can affect transportation of fuel to plant sites and can be destructive, causing outages and property damage that can potentially result in additional expenses, lower revenue, and additional capital restoration costs. Extreme drought conditions can impact the availability of cooling water to support the operations of generating plants, which can also result in additional expenses and lower revenue.
The physical risks associated with climate changes could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
If climate changes occur that result in warmer temperatures in Cleco’s service territories, it could result in one or more physical risks, such as an increase in sea level, wind and storm surge damages, wetland and barrier island erosion, risks of flooding, and changes in weather conditions, such as changes in temperature and precipitation patterns, and potential increased impacts of extreme weather conditions or storms, or could affect Cleco’s operations. Cleco’s assets are in and serve communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas procurement programinfrastructure is located in these areas and is susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generating facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on Cleco’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change would adversely impact the economic health of a region or result in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Litigation
Cleco is subject to litigation related to the 2016 Merger.
In connection with the 2016 Merger, four actions were filed in the 9th Judicial District Court for Rapides Parish, Louisiana and three actions were filed in the Civil District Court for Orleans Parish, Louisiana. One of the actions filed in Rapides Parish has been dismissed. The remaining three actions in Rapides Parish have been consolidated. The three actions in Orleans Parish have been transferred to Rapides Parish and consolidated with the other litigation in Rapides Parish. The actions were filed against Cleco Corporation and, among others, Cleco Partners, Merger Sub, and members of the Board of Directors of Cleco Corporation. The petitions generally alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process, agreeing to the 2016 Merger at a price that allegedly undervalues Cleco, and failing to disclose material information about the 2016 Merger. The
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petitions also alleged that Cleco Partners, Cleco, and Merger Sub and, in some cases, certain of the investors in Cleco Partners either aided and abetted or entered into a civil conspiracy to advance those supposed breaches of duty. The petitions seek various remedies, including monetary damages, which includes attorneys’ fees and expenses. In September 2016, the District Court granted the exceptions filed by Cleco and dismissed all claims asserted by the former shareholders. The plaintiffs appealed the District Court’s ruling, and in December 2017, the Louisiana Third Circuit Court of Appeal issued an order reversing and remanding the case back to the District Court for further proceedings. In January 2018, Cleco filed a writ with the Louisiana Supreme Court seeking review of the Third Circuit Court of Appeal’s decision. In March 2018, the Louisiana Supreme Court denied the writ. Cleco filed writs of exception of res judicata and no cause of action in the District Court seeking dismissal of the case. On January 14, 2019, the District Court denied the writs. A hearing on plaintiffs’ request for certification of a class was scheduled for August 26, 2019; however, prior to the hearing, the parties reached an agreement to certify a limited class.
It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to seek monetary relief from Cleco. Cleco is not able to predict the outcome of these actions, or others, nor can Cleco predict the amount of time and expense that will be designedrequired to provide gas price stability for a minimumresolve the actions. In addition, the cost to Cleco of five years. The proposal is currently scheduled to be submitted todefending the LPSCactions, even if resolved in the second half of 2017.

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 thatCleco’s favor, could be used by Cleco Power to hedgesubstantial. Such actions could also divert the attention of Cleco’s management and mitigate commodities risk. resources from day-to-day operations.

The Dodd-Frank Act increases regulatory oversightoutcome of OTC energy derivatives, including (1) requiring standardized OTC derivatives tolegal proceedings cannot 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 requirementspredicted. An adverse finding could cause Cleco Power’s future OTC transactions to be more costly and have ana material adverse effect on its liquidity duethe results of operations, financial condition, or cash flows of Cleco.
Cleco is party to additional capital requirements.various litigation matters arising out of the ordinary operations of their business. The ultimate outcome of these matters cannot presently be determined, nor, in many cases, can the liability that could potentially result from a negative outcome in each case presently be reasonably estimated. The liability that Cleco may ultimately incur with respect to any of these cases in the event of a negative outcome may be in excess of amounts currently reserved and insured against with respect to such matters and, as a result, these matters may have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Workforce
Failure to attract and retain an appropriately qualified workforce could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Certain events, such as an aging workforce without appropriate replacements, lack of equivalent or enhanced skill sets to fulfill future needs, or unavailability of contract resources, may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, by standardizing OTC products, these reforms could limitthis 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 effectivenesstransfer 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 Power’s hedging programs becausecould be materially adversely affected.
Alternative Generation Technology
Changes in technology may have a material adverse effect on the value of Cleco Power would have less abilityand Cleco Cajun’s generating facilities.
A basic premise of Cleco’s business is that generating electricity at central power plants achieves economies of scale and produces electricity at a relatively low price. There are alternative technologies to tailor OTC derivativesproduce electricity, most notably wind turbines, photovoltaic cells, and other solar generated power. Many companies and organizations conduct research and development activities to matchseek improvements in alternative technologies. As new technologies are developed and become available, the precise risk it is seeking to protect. The law givesquantity and pattern of electricity purchased by customers could decline, with a corresponding decline in revenues derived by generating assets. As a result, the CFTC authority to exempt end usersvalue of energy commodities. Cleco Power would qualifyand Cleco Cajun’s generating facilities could be reduced.
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Insurance
Cleco’s insurance coverage may not be sufficient.
Cleco currently has property, casualty, cybersecurity and liability insurance policies in place to protect its employees, directors, and assets in amounts that it considers appropriate. Such policies are subject to certain limits and deductibles. Insurance coverage may not be available in the future at current costs, on commercially reasonable terms, or at all, and the insurance proceeds received for any loss of, or any damage to, any of Cleco’s facilities may not be sufficient to restore the end-user exemption which reduces butloss or damage without a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
Like other utilities that serve coastal regions, Cleco Power does not eliminatehave insurance covering its transmission and distribution system, other than substations, because it believes such insurance to be cost prohibitive. In the applicabilityfuture, Cleco Power may not be able to recover the costs incurred in restoring transmission and distribution properties following hurricanes or other natural disasters through issuance of these measures. Management continuesstorm recovery bonds or a change in Cleco Power’s regulated rates or otherwise, or any such recovery may not be timely granted. Therefore, Cleco Power may not be able to monitor this lawrestore any loss of, or damage to, any of its transmission and its possible impactsdistribution properties without a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Regulatory Risks
Regulatory Compliance

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

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

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.

costs.

As a result of the 2016 Merger, Cleco Holdings and Cleco Power made the 2016 Merger Commitments to the LPSC including, but not limited to, the extension of Cleco Power’s current FRP for an additional two years, maintaining employee headcount, salaries, and benefits for ten years, and a limitation from incurring additional long-term debt, excluding non-recourse debt, unless certain financial ratios are achieved. A report on the statusAdditionally, upon approval of the Merger Commitments must be filed annuallyCleco Cajun Transaction, Cleco made commitments to the LPSC including, but not limited to, holding Cleco Power retail customers harmless for any adverse impacts, increased costs of debt or equity, and credit rating downgrades attributable to the Cleco Cajun Transaction; the repayment of $400.0 million of Cleco Holdings’ debt by October 31 for the 12-month period ended June 30.

On2024; and a $4.0 million annual reduction to Cleco Power’s retail customer rates.

In 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

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. OnIn 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

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will be those that do not exceed the utility’s share of the actual taxes paid to those federal and state taxing authorities. Cleco Power filed a motion to intervene in this proceeding along with other Louisiana utilities. 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, Cleco Power’s cost of fuel used for electric generation and cost of purchased power expenses are recovered through the LPSC-established FAC, thatwhich 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 2016January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. If a disallowance of fuel costs is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides forCleco Power an EAC to recover from customers certain costs of environmental compliance. The costs eligible for recovery are prudently incurred air emissions credits associated with complying with federal, state, and local air emission regulations that apply to the generation of electricity reduced by the sale of such allowances. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. 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.

Cleco Power currently has EAC filings for 2016January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. If a disallowance of environmental costs is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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

FERC Audit
FERC conducts audits 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 valueCleco Power making refunds of benefit plan assets and increase the Company’s liabilities related to such plans. Sustained declines in the fair valuepreviously recorded revenue.

Generally, Cleco Power records wholesale transmission revenue through approved formula rates, Attachment O 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 liquidityMISO tariff, and results of operations.

Performancecertain grandfathered agreements. The calculation of the capital markets affectsrate formulas, as well as FERC accounting and reporting requirements, are subject to periodic audits by FERC. In March 2018, the valueDivision of assets that are heldAudits and Accounting within the Office of Enforcement of FERC initiated an audit of Cleco Power for the period of January 1, 2014, through June 30, 2019. On September 27, 2019, Cleco Power received the final audit report, which indicated 12 findings of noncompliance with a combination of FERC accounting and reporting requirements and computation of revenue requirements along with 59 recommendations associated with the audit period. Cleco Power submitted a plan for implementing the audit recommendations on October 28, 2019. Cleco Power also submitted the refund analysis on November 7, 2019, which resulted in trust to satisfy future obligations under Cleco’s defined benefit pension plan. Sustained adverse market performance could result in lower ratesan estimated refund of return for these assets than projected by Cleco and could increase Cleco’s funding requirements$3.5 million 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 measuredFERC audit findings, pending final assessment 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 resultsFERC Division 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,Audits 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,

including the ability to draw on their respective bank credit facilities. ClecoAccounting. Management is unable to predict the degreetiming of success theyfuture audits and whether or not the outcome of such future audits 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

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
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market is determined by MISO. Costs in the MISO South region are heavily influenced by commodity fuel prices, transmission congestion, dispatch of the generating assets owned not only by Cleco, 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. TheFor Cleco Power, the costs of such capacity may not be recoverable in its rates and could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco. Using MISO’s unforced capacity method for determining generating unit capacity, Cleco Power’s fleet provided for 590546 MW of capacity in excess of its peak, coincident to MISO’s peak, in 2016.

2019.

TCJA
Changes in taxation due to uncertain effects of the TCJA could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
The budget reconciliation act commonly referred to as the TCJA was signed into law on December 22, 2017. Proposed rulemakings issued by the IRS subsequent to the TCJA could have a material adverse effect on the results of operations, financial conditions, or cash flows of Cleco. Cleco continues to assess the regulatory treatment of the TCJA, which could also have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.
On July 10, 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT, resulting from the enactment of the TCJA, in Cleco Power’s application for its next FRP, which was filed on June 28, 2019. The anticipated new rates will be effective July 1, 2020. At March 31, 2020, Cleco Power had a regulatory liability of $375.0 million for the portion of the net reduction to ADIT subject to regulatory treatment.
Reliability and Infrastructure ProtectionCIP Standards Compliance

Cleco is subject to mandatory reliability and critical infrastructure protectionCIP 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 protectionCIP standards, subject to FERC approval, for users of the nation’s transmission system. FERC enforces compliance with these standards. New standards are being developed and existing standards are continuously being modified.

As these standards continue to be adopted and modified, they may impose additional compliance requirements on Cleco Power and Cleco Cajun separately, which may result in an increase inincreased 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 RESERC Reliability Corporation Regional Entity conducts a NERC Reliability Standards audit and a NERC CIP audit every three years.years on Cleco Power’s nextPower and Cleco Cajun separately. Cleco Cajun’s NERC CIP audit is scheduled to beginoccurred in AprilJune 2019. The preliminary findings have been received by Cleco Cajun.
Management is unable to predict the final financial outcome of thisthe current Cleco Power NERC Reliability Standards audit, the current Cleco Cajun NERC CIP audit, or any future audits, oraudits. Management is also unable to predict whether any findings will have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

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
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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 could be rendered uneconomical to maintain or operate and could prompt early retirement of certain generation units. Any legal obligation that would require Cleco to substantially reduce its emissions beyond present levels could require extensive mitigation efforts and could raise uncertainty about the future viability of some fossil fuels as fuel for new and existing electric generating facilities.EGUs. Cleco will evaluate potential solutions to comply with such regulations and monitor rulemaking and any legal matters impacting the proposed regulations. Cleco may incur significant capital expenditures or additional operating costs to comply with such revisions, reinterpretations, and new requirements. If Cleco were to fail to comply, it could be subject to civil or criminal liabilities and fines or may be forced to shut down or reduce production from its facilities. Cleco cannot predict the timing or the outcome of pending or future legislative and rulemaking proposals.

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

Cleco Power’s Rates

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

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

Cleco Power’s revenues and earnings are substantially affected by regulatory proceedings known as rate cases or, in some cases, a request for extension of an FRP. During those cases, the LPSC determines Cleco Power’s rate base, depreciation rates, operation and maintenance costs, and administrative and general costs that Cleco Power may recover from its retail customers through its rates. In some instances, the outcome of a rate case or request for extension of an FRP may impact wholesale decisions of Cleco Power. These proceedings may examine, among other things, the prudence of Cleco Power’s operation and maintenance practices, level of subject expenditures, allowed rates of return, and previously incurred capital expenditures. The LPSC has the authority to disallow costs found not to have been prudently incurred. Rate cases generally have timelines of approximately one year, and decisions are typically subject to appeal, potentially leading to additional uncertainty. The transmission tariffs of Cleco Power are regulated by FERC with its own regulatory proceedings. Both the LPSC and FERC regulatory proceedings can involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, all of whom have differing concerns but who have the common objective of limiting rate increases or reducing rates.

Transmission rates that MISO transmission owners may collect are regulated by FERC. Two complaints were filed withOn November 21, 2019, FERC seekingvoted to reduce theadopt new methodology for evaluating base ROE component of the transmission rates that MISO transmission owners, including Cleco, may collectfor public utilities under the MISO tariff. As of December 31, 2016,Federal Power Act, as amended. Cleco Power had $3.3 million accrued for ROE reductions, including accrued interest. On February 13, 2017, $1.2 million of refunds relatingis unable to the first complaint were submitted to MISO.determine when a binding FERC order will be issued. Any reduction to the ROE component of the transmission rates could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Retail Electric Service

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

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

Cleco Power’s

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

FERC conducts a review of Cleco Power’sCleco’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.during the fourth quarter of 2020. In the future, if FERC determines Cleco Power and/or Cleco Cajun possesses generation market power in excess of certain thresholds, Cleco Power and/or Cleco Cajun could lose the right to sell wholesale generation at market-based rates, which could result in a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Weather SensitivityFinancial Risks

The operating results

Controls and Procedures
Cleco has identified material weaknesses in internal control over financial reporting. If these material weaknesses are not remediated, they could result in material misstatements in Cleco’s financial statements.
A material weakness is a deficiency, or combination of Cleco Power are affected by weather conditions and may fluctuatedeficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a seasonaltimely basis.

Weather conditions directly influence As disclosed in “Managements’ Reports on Internal Control Over Financial Reporting,” Cleco identified a material weakness related to the demanddesign and operation of certain information technology general controls for electricity, particularly kWh salesinformation systems that are relevant to residentialthe preparation of Cleco’s financial statements. Cleco also identified a material weakness in the design and operating effectiveness of controls over the completeness and accuracy of billed and unbilled revenue from contracts with customers. In Cleco Power’s service territory, demand for power typically peaks during the hot summer months. As a result of these material weaknesses, management concluded that Cleco Power’sdid not maintain effective disclosure controls and procedures as of March 31, 2020.

Cleco is taking steps to remediate the underlying cause of these material weaknesses, but Cleco cannot assure that the remediation of the material weaknesses will be successful or that additional material weaknesses in internal controls will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties encountered in implementation, could result in additional material weaknesses, or could result in material misstatements in Cleco’s financial results may fluctuate on a seasonal basis. In addition, statements. These misstatements could result in restatements of Cleco’s financial statements, failure to meet reporting obligations, or cause stakeholders to lose confidence in reported financial information of Cleco.
Commodity Prices
Cleco Power has sold less power and consequently, earned less income when weather conditions were milder. Unusually mild weatherCleco Cajun’s financial performance could be exposed to fluctuations in the futurecommodity prices and other factors, which could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco.

Severe weather, including hurricanes

Cleco Power
Cleco Power may enter into fuel cost hedging transactions to mitigate the volatility in fuel costs passed through to its retail customers. When transactions expire or are offset through liquidation, actual gains or losses are deferred and winter storms,included in the FAC in the month the physical contract settles. Recovery of any of these FAC costs is subject to, and may be disallowed as part of, a prudency review or a periodic fuel audit conducted by the LPSC.
Cleco Cajun
Cleco Cajun is exposed to uncertain market prices of electricity, natural gas, coal, and other commodities that can affect transportationimpact costs of fuel supply for generation, generation revenue, cost to plant sitesserve its contracted wholesale electricity customers, and can be destructive, causingrevenue from these customers. Energy costs and revenues are also subject to volumetric risk due to fluctuations related to unexpected plant outages and property damageuncertain customer load.
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Commodity Hedging and Commercial Transactions
Cleco may enter into fuel supply contracts and/or commercial transactions, including sales to wholesale customers and physical and financial hedges. If these transactions are not managed effectively, they may have a material adverse effect on the liquidity, results of operations, and financial condition of Cleco.
Cleco may enter into physical or financial transactions during its normal course of business. Cleco may also enter into transactions to hedge its exposure to commodity price risk of all or some of its customer supply agreements, natural gas, solid fuel requirements (coal), power, and other commodities, inclusive of transmission and transportation. Transactions are executed within board approved risk management guidelines, including transactions that can potentiallyqualify as derivatives contracts in accordance with accounting guidance.
The accounting treatment for Cleco Cajun’s hedging activities may increase the volatility in Cleco’s financial results.
Cleco Cajun engages in transactions to economically hedge forward commodity market price risk exposure utilizing both physical and financial commodity purchases and sales commitments. Some of these contracts are accounted for as derivatives, which require Cleco to record the fair value of the commitment on the balance sheet with changes in the fair value of all derivatives reflected within current period earnings. As a result, in additional expenses, lower revenue,Cleco is unable to accurately predict the effect that these transactions may have on its results of operations, financial condition, or cash flows.
Counterparty Risk and additional capital restoration costs. Extreme drought conditions can impactGuarantees
Cleco is exposed to the availability of cooling water to support the operations of generating plants,risk that counterparties may not meet their performance obligations, 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 resultsoperating and financial performance of operations,Cleco.

Counterparties may fail to perform on their physical or financial condition,obligations. Currently, some master agreements with counterparties contain provisions that require the counterparties to provide credit support to secure all or cash flowspart of Cleco.

their obligations to Cleco, recognizes that certain groups associate severe weather withor specifically to Cleco Power or Cleco Cajun. If the conceptcounterparties to these arrangements fail to perform, Cleco may enforce and recover the proceeds from the credit support provided; however, in the event of global climate change and forecasta default, credit support may not always be adequate to cover the possibility that these weather events could have a material impact on future resultsrelated obligations. In such event, Cleco may incur losses in excess of operations should they occur more frequently and with greater severity. If there isamounts already paid, if any, to the counterparties or due to 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 lossadverse replacement cost of the protection offered by coastal wetlands. A significant portiontransaction.

The credit commitments of the nation’s oil and gas infrastructure is located in these areas and is susceptible to storm damage that couldCleco’s lenders under its bank facilities may not be aggravated by wetland and barrier island erosion,honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could give risematerially affect the adequacy of its liquidity sources. In no case would Cleco Power bear any commodity or credit risk of Cleco Cajun.
Cleco may be required to 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 abilityprovide credit support 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 risksits counterparties, which could have a material adverse effect on Cleco’s liquidity ratios and liquidity.

Cleco may guarantee the resultsperformance of operations, financial condition,all or cash flowssome of Cleco.

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, Louisianaits commercial transaction obligations 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 petitionsmay 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 costprovide counterparty credit support to Clecosecure all or part of defending the actions, even if resolvedthose obligations. Downgrades in Cleco’s favor,credit quality or changes in the market prices of transaction-related energy commodities could increase the collateral required to be substantial. Such actions could also diverton deposit with the attention of Cleco’s management and resources from day-to-day operations.

counterparty or clearing house. The outcome of legal proceedings cannot be predicted. An adverse findingrequired credit support or increase in credit support could have a material adverse effect on Cleco’s liquidity ratios and liquidity.

Global Economic Environment and Uncertainty; Access to Capital
Adverse capital market performance could result in reductions in the fair value of benefit plan assets and increase Cleco’s liabilities related to such plans. Sustained declines in the fair value of the plan’s assets or sustained increases in plan liabilities could result in significant increases in funding requirements, which could adversely affect Cleco’s liquidity and results of operations, financial condition, or cash flows of Cleco.

Cleco is party to various litigation matters arising outoperations.

Performance of the ordinary operationscapital markets affects the value of their business. The ultimate outcomeassets 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 matters cannot presently be determined, nor,assets than projected by Cleco and could increase Cleco’s funding requirements related to the pension plan. Additionally, changes in many cases, caninterest rates affect the liability thatpresent value of Cleco’s liabilities under the pension plan. Adverse changes in assumptions or adverse actual events 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 casescause additional minimum contributions.
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Changes in the eventmethod of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under Cleco’s current debt agreements may bear interest at rates based on LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a negative outcomebenchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. In addition, the overall financial markets may be in excess of amounts currently reserved and insured against with respect to such matters and,disrupted as a result these matters may have a material adverse effect onof the resultsphase-out or replacement of operations,LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the 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.

Taxes

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisionsmarket could have a material adverse effect on theCleco’s financial condition, results of operations, financial condition, orand cash flows.

Inflation
Annual inflation rates, as measured by the United States Consumer Price Index, have averaged 2% during the three years ended December 31, 2019. Under established regulatory practice, historical costs have traditionally formed the basis for recovery from customers. As a result, Cleco Power’s future cash flows designed to provide recovery of Cleco.

historical plant costs may not be adequate to replace property, plant, and equipment in future years.

Disruptions in the capital and credit markets may adversely affect Cleco’s cost of capital and ability to meet liquidity needs or access capital to operate and grow the business.
Cleco’s business is capital intensive and dependent upon Cleco’s abilities to access capital at reasonable rates and other terms. Cleco’s liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster or when there are spikes in the price for natural gas and other commodities. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel, purchased power, or storm restoration costs; higher than expected required pension contributions; an acceleration of payments or decreased credit lines; less cash flow from operations than expected; or other unexpected events, could cause the financing needs of Cleco makes judgments regardingto increase materially.
Events beyond Cleco’s control, such as political uncertainty in the utilizationUnited States (including the ongoing debates related to the United States federal government budget and debt ceiling), volatility and disruption in global capital and credit markets, may create uncertainty that could increase their cost of capital or impair their ability to access the capital markets, including the ability to draw on their respective bank credit facilities. Additionally, upon approval of the Cleco Cajun Transaction, Cleco made commitments to the LPSC including, but not limited to, holding Cleco Power retail customers harmless for any adverse impacts, increased costs of debt or equity, and credit rating downgrades attributable to the Cleco Cajun Transaction; the repayment of $400.0 million of Cleco Holdings’ debt by 2024; and a $4.0 million annual reduction to Cleco Power’s retail customer rates. Cleco may be unable to predict the degree of success they will have in renewing or replacing their respective credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing income tax creditsfacilities. If Cleco is unable to access the credit and the potential tax effectscapital markets on terms that are reasonable, it may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost 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. Changescapital, which, in federal, state, or local tax laws, adverse tax audit results, or adverse tax rulings on positions taken by Clecoturn, could have a material adverse effect on the results of operations, financial condition,Cleco’s ability to fund capital expenditures or cash flows of Cleco.

to service debt, or on Cleco’s flexibility to react to changing economic and business conditions.

Cleco Credit Ratings

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

sources, and a restriction on Cleco Power making distributions to Cleco Holdings.

Neither Cleco Holdings nor Cleco Power can assure that its current debt ratings will remain in effect for any given period of time or that one or more of its debt ratings will not be lowered or withdrawn entirely by a rating agency. If S&P, Moody’s, or Moody’sFitch 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 wouldcould result in additional fees and higher interest rates for borrowings under their respective credit facilities. In addition, Cleco Holdings or Cleco Power, as the case may be, would likely be required to pay higher interest rates in future debt financings, may be subject to more onerous debt covenants, and their pool of potential investors and funding sources could decrease. In addition, the
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Technology

2016 Merger Commitments provide for limitations on the amount of distributions that may be paid from Cleco Power to Cleco Holdings, depending on Cleco Power’s common equity ratio and Terrorism Threats

The operational and information technology systems on whichits corporate credit/issuer ratings. As a result, Cleco reliesPower may be prohibited from making distributions to conduct itsCleco Holdings in the event of a ratings downgrade below investment grade.

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

Cleco’s systems, including its

Cleco makes judgments regarding the utilization of existing income tax credits and the potential tax effects of various financial information, operational systems, advanced metering,transactions 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.

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 to estimate their obligations to taxing authorities. Tax obligations include income, franchise, property, sales and use, and employment-related taxes. These judgments may include reserves for potential adverse outcomes regarding tax positions that have been taken. Changes in federal, state, or 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,local tax laws, adverse tax audit results, 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 oradverse tax rulings 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 intopositions taken 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

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.

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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.

USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the Exchange Notes pursuant to the exchange offer. The exchange offer is intended to satisfy our obligations under the registration rights agreement, which we entered into in connection with the issuance and sale of the Outstanding Notes, for which we received $882.1$297.9 million in net proceeds that were used to repay the then-remaining amounts due under the Bridge Facility and pay a portion of the amounts due under the Acquisition Term Loan Facility. See “Registration Rights Agreement.”

In consideration for issuing the Exchange Notes as contemplated in this prospectus, we will receive in exchange a like principal amount of Outstanding Notes. The form and terms of the Exchange Notes are identical in all material respects to the form and terms of the Outstanding Notes, except the offer and exchange of the Exchange Notes have been registered under the Securities Act and the Exchange Notes will not have restrictions on transfer, registration rights or provisions for additional 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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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.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND


RESULTS OF OPERATIONS

RECENT EVENTS
COVID-19
On March 11, 2020, the World Health Organization declared the current COVID-19 outbreak to be a global pandemic, and on March 13, 2020, the United States declared a national emergency. In response to these declarations and the rapid spread of COVID-19, federal, state and local governments have imposed varying degrees of restrictions on business and social activities to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory. Cleco has modified some of its business operations, as these restrictions have significantly impacted many sectors of the economy, including record levels of unemployment, with businesses, nonprofit organizations, and governmental entities modifying, curtailing, or ceasing normal operations. Cleco has also modified certain business practices to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. For example, since March 13, 2020, Cleco temporarily closed all customer service offices, temporarily suspended disconnects and late fees, restricted access to its administrative offices, implemented remote work arrangements, prohibited all non-critical travel for Cleco business, prohibited in-person gatherings of more than 10 people at Cleco work locations, and required all meetings to be held virtually or via telephone.
Cleco provides a critical service to its customers which means that it is paramount that it keeps its employees who operate its business safe and informed and has taken and continues to take and update precautions for that purpose. In addition, Cleco assessed and updated its existing business continuity plans for its business units in the context of the COVID-19 pandemic. The LPSC has issued a moratorium on disconnects of customers for non-payment, and accordingly Cleco has taken steps to assure its customers that disconnections for non-payment as well as late fees are temporarily suspended. Cleco is also working with its suppliers to understand the potential impacts to its supply chain. This is a rapidly evolving situation and could lead to extended disruption of economic activity in Cleco’s service territory. Cleco will continue to monitor developments affecting its workforce, customers, and suppliers and take additional precautions as Cleco believes are warranted.
The first priority in Cleco’s response to this crisis has been the health and safety of its employees and those of its customers and other business counterparties. Cleco has implemented preventative measures and developed corporate response plans to minimize unnecessary risk of exposure and prevent infection, while supporting its customers’ operations to the best of its ability in the circumstances. Cleco has an Emergency (Crisis) Response Team for health, safety, and environmental matters and personnel issues, and has established a Pandemic Plan Team to address various impacts of COVID-19 as they have been developing. This team provides leadership and guidance for planning, risk management, and any policy changes. The team ensures that areas of Cleco plan, manage, and safely execute the pandemic plan set forth by management. Cleco employees are required to report daily to their manager or supervisor any changes to the employee’s health, the employee’s family’s health, and travel plans. This is reported to the Pandemic Plan Team at a minimum of three times per week. The results are then communicated on a weekly update call to all employees. Proper measures are taken for any employee at risk of having COVID-19 and measures are taken to protect any employees with which the at-risk employee had been in contact. Cleco also has modified certain business practices, including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences, to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other federal, state, and local governmental and regulatory authorities. Cleco is continuing to address concerns to protect the health and safety of its employees and those of its customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, Cleco, its suppliers, and other business counterparties to experience operational delays.
In addition, Cleco has implemented certain measures that it believes will provide financial flexibility and maintain liquidity. On March 23, 2020, Cleco Holdings made an $88.0 million draw on its credit facility, and Cleco Power made a $150.0 million draw on its credit facility. While Cleco continues to assess the COVID-19 situation, at this time Cleco cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being
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experienced in the markets will have on its business, cash flows, liquidity, financial condition, and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities, including the LPSC and FERC, Cleco’s customers and suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding certain risks associated with the COVID-19 pandemic, see “Risk Factors — COVID-19.”
Credit Facility Amendments
On May 15, 2020, Cleco Holdings entered into the Cleco Holdings Amendments. Also, on May 15, 2020, Cleco Power entered into the Cleco Power Amendment. The Amendments extend the terms of each facility through June 28, 2022. The current borrowing costs under the amended Cleco Holdings revolving credit facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. Cleco Holdings’ amended $300.0 million term loan bears interest at an interest rate of LIBOR plus 1.875% and Cleco Holdings’ amended $30.0 million term loan bears interest at an interest rate of LIBOR plus 1.875%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and additional interest of 0.50% under any of the Cleco Holdings Amendments. The current borrowing costs under the amended Cleco Power revolving credit facility are equal to LIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees of 0.150%. If Cleco Power’s credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of 0.125% under the Cleco Power Amendment. The Amendments also include customary LIBOR-transition provisions.
OVERVIEW

Cleco is a regional energy company that, conductsprior to the close of the Cleco Cajun Transaction, conducted substantially all of its business operations through its primary subsidiary, Cleco Power. As a result of the Cleco Cajun Transaction, Cleco now conducts substantially all of its business operations through its two primary subsidiaries:
Cleco Power, is a regulated electric utility company that owns nine10 generating units with a total nameplate capacity of 3,3103,360 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, Mississippi; and
Cleco also conducted wholesale business operations through its Midstream subsidiary. MidstreamCajun, an unregulated electric utility company that owns Evangeline (which owned and operated Coughlin). On March 15, 2014, the Coughlineight generating assets were transferred to Cleco Power. Coughlin consists of two generating units with a total nameplaterated capacity of 775 MW.3,555 MW and supplies wholesale power and capacity in Arkansas, Louisiana, and Texas. Upon the closing of the Cleco Cajun Transaction, Cottonwood Energy entered into the Cottonwood Sale Leaseback.
Cleco Cajun Transaction
Upon completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a reportable segment and is reflected as such in this prospectus. For more information on the transfer of Coughlin to Cleco Power,Cajun Transaction, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 18—Coughlin Transfer.”

Merger

On April 13, 2016, Cleco Holdings completed its merger with Merger Sub whereby Merger Sub merged with3 — Business Combinations” 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—Data — Notes to the Unaudited Interim Financial Statements—Statements — Note 3—2 — Business Combinations.”

Cleco’s unaudited condensed consolidated financial statements for the quarter ended March 31, 2019, include the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, until March 31, 2020.

Cleco Power

Many factors affect Cleco Power’s primary business of generating, delivering, and selling electricity. These factors include weather and the presence of a stable regulatory environment, which impacts cost recovery and the ROE, as well as the recovery of costs related to growing energy demand and rising fuel prices; the ability to increase energy sales while containing costs; the ability to reliably deliver power to its jurisdictional customers; the ability to meetcomply with increasingly stringent regulatory and environmental standards; and the ability to successfully perform in MISO andwhile subject to the related operating challenges and uncertainties, including increased wholesale competition relative to more suppliers. Keycompetition. Cleco Power’s current key initiatives on which Cleco Power is working includeare continuing construction on the Cenla Transmission Expansion project and the St. Mary Clean Energy Center project; beginning construction on the Terrebonne to Bayou Vista to Segura Transmission project andproject; continuing the Coughlin PipelineDSMART project; and maintaining and growing its wholesale and retail business. These initiatives are discussed below.
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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.

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 to Segura Transmission Project

The Terrebonne to Bayou Vista to Segura Transmission project includes the construction of additional48 miles of 230kV transmission interconnection facilitiesline, a 230/138kV substation and three substation expansions in south of Teche Power Station.Louisiana. The project is expected to cost approximately $136.7 million. The project is expected to increase reliability, reduce congestion,provide transmission system redundancy, and provide hurricane hardening for customers in southeastsouth Louisiana. A line routing study beganCleco Power received MISO approval for the project in March 2016, and permitting and right-of-way acquisition began in May 2016. Cleco Power’s portion ofDecember 2017. Construction has begun on expansions to existing substations, with the joint project with Entergy Louisiana is expected to cost $48.0 million. Construction isnorthern phase expected to be complete bycompleted in the thirdfirst quarter of 2018.2021 and the southern phase expected to be completed in the fourth quarter of 2021. As of DecemberMarch 31, 2016,2020, Cleco Power had spent $1.4$15.6 million on the project.

Coughlin Pipeline

DSMART Project

The Coughlin PipelineDSMART project includes constructionmodernization of a pipeline directly connecting the Pine Prairie Energy CenterCleco Power’s distribution system by replacing or upgrading distribution line equipment utilizing new and emerging technologies to Cleco’s Coughlin Power Station.facilitate automatic fault isolation, service restoration, and fault location. The project is expected to increase fuel delivery reliabilityprovide savings through a reduction in outage restoration time, time to locate faults, 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.improved operational efficiencies. The project is also expected to improve safety and reliability of Cleco Power’s distribution assets by minimizing outage patrols and improving situational awareness in the distribution operations center. The total estimated project cost is $90.2 million. The project implementation will be operationalcompleted in phases and management expects the total project will be completed by the third quarterend of 2018 with an estimated cost2025. In January 2019, Cleco Power began the first phase of $29.4 million.

the project. As of March 31, 2020, Cleco Power had spent $2.7 million on the project.

Other

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

RESULTS OF OPERATIONS

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ materially from those estimates.
Comparison of the Three Months Ended March 31, 2020, and 2019
Cleco
 
 
 
 
 
FOR THE THREE MONTHS ENDED MAR. 31,
 
 
 
FAVORABLE/(UNFAVORABLE)
(THOUSANDS)
2020
2019
VARIANCE
CHANGE
Operating revenue, net
$347,572
$344,186
$3,386
1.0%
Operating expenses
292,907
293,600
693
0.2%
Operating income
54,665
50,586
4,079
8.1%
Interest income
1,157
1,491
(334)
(22.4)%
Allowance for equity funds used during construction
(74)
5,688
(5,762)
(101.3)%
Other (expense) income, net
(12,709)
2,777
(15,486)
(557.7)%
Interest charges
35,149
33,999
(1,150)
(3.4)%
Federal and state income tax expense
1,562
5,986
4,424
73.9%
Net income
$6,328
$20,557
$(14,229)
(69.2)%
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Includes the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, through March 31, 2019, and January 1, 2020, through March 31, 2020.
COVID-19 Impacts
The rapid spread of COVID-19 and the varying degrees of restrictions on business and social activities imposed by federal, state, and local governments to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory, have caused Cleco to experience increasingly adverse business conditions, especially in the latter half of March 2020. While Cleco continues to assess the COVID-19 situation, at this time Cleco cannot estimate with any degree of certainty the full impact of the COVID-19 outbreak on its financial condition and future results of operations, although Cleco expects the COVID-19 situation to adversely impact future quarters. For additional discussion regarding risks associated with the COVID-19 pandemic, see “Risk Factors — COVID-19.”
Operating Revenue, Net
Operating revenue, net increased $3.4 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to higher electric operations revenue of $31.3 million and higher other operations revenue of $11.0 million at Cleco Cajun, partially offset by $38.4 million of lower fuel cost recovery revenue at Cleco Power.
Operating Expenses
Operating expenses increased $0.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $31.4 million of higher Cleco Cajun expenses, as well as $8.8 million of higher other operations and maintenance expenses and $2.7 million of higher taxes other than income taxes at Cleco Power. These increases were partially offset by $38.0 million of lower recoverable fuel and purchased power expenses at Cleco Power and $2.2 million of lower Cleco Cajun Transaction costs at Cleco Holdings.
Allowance for equity funds used during construction
Allowance for equity funds used during construction decreased $5.8 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $4.5 million of lower Cleco Power construction costs as a result of various projects being placed in service in 2019 and $1.0 million due to lower AFUDC rates driven by the impact of Cleco Power’s $150.0 million short-term debt borrowings outstanding under its credit facility.
Other (Expense) Income, Net
Other (expense) income, net increased $15.5 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $11.2 million for the decrease in cash surrender value of certain trust-owned life insurance policies as a result of unfavorable market conditions at Cleco Holdings and $2.0 million of higher pension non-service costs at Cleco Power.
Income Taxes
Federal and state income tax expense decreased $4.4 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.6 million for the change in pretax income, excluding AFUDC equity, and $1.2 million for state tax expenses.
The effective income tax rate for the first quarter of 2020 and 2019 was 19.8% and 22.6%, respectively. The estimated annual effective income tax rate used during the first quarter of 2020 and 2019 for Cleco may not be indicative of the full-year income tax rate.
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Results of operations for Cleco Power and Cleco Cajun are more fully described below.
Cleco Power
 
 
 
 
 
FOR THE THREE MONTHS ENDED MARCH 31,
 
 
 
FAVORABLE/(UNFAVORABLE)
(THOUSANDS)
2020
2019
VARIANCE
CHANGE
Operating revenue
 
 
 
 
Base
$147,999
$142,385
$5,614
3.9%
Fuel cost recovery
76,431
114,790
(38,359)
(33.4)%
Electric customer credits
(8,340)
(8,160)
(180)
(2.2)%
Other operations
15,764
19,430
(3,666)
(18.9)%
Affiliate revenue
1,106
300
806
268.7%
Operating revenue, net
232,960
268,745
(35,785)
(13.3)%
Operating expenses
 
 
 
 
Recoverable fuel and purchased power
76,834
114,794
37,960
33.1%
Non-recoverable fuel and purchased power
7,692
8,991
1,299
14.4%
Other operations and maintenance
56,944
47,700
(9,244)
(19.4)%
Depreciation and amortization
43,677
42,377
(1,300)
(3.1)%
Taxes other than income taxes
12,276
9,978
(2,298)
(23.0)%
Total operating expenses
197,423
223,840
26,417
11.8%
Operating income
35,537
44,905
(9,368)
(20.9)%
Interest income
954
994
(40)
(4.0)%
Allowance for equity funds used during construction
(74)
5,688
(5,762)
(101.3)%
Other (expense) income, net
(2,667)
268
(2,935)
*
Interest charges
18,581
17,145
(1,436)
(8.4)%
Federal and state income tax expense
3,338
7,998
4,660
58.3%
Net income
$11,831
$26,712
$(14,881)
(55.7)%
*
Not meaningful
The following table shows the components of Cleco Power’s retail and wholesale customer sales related to base revenue:
 
FOR THE THREE MONTHS ENDED MARCH 31,
(MILLION kWh)
2020
2019
FAVORABLE/
(UNFAVORABLE)
Electric sales
 
 
 
Residential
780
787
(0.9)%
Commercial
582
582
—%
Industrial
484
490
(1.2)%
Other retail
31
31
—%
Total retail
1,877
1,890
(0.7)%
Sales for resale
650
619
5.0%
Total retail and wholesale customer sales
2,527
2,509
0.7%
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The following table shows the components of Cleco Power’s base revenue:
 
FOR THE THREE MONTHS ENDED MARCH 31,
(THOUSANDS)
2020
2019
FAVORABLE/
(UNFAVORABLE)
Electric sales
 
 
 
Residential
$61,890
$56,104
10.3%
Commercial
47,056
44,863
4.9%
Industrial
20,580
20,649
(0.3)%
Other retail
2,679
2,558
4.7%
Surcharge
2,442
5,321
(54.1)%
Total retail
134,647
129,495
4.0%
Sales for resale
13,352
12,890
3.6%
Total base revenue
$147,999
$142,385
3.9%
Cleco Power’s residential customers’ demand for electricity is largely affected by weather. Weather generally is measured in cooling degree-days and heating degree-days. A cooling degree-day is an indication of the likelihood that a consumer will use air conditioning, while a heating degree-day is an indication of the likelihood that a consumer will use heating. An increase in heating degree-days does not produce the same increase in revenue as an increase in cooling degree-days because alternative heating sources are more readily available, and winter energy is typically priced below the rate charged for energy used in the summer. Normal heating degree-days and cooling degree-days are calculated for a month by separately calculating the average actual heating and cooling degree-days for that month over a period of 30 years.
The following chart shows how heating and cooling degree-days varied from normal conditions and from the prior period. Cleco Power uses weather data provided by the National Oceanic and Atmospheric Administration to determine cooling and heating degree-days.
 
FOR THE THREE MONTHS ENDED MARCH 31,
 
 
 
 
CHANGE
 
2020
2019
NORMAL
PRIOR YEAR
NORMAL
Heating degree-days
586
733
891
(20.1)%
(34.2)%
Cooling degree-days
264
108
78
144.4%
238.5%
Base
Base revenue increased $5.6 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to the absence of $4.6 million of deferrals to a regulatory liability for over collections of revenue related to the St. Mary Clean Energy Center project due to the delay in the project’s commercial operational date and the absence of $2.6 million for the reversal of the accumulated LCFC revenue, partially offset by $1.7 million of lower Cleco Katrina/Rita storm restoration surcharge revenue as a result of the completion of the Cleco Katrina/Rita bond repayment in March 2020. For information on the effects of future energy sales on the results of operations, financial condition, or cash flows of Cleco Power, see “Risk Factors — Operational Risks — Future Electricity Sales.”
Fuel Cost Recovery/Recoverable Fuel and Purchased Power
Changes in fuel costs historically have not significantly affected Cleco Power’s net income. Generally, fuel and purchased power expenses are recovered through the LPSC-established FAC, which enables Cleco Power to pass on to its customers substantially all such charges. Approximately 77% of Cleco Power’s total fuel cost during the first quarter of 2020 was regulated by the LPSC. Recovery of FAC costs is subject to periodic fuel audits by the LPSC which may result in a refund to customers. Generally, fuel and purchased power expenses are impacted by customer usage, the per unit cost of fuel used for electric generation, and the dispatch of Cleco Power’s generating facilities by MISO. For more information Cleco Power’s most current fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel
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Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Fuel Audit.”
Other Operations Revenue
Other operations revenue decreased $3.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to the absence of $2.4 million of net generation revenue as a result of the Teche Unit 3 SSR ending in April 2019 and $0.5 million of lower forfeited discounts. For more information on the SSR, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — SSR.”
Other Operations and Maintenance Expense
Other operations and maintenance expense increased $9.2 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $3.5 million of higher fees for outside services, $2.9 million of higher generating station outage maintenance expenses, and $2.3 million of higher uncollectible accounts expense.
Depreciation and Amortization
Depreciation and amortization increased $1.3 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $3.0 million of higher depreciation on normal recurring additions to fixed assets and $2.1 million of higher amortization of intangible property due to the implementation of the START project, partially offset by $2.7 million of lower amortization of storm damages which is based on collections from customers, and the absence of $1.1 million of deferrals of corporate franchise taxes to a regulatory asset.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $2.3 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $1.4 million of higher property taxes and $0.5 million of higher franchise taxes.
Allowance for Equity Funds Used During Construction
Allowance for equity funds used during construction decreased $5.8 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $4.5 million of lower construction costs as a result of the St. Mary Clean Energy Center project, the Coughlin Pipeline project, the Terrebonne to Bayou Vista Transmission project, and the START project being placed in service in 2019 and $1.0 million due to lower AFUDC rates driven by the impact of Cleco Power’s $150.0 million short-term debt borrowings outstanding under its credit facility.
Other (Expense) Income, Net
Other (expense) income, net increased $2.9 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.0 million of higher pension non-service costs and $0.7 million for the decrease in the cash surrender value of company-owned life insurance policies.
Interest Charges
Interest charges increased $1.4 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to lower allowance for borrowed funds used during construction primarily due to the St. Mary Clean Energy Center project, the Coughlin Pipeline project, the Terrebonne to Bayou Vista Transmission project, and the START project being placed in service in 2019.
Income Taxes
Federal and state income tax expense decreased $4.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.8 million for the change in pretax income, excluding AFUDC equity, and $1.6 million for state tax expenses.
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The effective income tax rate for the first quarter of 2020 and 2019 was 22.0% and 23.0%, respectively. The estimated annual effective income tax rate used during the first quarter of 2020 and 2019 for Cleco Power may not be indicative of the full-year income tax rate.
Cleco Cajun
 
 
 
 
 
FOR THE THREE MONTHS ENDED MARCH 31,
 
 
 
FAVORABLE/(UNFAVORABLE)
(THOUSANDS)
2020
2019
VARIANCE
CHANGE
Operating revenue
 
 
 
 
Electric operations
$89,147
$58,194
$30,953
53.2%
Electric customer credits
(153)
(153)
(100.0)%
Other operations
30,961
19,965
10,996
55.1%
Affiliate revenue
161
161
100.0%
Operating revenue, net
120,116
78,159
41,957
53.7%
Operating expenses
 
 
 
 
Fuel used for electric generation
15,572
9,922
(5,650)
(56.9)%
Purchased power
44,675
30,445
(14,230)
(46.7)%
Other operations and maintenance
20,516
14,410
(6,106)
(42.4)%
Depreciation and amortization
10,103
5,410
(4,693)
(86.7)%
Taxes other than income taxes
3,473
3,145
(328)
(10.4)%
Total operating expenses
94,339
63,332
(31,007)
(49.0)%
Operating income
25,777
14,827
10,950
73.9%
Interest income
155
254
(99)
(39.0)%
Other income (expense), net
34
(496)
530
106.9%
Interest charges
10
(10)
(100.0)%
Federal and state income tax expense
6,421
3,529
(2,892)
(81.9)%
Net income
$19,535
$11,056
$8,479
76.7%
Represents the financial results from the closing of the Cleco Cajun Transaction on February 4, 2019, through March 31, 2019, and January 1, 2020, through March 31, 2020.
Electric Operations
Electric operations revenue increased $31.0 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to the increase in wholesale revenue, which is partially the result of the Cleco Cajun Transaction closing in February 2019.
Other Operations Revenue
Other operations revenue increased $11.0 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $5.7 million of higher lease revenue, including variable lease revenue, as a result of the Cottonwood Sale Leaseback and $3.6 million of higher transmission revenue from wholesale customers. These increases were partially the result of the Cleco Cajun Transaction closing in February 2019. For more information on the Cottonwood Sale Leaseback agreement, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases — Lessor Agreements — Cottonwood Sale Leaseback Agreement” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 4 — Leases — Cottonwood Sale Leaseback Agreement.”
Fuel Used for Electric Generation
Fuel used for electric generation increased $5.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to mark-to-market losses for gas related derivative contracts and higher fuel costs, which is partially the result of the Cleco Cajun Transaction closing in February 2019.
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Purchased Power
Purchased power increased $14.2 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to a higher amount of purchased power from MISO, which is partially the result of the Cleco Cajun Transaction closing in February 2019.
Other Operations and Maintenance Expense
Other operations and maintenance expense increased $6.1 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $3.7 million of higher generation operations expenses and $2.3 million of higher administrative and generations expenses. These increases were partially the result of the Cleco Cajun Transaction closing in February 2019.
Depreciation and Amortization
Depreciation and amortization increased $4.7 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to normal recurring additions to fixed assets. This increase was partially the result of the Cleco Cajun Transaction closing in February 2019.
Income Taxes
Federal and state income tax expense increased $2.9 million during the first quarter of 2020 compared to the first quarter of 2019 primarily due to $2.4 million for the increase in pretax income and $1.0 million for state tax expenses. These increases were partially offset by $0.5 million of miscellaneous tax items.
The effective income tax rate for the first quarter of 2020 and 2019 was 24.7% and 24.2%, respectively. The estimated annual effective income tax rate used during the first quarter of 2020 and 2019 for Cleco Cajun may not be indicative of the full-year income tax rate.
Comparison of the Years Ended December 31, 2016,2019, 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 

2018

Cleco
 
 
 
 
 
FOR THE YEAR ENDED DEC. 31,
 
 
 
FAVORABLE / (UNFAVORABLE)
(THOUSANDS)
2019
2018
VARIANCE
CHANGE
Operating revenue, net
$1,639,605
$1,231,044
$408,561
33.2%
Operating expenses
1,324,711
986,487
(338,224)
(34.3)%
Operating income
314,894
244,557
70,337
28.8%
Interest income
6,090
6,073
17
0.3%
Allowance for equity funds used during construction
15,397
14,159
1,238
8.7%
Other income (expense), net
758
(14,328)
15,086
105.3%
Interest charges
141,309
126,642
(14,667)
(11.6)%
Federal and state income tax expense
43,165
29,382
(13,783)
(46.9)%
Net income
$152,665
$94,437
$58,228
61.7%
Significant factors affecting Cleco’s net loss attributableincome during the year ended December 31, 2019, are described below.
Operating Revenue
Operating revenue, net increased $408.6 million during 2019 as compared to 2018 primarily due to the successor period April 13, 2016, through December 31, 2016, was $24.1 million. Thereaddition of $375.5 million of electric operations and $117.5 million of other operations revenue at Cleco Cajun. These increases were no significant changespartially offset by $51.4 million of lower fuel cost recovery revenue at Cleco Power.
Operating Expenses
Operating expenses increased $338.2 million during 2019 as compared to 2018 primarily due to the addition of $400.3 million of Cleco Cajun’s operating expenses, as well as $10.4 million of higher depreciation and amortization expenses and $4.6 million of higher other operations and maintenance expenses at Cleco Power. These increases were partially offset by $51.3 million of lower recoverable fuel and purchased power expenses at Cleco Power.
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Other Income (Expense), Net
Other income (expense), net increased $15.1 million during 2019 as compared to 2018 primarily due to $10.3 million for the increase in the underlying trends impacting net losscash surrender value of certain trust-owned life insurance policies as a result of favorable market conditions at Cleco Holdings and $4.0 million of lower pension non-service costs at Cleco Power.
Interest Charges
Interest charges increased $14.7 million during 2019 as compared to 2018 primarily due to $9.3 million of interest associated with the exceptionfinancing of the Cleco Cajun Transaction and $3.2 million of interest associated with the private placement of senior notes entered into on September 11, 2019, at Cleco Holdings. For more information about the senior notes issued on September 11, 2019, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt — Cleco Debt.”
Income Taxes
Federal and state income tax expense increased $13.8 million during 2019 as compared to 2018 primarily due to the change in pretax 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.

income, excluding AFUDC equity. The effective income tax rate for the periodyear ended December 31, 2019, was 48.6%.

Cleco’s net loss attributable to22.0% which was different than the predecessor period January 1, 2016, through April 12, 2016, was $4.0 million. There were no significant changesfederal statutory rate. For more information about the difference 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 forand the period was (704.9%).

Cleco’s net income attributablefederal statutory rate, see “Financial Statements and Supplementary Data — Notes 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%.

Audited Financial Statements — Note 11 — Income Taxes — Cleco.”

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

Cleco Power

Significant Factors Affecting Cleco Power

Revenue is primarily affected by the following factors:

As an electric utility, Cleco Power is affected, to varying degrees, by a number of factors influencing the electric utility industry. These factors include, among others, an increasingly competitive business environment; the ability to recover costs through rate-setting proceedings; the ability to successfully perform in MISO and the related operating challenges; the cost of compliance with environmental and reliability regulations; conditions in the credit markets and global economy; changes in the federal and state regulation of generation, transmission, and the sale of electricity; the regulatory treatment of the TCJA, and the increasing uncertainty of future federal and state regulatory and environmental policies. For a discussion of various regulatory changes and competitive forces affecting Cleco Power and other electric utilities, see “Cautionary Note Regarding Forward-Looking“Forward-Looking Statements,” “Business—“Business — Regulatory Matters, Industry Developments, and Franchises,” and “—Financial Condition—Condition — Regulatory and Other Matters—Matters — Market Restructuring.” For a discussion of risk factors affecting Cleco Power’s business, see “Risk Factors— HedgingFactors.” For more information about the TCJA, see “— Financial Condition — Liquidity and Risk Management Activities,” “—Regulatory Compliance,” “—Transmission Constraints,” “—LPSC Audits,” “—Commodity Prices,” “—Global Economic EnvironmentCapital Resources — General Considerations and Uncertainty; Access to Capital,Credit-Related Risks — TCJA. “—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 is generally is measured in cooling degree-days and heating degree-days. A cooling degree-day is an indication of the likelihood that a consumer will use air conditioning, while a heating degree-day is an indication of the likelihood that a consumer will use heating. An increase in heating degree-days does not produce the same increase in revenue as an increase in cooling degree-days because alternative heating sources are more readily available, and energy used in the 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. ForCleco Power may experience increases in the retail industrial class Cleco Power expects new industrial loadin 2020, due to be added in 2017, principally driven by developmentschanges 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
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existing franchises and wholesale contracts as well as adding new wholesale customers and franchises. For more information on other expectations of future energy sales on Cleco Power, see “— Comparison of the Years Ended December 31, 2019, and 2018 — Base,” “Cautionary Note Regarding Forward-Looking“Forward-Looking Statements,” and “Risk Factors—Factors — Operational Risks — Future Electricity Sales.”

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

Impositionimposition of federal and/or state renewable portfolio standards;standards (“RPS”),

imposition of energy efficiency mandates,

legislative and regulatory changes,

increases in environmental regulations and compliance costs,

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

transmission congestion costs,

increaseincreases 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—“Business — Regulatory Matters, Industry Developments, and Franchises—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. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP, with anticipated new rates being effective July 1, 2020. The transmission tariffs of Cleco Power are regulated by FERC with its own regulatory proceedings. Both the LPSC and FERC regulatory proceedings can involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, all of whom have differing concerns but who have the common objective of limiting rate increases or reducing rates.

Other expenses are primarily affected by the following factors:

The majority of Cleco Power’s non-fuel cost recovery expenses consist of other operations, maintenance, depreciation and amortization, and taxes other than income taxes. Other operations expenses are affected by, among other things, the cost of employee benefits, insurance expense, and the costs associated with energy delivery and customer service. Annual maintenance expenses associated with Cleco Power’s plants generally depend upon their physical characteristics, maintenance practices, and the effectiveness of their preventive maintenance programs. Transmission and distribution maintenance expenses are generally affected by the level of repair and rehabilitation of lines to maintain reliability. Depreciation and amortization expense is primarily 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 lowerhigher in 20172020 as compared to 2016.2019. 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 miscellaneous expense, higher distribution maintenanceoperations expense, higher interest expense, higher generation operations expense, and higher amortizationadministration and general operations expense, partially offset by lower distribution maintenance expense.
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FOR THE YEAR ENDED DEC. 31,
 
 
 
FAVORABLE / (UNFAVORABLE)
(THOUSANDS)
2019
2018
VARIANCE
CHANGE
Operating revenue
 
 
 
 
Base
$669,091
$678,378
$(9,287)
(1.4)%
Fuel cost recovery
461,837
513,209
(51,372)
(10.0)%
Electric customer credits
(38,516)
(33,195)
(5,321)
(16.0)%
Other operations
72,833
82,330
(9,497)
(11.5)%
Affiliate revenue
3,125
874
2,251
257.6%
Operating revenue, net
1,168,370
1,241,596
(73,226)
(5.9)%
Operating expenses
 
 
 
 
Recoverable fuel and purchased power
461,877
513,206
51,329
10.0%
Non-recoverable fuel and purchased power
34,648
37,530
2,882
7.7%
Other operations and maintenance
207,164
202,552
(4,612)
(2.3)%
Depreciation and amortization
172,471
162,069
(10,402)
(6.4)%
Taxes other than income taxes
43,742
47,267
3,525
7.5%
Total operating expenses
919,902
962,624
42,722
4.4%
Operating income
248,468
278,972
(30,504)
(10.9)%
Interest income
4,744
5,052
(308)
(6.1)%
Allowance for equity funds used during construction
15,397
14,159
1,238
8.7%
Other expense, net
(3,616)
(8,699)
5,083
58.4%
Interest charges
71,279
71,303
24
%
Federal and state income tax expense
45,452
55,924
10,472
18.7%
Net income
$148,262
$162,257
$(13,995)
(8.6)%
The following table shows the components of debt issuance costs.

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 comparedretail and wholesale customer sales related to 2015. Contributing factors include:

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

The following tables showtable shows 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)% 
  

 

 

   

 

 

   

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
FAVORABLE /
(UNFAVORABLE)
Electric sales
 
 
 
Residential
$297,204
$304,708
(2.5)%
Commercial
198,664
192,781
3.1%
Industrial
84,030
90,291
(6.9)%
Other retail
10,786
10,918
(1.2)%
Storm surcharge
22,132
23,138
(4.3)%
Total retail
612,816
621,836
(1.5)%
Sales for resale
56,275
56,542
(0.5)%
Total base revenue
$669,091
$678,378
(1.4)%
The following chart shows how cooling and heating degree-days varied from normal conditions and from the prior period. Cleco Power uses weather data provided by NOAAthe National Oceanic and Atmospheric Administration (“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)% 

 
FOR THE YEAR ENDED DEC. 31,
 
 
 
 
2019 CHANGE
 
2019
2018
NORMAL
PRIOR YEAR
NORMAL
Cooling degree-days
3,178
3,311
2,779
(4.0)%
14.4%
Heating degree-days
1,325
1,470
1,547
(9.9)%
(14.4)%
Significant factors affecting Cleco Power’s net income during the year ended December 31, 2019, are described below.
Base

Base revenue decreased $9.6$9.3 million in 20162019 as compared to 20152018 primarily due to $6.4$6.8 million of milder weather and $2.5 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.rates. For more information on other

expectationsthe effects of future energy sales on the results of operations, financial condition, or cash flows of Cleco Power, see “—Significant Factors Affecting Cleco Power,” “Cautionary Note Regarding Forward-Looking“Forward-Looking Statements,” and “Risk Factors—Factors — Operational Risks — Future Electricity Sales.”

Fuel Cost Recovery/Recoverable Fuel and Purchased Power Purchased

Changes in fuel

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%76% of Cleco Power’s total fuel costscost during 20162019 was regulated by the LPSC. Recovery of FAC costs is subject to periodic fuel audits by the LPSC which may result in a refund to customers. Generally, fuel and purchased power expenses are impacted by customer usage, the per unit cost of fuel used for electric generation, and the dispatch of Cleco Power’s generating facilities by MISO. Fuel and purchased power expenses may also be impacted by the interruption of the continuous supply of lignite due to adverse weather conditions and other factors that disrupt mining operations and transportation to Dolet Hills Power Station. For more information on the accounting for MISO transactions, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 2—2 — Summary of Significant Accounting Policies—Policies — Accounting for MISO Transactions.” For more information on Cleco Power’s most current fuel audit, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 15—15 — Litigation, Other Commitments and Contingencies, and DisclosureDisclosures about Guarantees—Litigation—Guarantees — Litigation — LPSC Audits—Audits — Fuel Audit.”

Other Operations Revenue

Other operations revenue

Electric Customer Credits
Electric customer credits increased $1.5$5.3 million in 20162019 as compared to 20152018 primarily related to $3.4 million for the estimated refunds due to $2.8 million of higherCleco Power’s wholesale 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 2016customers as a result of the MergerFERC audit and $0.2$2.3 million of higher estimated FRP refunds. For more information on the FERC audit, see “Financial
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Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — FRP,” “Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — FERC Audit.”
Other Operations Revenue
Other operations revenue decreased $9.5 million in 2019 as compared to 2018 primarily related to $6.8 million of lower miscellaneous revenue.

Non-recoverablenet generation revenue as a result of the Teche Unit 3 SSR ending in April 2019 and $2.1 million of lower reconnect fees. For more information on the SSR, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR.”

Non-Recoverable Fuel and Purchased Power Purchased

Non-recoverable fuel and purchased power purchased increased $4.3decreased $2.9 million in 20162019 as compared to 20152018 primarily due to lower MISO transmission costs as a result of the Teche Unit 3 SSR ending in April 2019.
Other Operations and Maintenance Expense
Other operations and maintenance expense increased $4.6 million during 2019 as compared to 2018 primarily related to $3.1$6.9 million of higher outside service 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$6.4 million of higher generation expenseoperations expenses, and $1.1$4.1 million of higher customer service expenseexpenses, partially offset by $13.0 million of lower generating station outage maintenance expenses.

Depreciation and Amortization
Depreciation and amortization increased $10.4 million during 2019 as compared to 2018 primarily related to 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$4.0 million of higher deferrals of production operations and maintenance expenses to a regulatory asset, $1.3 million of higherlower deferrals of corporate franchise taxes to a regulatory asset, and $0.5$3.8 million of lower amortization of the corporate franchise taxes regulatory asset. These decreases were partially offset by $3.1 million ofhigher normal recurring additions to fixed assets, $1.6and $2.7 million of higher amortization of intangible property due to the production operations and maintenance regulatory asset, $0.8 millioninstallation of higher amortization of storm damages which is based on collections from customers, and $0.1 million of miscellaneous amortizations.

a new enterprise business applications suite.

Taxes Other thanThan Income Taxes

Taxes other than income taxes increased $1.2decreased $3.5 million in 20162019 as compared to 20152018 primarily duerelated to higher propertylower corporate franchise taxes.

Merger Commitment Costs

Merger commitment costs increased $151.5

Other Expense, Net
Other expense, net decreased $5.1 million in 2016during 2019 as compared to 2015 due2018 primarily related to $136.0$4.0 million of customer rate credits, a $7.0lower pension non-service costs and $0.6 million one-time contribution for economic developmentthe change in Cleco Power’s service territory to be administered by the LED, a $6.0 million accrualcash surrender value 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.

life insurance policies.

Income Taxes

Federal and state income taxes decreased $60.9$10.5 million in 2016during 2019 as compared to 2015. Tax expense decreased2018 primarily due to $64.5$6.2 million for the change in pretax income, excluding AFUDC equity, and $2.3$3.2 million for adjustments forflowthrough of state tax benefits, and $2.5 million of adjustment to tax returns as filed. These decreases were partially offset by $4.5$1.4 million of miscellaneous tax items. The effective income tax rate for the year ended December 31, 2019, was 23.5% which was different than the federal statutory rate. For more information about the difference in the effective income tax rate and the federal statutory rate, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 11 — Income Taxes — Cleco Power.”
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Cleco Cajun
(THOUSANDS)
FOR THE
YEAR ENDED
DEC. 31, 2019
Operating revenue
Electric operations
$375,489
Electric customer credits
(1,447)
Other operations
117,468
Affiliate revenue
108
Operating revenue, net
491,618
Operating expenses
Fuel used for electric generation
81,514
Purchased power
177,254
Other operations and maintenance
91,215
Depreciation and amortization
35,544
Taxes other than income taxes
14,785
Total operating expenses
400,312
Operating income
91,306
Interest income
987
Other expense, net
(368)
Interest charges
35
Federal and state income tax expense
22,479
Net income
$69,411
Significant factors affecting Cleco Cajun’s net income from the closing of the Cleco Cajun Transaction on February 4, 2019, through December 31, 2019, are described below.
Operating Revenue
Operating revenue, net of $491.6 million during 2019 primarily consisted of $375.5 million of electric operations revenue from wholesale customers, $57.1 million of lease revenue, including variable lease revenue, as a result of the Cottonwood Sale Leaseback, and $47.9 million of transmission revenue from wholesale customers. For more information on the Cottonwood Sale Leaseback agreement, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases Lessor Agreements — Cottonwood Sale Leaseback Agreement.”
Operating Expense
Operating expenses of $400.3 million during 2019 primarily consisted of $120.5 million of purchased power from MISO, $81.5 million of fuel expenses for generation, $50.3 million of MISO transmission costs, $34.9 million of depreciation on fixed assets, $29.2 million of general and administrative expense, $27.5 million for generating station operations expenses, and $26.5 million of routine generating station maintenance expenses.
Income Taxes
Federal and state income taxes of $22.5 million during 2019 primarily included $19.3 million of tax expense on pretax income at the statutory tax rate and $2.7 million for state taxes. The effective income tax rate for 2019 was 24.5%. The estimated annual effective income tax rate used for 2019 for Cleco Cajun may not be indicative of the full-year income tax rate.
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Comparison of the Years Ended December 31, 2018, and 2017
Cleco
 
 
FOR THE YEAR ENDED DEC. 31,
 
 
FAVORABLE / (UNFAVORABLE)
(THOUSANDS)
2018
2017
VARIANCE
CHANGE
Operating revenue, net
$1,231,044
$1,175,646
$55,398
4.7%
Operating expenses
986,487
910,419
76,068
8.4%
Operating income
$244,557
265,227
(20,670)
(7.8)%
Interest income
6,073
1,424
4,649
326.5%
Allowance for equity funds used during construction
14,159
8,320
5,839
70.2%
Other expense, net
(14,328)
(6,899)
(7,429)
(107.7)%
Interest charges
126,642
122,913
3,729
3.0%
Federal and state income tax expense
29,382
7,079
22,303
315.1%
Net income
$94,437
$138,080
$(43,643)
(31.6)%
Operating revenue, net increased $55.4 million during 2018 as compared to the 2017 primarily due to $56.6 million of higher fuel cost recovery revenue at Cleco Power, and $27.7 million higher base revenue at Cleco Power, partially offset by $31.6 million of higher electric customer credits at Cleco Power.
Operating expenses increased $76.1 million during 2018 as compared to 2017 primarily due to $56.7 million of higher recoverable fuel and power purchased expenses at Cleco Power and $14.4 million of expenses associated with the Cleco Cajun Transaction at Cleco Holdings.
Interest income increased $4.6 million during 2018 as compared to 2017 primarily due to $2.7 million of higher interest rates and balances on temporary investments and $1.2 million of interest on a note receivable at Cleco Power.
Allowance for equity funds used during construction increased $5.8 million during 2018 as compared to 2017 primarily due to higher construction costs related to various projects.
Other expense, net increased $7.4 million during 2018 as compared to 2017 primarily due to $6.4 million of change in value of life insurance policies as a result of unfavorable market conditions at Cleco Holdings.
Federal and state income tax expense increased $22.3 million during 2018 as compared to 2017 primarily due to $46.3 million for the absence of adjustments related to the TCJA and $3.7 million for the flowthrough of state tax benefits, $0.9 million for tax credits, $0.3 million for miscellaneous tax items, and $0.2 million for adjustments for permanent tax differences.benefits. 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)% 

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$15.2 million for the absence of favorable settlements with taxing authorities, $2.5 million forreduction in the flowthrough of statefederal statutory tax benefits, $1.1 million for miscellaneous tax items,rate as prescribed by the TCJA and $0.8 million for adjustments for tax returns filed. These increases were partially offset by $3.1$10.5 million for the change in pretax income, excluding AFUDCAFDUC equity. The effective income tax rate for the year ended December 31, 2018, was 36.8%, which is higher than23.7%. For more information on 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,TCJA, see “Financial Statements 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 dueSupplementary Data — Notes to the absence of favorable settlements with taxing authorities, tax returns as filed,Audited Financial Statements — Note 13 — Regulation and the flowthrough of state tax benefits, partially offset by the change in pretax income, excluding AFUDC equity.Rates — TCJA.”

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

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
 
FOR THE YEAR ENDED DEC. 31,
 
 
FAVORABLE / (UNFAVORABLE)
(THOUSANDS)
2018
2017
VARIANCE
CHANGE
Operating revenue
 
 
 
 
Base
$678,378
$651,732
$26,646
4.1%
Fuel cost recovery
513,209
456,657
56,552
12.4%
Electric customer credits
(33,195)
(1,566)
(31,629)
*
Other operations
82,330
77,522
4,808
6.2%
Affiliate revenue
874
851
23
2.7%
Operating revenue, net
$1,241,596
$1,185,196
$56,400
4.8%
Operating expenses
 
 
 
 
Recoverable fuel and purchased power
513,206
456,509
(56,697)
(12.4)%
Non-recoverable fuel and purchased power
37,530
35,750
(1,780)
(5.0)%
Other operations and maintenance
202,552
202,738
186
0.1%
Depreciation and amortization
162,069
158,415
(3,654)
(2.3)%
Taxes other than income taxes
47,267
46,539
(728)
(1.6)%
Total operating expenses
962,624
899,951
(62,673)
(7.0)%
Operating income
$278,972
$285,245
$(6,273)
(2.2)%
Allowance for equity funds used during construction
$14,159
$8,320
$5,839
70.2%
Interest charges
$71,303
$69,362
$(1,941)
(2.8)%
Federal and state income tax expense
$55,924
$67,331
$11,407
16.9%
Net income
$162,257
$150,738
$11,519
7.6%
*
Not Meaningful
Cleco Power’s net income for 2015 decreased $13.02018 increased $11.5 million compared to 2014. Contributing factors include:

2017 primarily as a result of the following factors:
lowerhigher base revenue,

lower federal and state income tax expense,
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,
higher other operations revenue, and

higher interest income.
These increases were partially offset by:
higher electric customer credits,
higher depreciation and amortization, and
higher interest charges.
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These were partially offset by lower electric

The following table shows the components of Cleco Power’s retail and wholesale 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)% 
  

 

 

   

 

 

   

sales related to base revenue:

 
FOR THE YEAR ENDED DEC. 31,
 
(MILLION kWh)
2018
2017
FAVORABLE/
(UNFAVORABLE)
Electric sales
 
 
 
Residential
3,780
3,526
7.2%
Commercial
2,731
2,650
3.1%
Industrial
2,243
2,078
7.9%
Other retail
133
131
1.5%
Total retail
8,887
8,385
6.0%
Sales for resale
2,991
2,959
1.1%
Total retail and wholesale customer sales
11,878
11,344
4.7%
The following table shows the components of Cleco Power’s base revenue:
 
FOR THE YEAR ENDED DEC. 31,
 
(THOUSANDS)
2018
2017
FAVORABLE/
(UNFAVORABLE)
Electric sales
 
 
 
Residential
$304,708
$286,587
6.3%
Commercial
192,781
188,431
2.3%
Industrial
90,291
87,528
3.2%
Other retail
10,918
10,592
3.1%
Surcharge
23,138
20,965
10.4%
Total retail
621,836
594,103
4.7%
Sales for resale
56,542
57,629
(1.9)%
Total base revenue
$678,378
$651,732
4.1%
The following chart shows how cooling and heating degree-days varied from normal conditions and from the prior period. Cleco Power uses weather data provided by NOAA to determine cooling and heating degree-days.

   FOR THE YEAR ENDED DEC. 31, 
               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)% 

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

Base revenue decreased $13.0increased $26.6 million in 20152018 as compared to 20142017 primarily due to lower net sales$22.6 million of higher usage from warmer summer weather and colder winter weather and $4.1 million due 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.

rates.

Fuel Cost Recovery/Recoverable Fuel and Purchased 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 74%76% of Cleco Power’s total fuel cost during 20152018 was regulated by the LPSC. Recovery of FAC costs is subject to periodic fuel audits by the LPSC which may result in a refund to customers. Generally, fuel and purchased power expenses are impacted by customer usage, the per unit cost of fuel used for electric generation, and the dispatch of Cleco Power’s generating facilities by MISO. Fuel and purchased power expenses were also impacted by the interruption of the continuous supply of lignite due to adverse weather conditions and other factors that disrupted mining operations and transportation to Dolet Hills Power Station. For more information on the accounting for MISO transactions, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 2—2 — Summary of Significant Accounting Policies—Policies — Accounting for MISO Transactions.” For more information on

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

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

Other operations revenue increased $2.2$4.8 million in 20152018 as compared to 20142017 primarily due to $3.5$2.3 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 millionfrom wholesale customers due to the absence of a gain associated with the extinguishment of2017 customer credits relating to 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 $4.5MISO ROE complaints, $1.6 million of higher MISOnet transmission expenses and administrative feesdistribution revenue, and $0.1$0.2 million of higher miscellaneous expenses,generation revenue from the Teche Unit 3 SSR. The $0.2 million of Teche Unit 3 SSR revenue consisted of $1.8 million higher revenue, partially offset by $0.6$1.6 million of lower capacity chargesexpected refunds to MISO as a result of the SSR settlement agreement. For more information on the SSR, see “Financial Statements and $0.6 million for a one-time facility credit.

Supplementary Data — Notes to the Audited Financial Statements — Note 13 — Regulation and Rates — SSR.”

Other Operations and Maintenance Expense

Other operations and maintenance expense increased $12.0decreased $0.2 million in 20152018 as compared to 20142017 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$7.6 million of lowerhigher deferrals of production operations and maintenance expenses to a regulatory asset, $3.9$7.5 million of lower compensation expense, and the absence of $1.9 million for the write-off of an uncollectible account. These decreases were partially offset by $5.6 million of higher fees for outside services, $3.4 million of higher employee benefits expenses, $2.9 million of higher net generating station outage and routine maintenance expenses, $2.8 million of higher customer service expenses, $1.7 million of higher distribution operations expenses, and $1.5 million of higher generation operations expenses.

Depreciation and Amortization
Depreciation and amortization expense increased $3.7 million in 2018 as compared to 2017 primarily due to $4.2 million of normal recurring additions to fixed assets and $3.2$3.8 million for theof higher amortization of regulatory assets

related to the FRP extension. The increase was also due to $1.9storm damages which is based on collections from customers. These increases were partially offset by $2.7 million of amortization related to a regulatory asset for statehigher deferrals of corporate franchise taxes $1.2 million for the absence of the deferral of AMI revenue requirements to a regulatory asset and $1.1$1.4 million of lower amortization of the production operations and maintenance regulatory asset.

Interest Income
Interest income increased $3.8 million in 2018 as compared to 2017 primarily due to $1.7 million of higher miscellaneous amortization. These amounts were partially offset by $13.5interest rates and balances on temporary investments and $1.2 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.

interest on a note receivable.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction decreased $2.3increased $5.8 million in 20152018 as compared to 20142017 primarily due to lowerhigher construction costs related to the completion ofSt. Mary Clean Energy Center project, the MATSCoughlin Pipeline project, the START project, the Terrebonne to Bayou Vista Transmission project, and the Bayou Vista to Segura Transmission project.

Interest Charges

Interest charges increased $1.9 million in 20152018 as compared to 20142017 primarily due to $5.0$4.9 million related to the absence of favorable settlements with taxing authoritiesinterest on senior notes issued in December 2017 and $0.7March 2018. This increase was partially offset by $2.4 million related to lowerof higher 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$1.0 million of lower miscellaneous interest charges.on Cleco Katrina/Rita storm recovery bonds.
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Income Taxes

Federal and state income taxes increased $2.3decreased $11.4 million in 20152018 as compared to 2014.2017. Tax expense increaseddecreased primarily due to $2.5$26.9 million forrelated to the flowthrough of statereduction in the federal statutory tax benefits,rate as prescribed by the TCJA, $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.equity, and $1.3 million for adjustments for permanent tax differences. These decreases were partially offset by $14.3 million for the absence of adjustments related to the TCJA and $3.7 million for the flowthrough of state tax benefits. The effective income tax rate was 35.9%is 25.6%, which is higherdifferent 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 ofmore information on the results of operations explainingTCJA, see “Financial Statements and Supplementary Data — Notes to 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’sAudited Financial Statements — Note 11 — Income Taxes — TCJA,” “Note 13Regulation and the Notes contained in this prospectus.

Rates — TCJA.”

CRITICAL ACCOUNTING POLICIES

Cleco’s critical accounting policies include accounting policies that are important to Cleco’s financial condition and results of operations and that require management to make difficult, subjective, or complex judgments about future events, which could result in a material impact to the financial statements of Cleco. The

preparation of financial statements contained in this report requires management to make estimates and assumptions. Estimates and assumptions about future events and their effects cannot be made with certainty. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. On an ongoing basis, these estimates and assumptions are evaluated and, if necessary, adjustments are made when warranted by new or updated information or by a change in circumstances or environment. Actual results may differ significantly from these estimates under different assumptions or conditions. For more information on Cleco’s accounting policies, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 2—2 — Summary of Significant Accounting Policies” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies.”

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

To determine assets, liabilities, and expenses relating to pension and other postretirement benefits, management must make assumptions about future trends. Assumptions and estimates include, but are not limited to, discount rates, expected return on plan assets, mortality rates, future rate of compensation increases, and medical inflation trend rates. These assumptions are reviewed and updated on an annual basis. Changes in the rates from year-to-year and newly-enacted laws could have a material effect on Cleco’s financial condition and results of operations by changing the recorded assets, liabilities, expense, or required funding of the pension plan obligation. One component of pension expense is the expected return on plan assets. It is an assumed percentage return on the market-related value of plan assets. The market-related value of plan assets differs from the fair value of plan assets by the amount of deferred asset gains or losses. Actual asset returns that differ from the expected return on plan assets are deferred and recognized in the market-related value of assets on a straight-line basis over a five-year period. The 20162019 return on plan assets was 10.90%22.17% compared to an expected long-term return of 6.21%6.55%. For 2015,2018, the return on plan assets was (2.90)had a negative return of (7.31)% compared to an expected long-term return of 6.15%5.86%. For the calculation of the 20172020 periodic expense, Cleco decreased the expected long-term return on plan assets to 6.08%5.91%.

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 inAs a decrease to the discount rate from 4.62% to 4.21%. Afterresult of the annual review of assumptions, the pension plan discount rate increaseddecreased from 4.21%4.35% to 4.27%3.43% for the December 31, 2016,2019, measurement of liabilities.

A change in the assumed discount rate creates a deferred actuarial gain or loss. Generally, when the assumed discount rate decreases compared to the prior measurement date, a deferred actuarial loss is created. When the assumed discount rate increases compared to the prior measurement date, a deferred actuarial gain is created. Actuarial gains and losses also are created when actual results, such as compensation increases, differ from assumptions. Historically, Cleco Power has been allowed to recover pension plan expenses; therefore, deferred actuarial gains and losses are recorded as a regulatory asset or liability. The net of the deferred gains and losses is amortized to pension expense over the average service life of the remaining plan participants (approximately 10eight years as of December 31, 2016,2019, for Cleco’s plan) when it exceeds certain thresholds. This approach of
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amortizing gains and losses has the effect of reducing the volatility of pension expense. Over time, it is not expected to reduce or increase the pension expense relative to an approach that immediately recognizes losses and gains.

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.

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 

ACTUARIAL ASSUMPTION
(THOUSANDS)
CHANGE IN
ASSUMPTION
CHANGE IN
PROJECTED BENEFIT
OBLIGATION
CHANGE IN
ESTIMATED BENEFIT
COST
Discount rate
0.5% increase
$(41,744)
$(4,323)
 
0.5% decrease
$46,870
$4,775
Salary scale
0.5% increase
$8,428
$1,669
 
0.5% decrease
$(7,650)
$(1,510)
Expected return on assets
0.5% increase
$
$(2,113)
 
0.5% decrease
$
$2,113
Cleco Power made a $12.3 million discretionary contribution to the pension plan in 2019. Cleco Power did not make any required or discretionary contributions to the pension plan in 2016, 2015,2018 or 2014.2017. Based on current funding assumptions at December 31, 2019, management estimates that $44.0$66.5 million in pension contributions will be required through 2021.2024. Cleco expects to make $83.0 million in discretionary contributions during 2020, which would reduce the future required contributions. Future discretionary contributions may be made depending on changes in assumptions, the ability to utilize the contribution as a tax deduction, and requirements concerning recognizing a minimum pension liability. Future required contributions are driven by liability funding target percentages set by law which could cause the required contributions to change from year to year.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—Data — Notes to the Audited Financial Statements—Statements — Note 9—10 — Pension Plan and Employee Benefits” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 9 — Pension Plan and Employee Benefits.

Cleco has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. At DecemberMarch 31, 2016,2020, Cleco Power had $544.0$144.7 million in regulatory assets.assets, net. As a result of the 2016 Merger, Cleco Holdings recognized regulatory assets. At DecemberMarch 31, 2016,2020, Cleco Holdings had $195.7$155.4 million of regulatory assets. Actions by the LPSC could limit the recovery of Cleco’s regulatory assets, causing Cleco to record a loss on some or all of the regulatory assets. If future recovery of costs ceases to be probable, Cleco Holdings could be required to record a loss of its regulatory assets associated with acquisition adjustments. For more information on the LPSC and regulatory assets, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 2—2 — Summary of Significant Accounting Policies—Policies — Regulation,” “Note 6 — Regulatory Assets and “Note 4—Liabilities,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 6 — Regulatory Assets and Liabilities.

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

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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—Supplementary Data — Notes to the Audited Financial Statements—Statements — Note 10—11 — Income Taxes” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 10 — Income Taxes.”

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

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

Cleco Power

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

The LPSC determines the ability of Cleco Power to recover prudent costs incurred in developing long-lived assets. If the LPSC were to rule that the cost of current or future long-lived assets was imprudent and not recoverable, Cleco Power could be required to write down the imprudent cost and incur a corresponding impairment loss. At December March��31, 2016,2020, the carrying value of Cleco Power’s long-lived assets was $3.17$3.60 billion. Currently, Cleco Power has concluded that none of its long-lived assets are impaired.

The LPSC determines the amount and type of fuel and purchased power expenses that Cleco Power can charge customers through the FAC. Changes in the determination of allowable costs already incurred by Cleco Power could cause material changes in fuel revenue. Cleco Power currently has FAC filings for 2016January 2018 and thereafter that are subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. For more information on LPSC fuel audits, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 15—15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees —Litigation—— Litigation — LPSC Audits” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits.” For information on fuel revenue, see “—Results of Operations—Operations — Comparison of the Years Ended December 31, 2016,2019, and 2015—2018 — Cleco Power—Power — Significant Factors Affecting Cleco Power’s Results of Operations—Power — Fuel Cost Recovery/Recoverable Fuel and Power Purchased.Purchased” and “— Results of Operations — Comparison of the Three Months Ended March 31, 2020, and 2019 — Cleco Power — Fuel Cost Recovery/Recoverable Fuel and Purchased Power.
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FINANCIAL CONDITION

Liquidity and Capital Resources

General Considerations and Credit-Related Risks

Credit Ratings and Counterparties

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short- and long-term financing. The inability to raise capital on favorable terms could negatively affect Cleco’s ability to maintain or expand its businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, including the impact of COVID-19, regulatory authorizations and policies, Cleco Holdings’ and Cleco Power’s credit ratings, cash flows from routine operations, and credit ratings of project counterparties. After assessing the current operating performance, liquidity, and credit ratings of Cleco Holdings and Cleco Power, management believes that Cleco will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. The following table presents the credit ratings of Cleco Holdings and Cleco Power at DecemberMarch 31, 2016:

2020:
SENIOR UNSECURED DEBT
CORPORATE/LONG-TERM ISSUER
SENIOR
UNSECURED DEBT
S&P
CORPORATE
CREDIT
MOODY’S
FITCH
S&P
MOODY’S
FITCH
Cleco Holdings
MOODY’S
BBB-
S&PS&P
Baa3
BBB-
BBB-
Baa3
BBB-

Cleco Holdings

Baa3N/ABBB-

Cleco Power

A3
BBB+
BBB+
A3
BBB+
BBB+
A3
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

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 HoldingsHoldings’ or Cleco Power’s credit ratings were to be downgraded, by Moody’s or S&P, Cleco Holdings and/or Cleco Power, wouldrespectively, could 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 positionscontracts that Cleco Powerhas or 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,contract, changes in the market price, of power and natural gas, changes in open power and gas positions,contracts, and changes in the amount counterparties owe Cleco Power.Cleco. Changes in any of these factors could cause the amount of requested credit support to increase or decrease.

Cleco Power participatesand Cleco Cajun participate 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.market. MISO requires Cleco Power and Cleco Cajun to provide credit support which may increase or decrease due to the timing of the settlement schedules. 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—Matters — Transmission Rates of Cleco Power.Rates.

For more information about credit support, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees.”

Global and U.S.United States Economic Environment

Global and domestic economic conditions may have an impact on Cleco’s business and financial condition. Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows. During periods of capital market volatility, the availability of capital could be limited and the costs of capital may increase for many companies. Although the CompanyCleco has not experienced restrictions in the financial markets, itstheir ability to access the capital markets may be restricted at a time when the CompanyCleco would like, or need, to do so. Any restrictions could have a material impact on the Company’sCleco’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’sCleco’s lenders or customers, causing them to fail to meet their obligations to the CompanyCleco or to delay payment of such obligations. The lower interest rates to which the CompanyCleco has been exposed have been beneficial to debt issuances; however, these rates have negatively affected interest income for the Company’sCleco’s short-term investments.
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TCJA
The provisions of the TCJA reduced the top federal statutory corporate income tax rate from 35% to 21%. As a result of the tax rate reduction, on January 1, 2018, Cleco Power began accruing an estimated reduction in reserve for the federal statutory corporate income tax rate. In February 2018, the LPSC directed utilities, including Cleco Power, to provide considerations of the appropriate manner to flowthrough to ratepayers the benefits of the reduction in corporate income taxes as a result of the TCJA. After various filings and settlement discussions, on July 10, 2019, the LPSC approved for Cleco Power to accrue rate refunds totaling $79.2 million, plus interest, for the reduction in the statutory federal tax rate for the period from January 2018 to June 2020. The refund is being credited to customers over 12 months beginning August 1, 2019. At March 31, 2020, Cleco Power had $19.7 million accrued for the estimated tax-related benefits from the TCJA and $1.6 million accrued for the related interest.
Also, on July 10, 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT resulting from the enactment of the TCJA in Cleco Power’s application for its next FRP, which was filed on June 28, 2019, with anticipated new rates being effective July 1, 2020. At March 31, 2020, Cleco Power had a regulatory liability of $375.0 million for the portion of the net reduction to ADIT subject to regulatory treatment. Due to the uncertainty around the regulatory treatment, the entire regulatory liability is reflected in non-current liabilities.
Fair Value Measurements

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values. Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance. Cleco and Cleco Power are required to disclose the fair value of certain assets and liabilities by one of three levels. Other financial assets and liabilities 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—Data — Notes to the Audited Financial Statements—Statements — Note 6—8 — Fair Value Accounting” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 7 — Fair Value Accounting.”

Cash Generation and Cash Requirements

Restricted Cash and Cash Equivalents

Various agreements to which Cleco is subject contain covenants that restrict its use of cash. As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for its intended purposes and/or general companycorporate purposes. For more information on 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 
  

 

 

   

 

 

 

see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Restricted Cash and Cash Equivalents” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies – Restricted Cash and Cash Equivalents.”

Debt
Cleco
At March 31, 2020, Cleco 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 $6.0had $238.0 million of charitable contributions to be disbursed over five years and $136.0short-term debt outstanding under its $475.0 million credit facilities, at an average all-in interest rate 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

2.11%. Cleco had no short-term debt outstanding at December 31, 2016, or 2015.

2019.

At DecemberMarch 31, 2016,2020, Cleco’s long-term debt and finance leases outstanding was $2.76$3.18 billion, of which $19.7$63.9 million was due within one year. The long-term debt due within one year at DecemberMarch 31, 2016,2020, primarily represents $17.9$63.3 million of principal payments foron Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC. Long-term debt decreased by $13.5 million from December 31, 2019, primarily due to the $11.1 million final principal payment made on the Cleco Katrina/Rita storm recovery bonds on March 2, 2020. For more information on Cleco’s debt, see “Financial Statements and $1.8 million of capital lease payments.

In connection withSupplementary Data — Notes to the completion ofAudited Financial Statements — Note 9 — Debt” and “Financial Statements and Supplementary Data — Notes to 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.Unaudited Interim Financial Statements — Note 8 — Debt.”

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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.

Cash and cash equivalents available at DecemberMarch 31, 2016,2020, were $23.1$350.2 million combined with $400.0$237.0 million available credit facility capacity ($100.087.0 million from Cleco Holdings and $300.0$150.0 million from Cleco Power) for total liquidity of $423.1$587.2 million.

For more information on the credit facility capacity, see “— Credit Facilities.” Cleco Holdings and Cleco Power have uncommitted lines of credit that allow up to $10.0 million each in short-term borrowings, but no more than $10.0 million in the aggregate, to support their working capital needs.

At DecemberMarch 31, 2016,2020, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents. In order to mitigate potential credit risk, Cleco and Cleco Power have established guidelines for short-term investments. For more information on the concentration of credit risk through short-term investments classified as cash equivalents, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 6—8 — Fair Value Accounting” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 7 — Fair Value Accounting.”

For the successor period

At March 31, 2020, and December 31, 2016,2019, 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$184.1 million and $126.7 million, respectively. The $57.4 million increase in provisions for the Merger Commitments, working capital is primarily due to:
a $13.9$233.9 million increase in restricted cash and cash equivalents, primarily due to the funding of customer rate credits as draws on Cleco’s credit facilities,
a result of the Merger Commitments, and a $8.5$62.1 million regulatory asset related to fair value adjustments ofdecrease in long-term debt as a resultdue within one year primarily due to the long-term refinancing 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$50.0 million for the difference between the carrying value2008 series A GO Zone bonds and the fair value$11.1 million final principal payment on the Cleco Katrina/Rita storm recovery bonds on March 2, 2020,

a $50.6 million decrease in accounts payable, excluding FTR purchases, primarily due to the short-term incentive plan payments in March 2020, the timing of long-term debt recorded as property tax payments, lower accruals for fuel costs, and lower MISO power purchases and load charges, and
a result of the Merger, and a $14.4$26.2 million increase in fuel inventory primarily due to higher purchases of coal and higher deliveries of lignite at Cleco Power.
These increases in working capital were partially offset by:
a $238.0 million increase in short-term debt due to draws on Cleco’s $475.0 million credit facilities,
a $22.7 million increase in accrued interest primarily due to the timing of interest payments on long-term debt,
a $15.0 million increase in taxes payable primarily due to accruals of property taxes and higher provisions for income taxes,
an $11.8 million decrease in customer accounts receivable primarily due to a decrease in customer usage, a decrease in fuel surcharges, the Merger Commitments.

Fortiming of customer collections, and the predecessor period December 31, 2015, Cleco’s Consolidated Balance Sheets reflected $2.65 billionabsence of total liabilities. There were no significantthe Cleco Katrina/Rita storm restoration surcharge,

a $10.7 million decrease in cash surrender value of life insurance policies primarily due to market changes,
a $7.0 million decrease in restricted cash and cash equivalents, and
a $6.9 million decrease in accumulated deferred fuel, excluding Cleco Power FTRs, primarily due to the underlying trends impacting total liabilities for the predecessor period.

timing of collections.

Cleco Holdings (Holding Company Level)

Cleco Holdings had no short-term debt outstanding at December 31, 2016,2019, or 2015.

2018.

At December 31, 2016, Cleco Holding’s2019, Cleco’s long-term debt and finance leases outstanding was $1.34$3.19 billion, of which none$126.0 million was due within one year.

In connection with The long-term debt due within one year at December 31, 2019, primarily represents $63.3 million of principal payments on Cleco Holdings’ debt as required by the completionCleco Cajun Transaction commitments to the LPSC, $50.0 million 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 FacilityGO Zone bonds with a seriesmandatory tender in May 2020, and $11.0 million of other long-term financings described below.

On May 17, 2016,principal payments for the Cleco Holdings completedKatrina/Rita storm recovery bonds. Long-term debt increased by $295.1 million from December 31, 2018, primarily due to the private saleplacement of $535.0$300.0 million aggregate principal amount of 3.743% senior notes due May 1, 2026,on September 11, 2019, and $350.0$30.0 million of 4.973% senior notes due May 1, 2046. On May 24, 2016, Cleco Holdings completedbalance remaining on the private sale of $165.0$100.0 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 costsentered into on February 4, 2019, in connection with the repayment ofCleco Cajun Transaction.

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These increases were partially offset by $20.6 million for scheduled payments made on the Acquisition Loan Facility.

On April 13, 2016, in connectionCleco Katrina/Rita storm recovery bonds. For more information on Cleco’s debt, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt.”

Cash and cash equivalents available at December 31, 2019, were $116.3 million combined with the completion of the Merger,$475.0 million available credit facility capacity ($175.0 million from Cleco Holdings replaced its existing $250.0and $300.0 million from Cleco Power) for total liquidity of $591.3 million. For more information on the 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.

capacity, see “— Credit Facilities.” 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 the aggregate, to support their working capital needs.

At December 31, 2019, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents. In order to mitigate potential credit risk, Cleco and Cleco Power have established guidelines for short-term investments. For more information on the concentration of credit risk through short-term investments classified as cash equivalents, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 8 — Fair Value Accounting.”
At December 31, 2019, and 2018, Cleco had a working capital surplus of $126.7 million and $185.9 million, respectively. The $59.2 million decrease in working capital is primarily due to:
a $104.9 million increase in long-term debt due within one year primarily due to $63.3 million of principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC, $50.0 million of GO Zone bonds with a mandatory tender in May 2020, partially offset by $9.5 million of lower principal payments for the Cleco Katrina/Rita storm recovery bonds due to the bonds maturing in March 2020,
a $33.8 million increase in affiliate accounts payable primarily for amounts due to Cleco Group for affiliate settlement of taxes payable,
a $14.1 million increase in other current liabilities primarily due to additional liabilities incurred as a result of the Cleco Cajun Transaction,
a $10.0 million decrease in accumulated deferred fuel, excluding FTRs, primarily due to the timing of collections at Cleco Power, partially offset by additional deferrals through a fuel surcharge at Cleco Power, and
a $6.6 million increase in accounts payable, excluding Cleco Power FTR purchases, primarily due to higher accruals related to the Cleco Cajun Transaction, partially offset by lower accruals of operating and maintenance expenses and lower capital expenditures as a result of several Cleco Power capital projects being placed in service in 2019.
These decreases in working capital were partially offset by:
a $34.7 million decrease in taxes payable primarily due to lower provisions for income taxes and lower corporate franchise taxes,
a $33.5 million increase in customer accounts receivable primarily due to the addition of Cleco Cajun receivables, partially offset by credits to Cleco Power’s customers related to the TCJA,
a $26.2 million increase in material and supplies inventory primarily due to the addition of inventory at Cleco Cajun,
a $11.4 million increase in other current assets primarily due to an indemnification asset at Cleco Cajun as a result of a contingent liability assumed with the Cleco Cajun Transaction,
an $8.5 million increase in other accounts receivable primarily due to the addition of Cleco Cajun receivables, and
a $6.1 million increase in cash and cash equivalents.
At December 31, 2019, Cleco’s Consolidated Balance Sheets reflected $4.83 billion of total liabilities compared to $4.31 billion at December 31, 2018. The $521.2 million increase in total liabilities during 2019 was primarily due to:
an increase in total long-term debt of $295.1 million, as previously discussed,
an increase in deferred lease revenue of $49.9 million as a result of the Cleco Cajun Transaction,
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an increase in accumulated deferred federal and state income taxes, net of $49.0 million,
an increase in postretirement benefit obligations of $34.2 million primarily due to lower discount rates, partially offset by a greater return on the fair value of plan assets and a contribution to the plan during 2019,
an increase of $33.8 million in affiliate accounts payable primarily for amounts due to Cleco Group for affiliate settlement of taxes payable,
an increase in intangible liabilities of $31.9 million as a result of the Cleco Cajun Transaction, and
an operating lease liability of $25.8 million as a result of the implementation of new accounting guidance effective January 1, 2019.
These increases in total liabilities were partially offset by a decrease in taxes payable of $34.7 million primarily as a result of lower accruals of federal and state income taxes.
In connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings issued $300.0 million under a new bridge loan agreement and $100.0 million under a new term loan agreement. Both loan agreements are variable rate debt and have a three-year term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings to maintain (i) a debt to capital ratio (as defined in the applicable agreement) below 65% and (ii) a rating applicable to Cleco’s senior debt rating (as defined in the applicable agreement). On September 11, 2019, Cleco Holdings completed the private placement of $300.0 million aggregate principal amount of its 3.375% senior notes due September 15, 2029. The proceeds from the issuance were used to repay the remaining amounts due under the $300.0 million bridge loan agreement and to repay a portion of the $100.0 million term loan agreement. The senior notes are governed by an indenture entered into between Cleco Holdings and a trustee. The indenture contains certain covenants that restrict Cleco Holdings’ ability to merge, consolidate, transfer, or lease all or substantially all of its assets or create or incur certain liens.
Cleco Holdings (Holding Company Level)
At March 31, 2020, Cleco Holdings had $88.0 million of short-term debt outstanding under its $175.0 million credit facility, at an all-in interest rate of 2.50%. For more information on Cleco Holding’s credit facility, see “— Credit Facilities.” Cleco Holdings has an uncommitted line of credit that allows up to $10.0 million in short-term borrowings, but no more than $10.0 million in the aggregate with Cleco Power’s similar line of credit, to support its working capital needs. There were no amounts outstanding under the uncommitted line of credit at March 31, 2020. Cleco Holdings had no short-term debt outstanding at December 31, 2019.
At March 31, 2020, Cleco Holding’s long-term debt outstanding was $1.67 billion, of which $63.3 million was due within one year. The long-term debt due within one year at March 31, 2020, represents principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC.
Cash and cash equivalents available at Cleco Holdings at DecemberMarch 31, 2016,2020, were $1.4$93.5 million, combined with $100.0$87.0 million credit facility capacity for a total liquidity of $101.4$180.5 million.

Cleco Power

There wasHoldings had no short-term debt outstanding at Cleco Power at December 31, 2016,2019, or 2015.

2018.

At December 31, 2016,2019, Cleco Power’sHolding’s long-term debt outstanding was $1.25$1.67 billion, $63.3 million of which $19.7 million was due within one year. The long-term debt due within one year at December 31, 2016,2019, represents $17.9 million of principal payments foron Cleco Holdings’ debt as required by the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments.Cajun Transaction commitments to the LPSC. For Cleco Power,Holdings, long-term debt increased $1.3$326.3 million from December 31, 2015, primarily due to the issuanceprivate placement of $330.0$300.0 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 repaymentaggregate principal amount of senior notes in December 2016, a $60.0on September 11, 2019, and $30.0 million repayment of Solid Waste Disposal Facility Bonds in November 2016, $16.8balance remaining on the $100.0 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,bank term loan entered into on February 4, 2019, in connection with the completion of the Merger, Cleco Power replacedCajun Transaction.

At December 31, 2019, and 2018, Cleco Holdings had no borrowings outstanding under its existing $300.0 million credit facility with a new $300.0$175.0 million credit facility. This credit facility provides for working capital and other financing needs. The new credit facility has similar terms as the previous facility, including restrictedincludes restrictive 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 letterHoldings has an uncommitted line 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 allowallows up to $10.0 million each in short-term borrowings, but no more than $10.0 million in the aggregate with Cleco Power’s similar line of credit, to support theirits working capital needs.

Cash and cash equivalents available at Cleco Holdings at December 31, 2016,2019, were $21.5$15.0 million, combined with $300.0$175.0 million credit facility capacity for a total liquidity of $321.5$190.0 million.
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At December 31, 2016, and 2015,

Credit Facilities
On May 15, 2020, Cleco Holdings entered into the Cleco Holdings Amendments. Also, on May 15, 2020, Cleco Power had a working capital surplusentered into the Cleco Power Amendment. The Amendments extend the terms of $149.1each facility through June 28, 2022. The current borrowing costs under the amended Cleco Holdings revolving credit facility are equal to LIBOR plus 1.875% or ABR plus 0.875%, plus commitment fees of 0.300%. Cleco Holdings’ amended $300.0 million term loan bears interest at an interest rate of LIBOR plus 1.875% and $184.9Cleco Holdings’ amended $30.0 million respectively. The $35.8 million decrease in working capital is primarily due to:

a $44.2 million decrease in unrestricted cashterm loan bears interest at an interest rate of LIBOR plus 1.875%. If Cleco Holdings’ credit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Holdings may be required to pay higher fees and 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 timingadditional interest 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 creation0.50% under any 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 dueCleco Holdings Amendments. The current borrowing costs under the amended Cleco Power revolving credit facility are equal to timingLIBOR plus 1.250% or ABR plus 0.250%, plus commitment fees 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, 2016,0.150%. If Cleco Power’s Consolidated Balance Sheets reflected $2.73 billioncredit ratings were to be downgraded one level by Fitch, Moody’s or S&P, Cleco Power may be required to pay higher fees and additional interest of total liabilities compared to $2.68 billion at December0.125% under the Cleco Power Amendment. The Amendments also include customary LIBOR-transition provisions.

At March 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, 2016,2020, Cleco had two separate revolving credit facilities, one for Cleco Holdings in the amount of $175.0 million with outstanding borrowings of $88.0 million and one for Cleco Power in the amount of $300.0 million with outstanding borrowings of $150.0 million. The total of all revolving credit facilities creates a maximum aggregate capacity of $400.0$475.0 million with outstanding borrowings of $238.0 million.

At December 31, 2015, Cleco Holdings had a $250.0 million credit facility. On April 13, 2016, in

In connection with the completion of the Merger,Cleco Cajun Transaction, on February 4, 2019, Cleco Holdings replaced the existingincreased its credit facility withcapacity by $75.0 million, for a $100.0total credit facility of $175.0 million. Cleco Holdings’ $175 million credit facility.facility provides for working capital and other financing needs. The new credit facility has similar terms as the previous facility, including restrictedincludes restrictive financial covenants and expires in 2021.2022. Under covenants contained in Cleco Holdings’ credit facility, Cleco is required to maintain total indebtedness less than or equal to 65% of total capitalization. At DecemberMarch 31, 2016,2020, Cleco Holdings was in compliance with the covenants of its credit facility. The borrowing costs under the facility are equal to LIBOR plus 1.75%1.875% or ABR plus 0.75%0.875%, plus commitment fees of 0.275%0.300%. 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,Fitch, Moody’s or S&P, Cleco Holdings wouldmay be required to pay higher fees and additional interest of 0.075% and 0.50%, respectively, under the pricing levels forof its credit facility.

At December 31, 2015,

Cleco Power had aPower’s $300.0 million credit facility. On April 13, 2016, in connection with the completion of the Merger, Cleco Power replaced its existing credit facility.facility provides for working capital and other financing needs. The new credit facility has similar terms as the previous facility, including restrictedincludes restrictive financial covenants and expires in 2021.2022. Under covenants contained in Cleco Power’s credit facility, Cleco Power is required to maintain total indebtedness less than or equal to 65% of total capitalization. At DecemberMarch 31, 2016,2020, Cleco Power was in compliance with the covenants of its credit facility. The borrowing

costs under the facility are equal to LIBOR plus 1.125%1.250% or ABR plus 0.125%0.250%, plus commitment fees of 0.125%0.150%. 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,Fitch, Moody’s or S&P, Cleco Power wouldmay 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 and Distribution Limitations

The 2016 Merger Commitments provideinclude provisions for limitations onlimiting the amount of distributions that maycan be paidmade from Cleco Holdings to Cleco Group, or Cleco Partners, depending on Cleco Holdings’ debt to EBITDA ratio and its corporate credit ratings. Cleco Holdings may not make any distribution unless, after giving effect to such distribution, Cleco Holdings’ debt to EBITDA ratio is equal to or less than 6.50 to 1.00 and Cleco Holdings’ corporate credit rating is investment grade with one or more of the three credit rating agencies. At March 31, 2020, Cleco Holdings was in compliance with the provisions of the 2016 Merger Commitments that would restrict the amount of distributions available. Additionally, in accordance with the 2016 Merger Commitments, Cleco Power is subjectedsubject 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. TheCleco Power may not make any distribution unless, after giving effect to such distribution, Cleco Power’s common equity ratio would not be less than 48% and Cleco Power’s corporate credit rating is investment grade with two of the three credit rating agencies. At March 31, 2020, Cleco Power was in compliance with the provisions of the 2016 Merger Commitments that would restrict the amount of distributions available. The 2016 Merger Commitments also
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prohibit Cleco from incurring additional long-term debt, excluding non-recourse debt, unless certain financial ratios are achieved. 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,the 2016 Merger Commitments, see “Risk Factors—Factors — Structural Risks — Holding Company.Company” and “— Regulatory Risks — Regulatory Compliance.

Cleco Cash Flows

Net Operating Cash Flow

Net

Internally generated cash from operating activities consists of net income, adjusted for non-cash expenses, non-cash income, and changes in operating assets and liabilities. Non-cash items include depreciation and amortization, deferred fuel costs, deferred income taxes, and allowance for equity funds used during construction. Cash provided by operating activities for Cleco may vary year to year primarily as a result of the cash provided by operating activities for the successor period April 13, 2016, through December 31, 2016, was $51.3 million. There were no significant changesat Cleco Power and Cleco Cajun. Changes in the underlying trends impactingCleco Power’s 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.

Netare discussed below. Cleco Cajun’s cash provided by operating activities for the predecessor period January 1, 2016, through April 12, 2016, was $129.8 million. There were no significantmay vary year to year primarily as a result of 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 netwholesale contracts, cost of fuel and purchased 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 paymentscosts for generatinggeneration station outage expenses of $15.9 million,operations and maintenance.

lower income tax payments of $13.9 million.

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$60.2 million and $108.1 million during 2016, $366.5the three months ended March 31, 2020, and 2019, respectively. Net cash provided by operating activities decreased $47.9 million during 2015,primarily due to:

higher payments for fuel purchases of $24.8 million primarily due to higher purchases of petroleum coke and $347.1coal,
higher payout for employee benefits of $7.1 million, during 2014.
lower net fuel and purchased power collections of $6.2 million primarily due to timing of collections at Cleco Power,
higher payments of $6.1 million primarily due to timing of vendor payments, and
higher interest payments of $3.3 million.
These decreases were partially offset by:
higher receipts for other accounts receivable of $8.5 million, including the timing of receipts of joint owners’ portion of generating station expenditures and
higher collections from Cleco Cajun customers of $6.0 million.
Net cash provided by operating activities was $430.1 million and $317.8 million for the years ended December 31, 2019, and 2018, respectively. Net cash provided by operating activities during 2016 decreased $150.72019 increased $112.3 million from 20152018 primarily due to:
$124.0 million for the addition of Cleco Cajun operations, including receipts of $37.7 million as a result of the Cottonwood Sale Leaseback,
higher net fuel and purchased power collections at Cleco Power of $29.7 million primarily due to the following items:

timing of collections, and
lower payments for fuel purchases of $18.6 million primarily due to lower purchases of petroleum coke at Cleco Power.
These increases were partially offset by:
payments for pension plan contributions of $12.3 million at Cleco Power,
lower receipts of $8.6 million, primarily due to the timing of receipts of Cleco Power’s joint owners’ portion of generating stations expenditures,
lower Cleco Power customer deposits of $7.9 million, and
higher interest paid on long-term debt at Cleco Holdings of $6.8 million primarily as a result of additional borrowings to finance the Cleco Cajun Transaction.
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lower
Net cash provided by operating activities during 2018 increased $52.4 million from 2017 primarily due to:
higher collections from customers of $121.5$25.3 million due to lower 2016 Merger credits issuedused in 2016,2018 and the timing of collections of accounts receivables,

higherlower payments for fuel purchases of $23.6 million primarily due to lower deliveries of lignite and petroleum coke,
lower payments for affiliate settlements of $34.0$18.1 million
lower vendor payments of $18.0 million due to timing of property tax payments, and

higher receipts of $8.1 million primarily due to timing of receipts of joint owners’ portion of generating station expenditures.
These increases were partially offset by:
lower net fuel and power purchase collections of $17.1$30.4 million primarily due to timing of recovery.collections and

higher payments for employee benefits of $8.2 million.
Net Investing Cash Flow
Net cash used in investing activities was $65.4 million and $892.7 million during the three months ended March 31, 2020, and 2019, respectively. Net cash used in investing activities decreased $827.3 million primarily due to:
the absence of payment for the acquisition of all the membership interest in South Central Generating of $962.2 million, partially offset by the absence of cash received of $147.2 million and
lower additions to property, plant, and equipment, net of AFUDC, of $12.3 million.
Net cash used in investing activities was $1.12 billion and $288.2 million during the years ended December 31, 2019, and 2018, respectively. Net cash used in investing activities increased $827.2 million primarily due to:
payment for the acquisition of all the membership interest in South Central Generating of $962.2 million, partially offset by cash received of $147.2 million and
higher additions to property, plant, and equipment, net of AFUDC, of $31.5 million.
These decreases in net operating cashincreases were partially offset by:

by the absence of the issuance of a $16.8 million note receivable.
lower paymentsNet cash used in investing activities during 2018 increased $84.6 million from 2017 primarily due to:
higher additions to vendorsproperty, plant, and equipment, net of $28.9AFUDC, of $48.3 million,
the issuance of a $16.8 million note receivable, and
the absence of proceeds from the sale of transmission assets of $16.7 million.
Net Financing Cash Flow
Net cash provided by financing activities was $226.8 million and $770.6 million during the three months ended March 31, 2020, and 2019, respectively. Net cash provided by financing activities decreased $543.8 million primarily due to:
the absence of borrowings of $400.0 million related to the timingfinancing of property tax paymentsthe Cleco Cajun Transaction in February 2019 and other vendor payments
lower contributions from Cleco Group of $384.9 million.
These decreases were partially offset by:
higher draws on credit facilities of $130.0 million and

lower payments on credit facilities of $108.0 million.
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Net cash provided by financing activities was $687.8 million for fuel inventorythe year ended December 31, 2019. Net cash used in financing activities was $41.7 million for the year ended December 31, 2018. Net cash provided by financing activities during 2019 increased $729.5 million primarily due to:
borrowings of $26.8$400.0 million related to the financing of the Cleco Cajun Transaction,
higher contributions from Cleco Group of $384.9 million,
the issuance of $300.0 million in senior notes at Cleco Holdings, and
the absence of distributions to Cleco Group of $71.4 million.
These increases were partially offset by:
higher repayments of long-term debt of $371.4 million and
the absence of the $50.0 million issuance of senior notes in March 2018 at Cleco Power.
Net cash used in financing activities during 2018 increased $62.5 million from 2017 primarily due to lower lignite deliveries and lower petroleum coke purchases.

Net cash provided by operating activities during 2015 increased $19.4issuances of senior notes of $75.0 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 paymentslower distributions to vendorsCleco Group 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.”

$12.7 million.

Capital Expenditures

Cleco’s capital expenditures are primarily incurred in its major first-tier subsidiary,at Cleco Power.Power and Cleco Cajun. Cleco Power’s capital expenditures relate primarily to assets that may be included in Cleco Power’s rate base and, if considered prudent by the LPSC, can be recovered from its customers. Those assets also earn a rate of return authorized by the LPSC and are subject to the FRP. Such assets primarily consist of improvements to Cleco Power’s distribution system, transmission system, and generating stations.

stations as well as hardware and software upgrades. Cleco Cajun’s capital expenditures primarily consist of improvements to Cleco Cajun’s transmission system and generating stations as well as hardware and software upgrades.

During the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, Cleco Power had capital expenditures, excluding AFUDC, of $181.7$298.6 million, $153.3$275.0 million, and $201.2$226.9 million, respectively. In 2016, 2015,2019, 2018, and 2014,2017, 100% of Cleco Power’s capital expenditure requirements were funded internally.

For

During the successor period April 13, 2016, throughyears ended December 31, 2016,2019, 2018, and 2017, other subsidiaries had capital expenditures excluding AFUDC, of $0.7 million. Other subsidiaries had$9.8 million, $1.9 million, and $1.7 million, respectively. The higher capital expenditures excluding AFUDC,in 2019 was primarily due to the addition 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.

Cleco Cajun’s capital expenditures.

In 20172020 and for the five-year period ending 2021,2024, Cleco and Cleco Power expectsexpect to internallymaterially fund 100% of its capital expenditure requirements.requirements with internally generated funds. However, Cleco Power may choose to issue debt in order to achieve aits stipulated regulatory capital structure with a debt ratio of 49%.structure. All computations of internally funded capital expenditures exclude AFUDC.

AFUDC and capitalized interest.

Cleco and Cleco Power’s estimated capital expenditures and debt maturities for 20172020 and for the five-year period ending 2021December 31, 2024 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   
  

 

 

    

 

 

   

AFUDC and capitalized interest.
Cleco
 
 
 
 
PROJECT (THOUSANDS)
2020
%
2020-2024
%
Environmental
$
—%
$71,000
5%
New business
50,000
17%
169,000
11%
Transmission reliability
67,000
22%
222,000
15%
Fuel optimization
—%
265,000
18%
General(1)
182,000
61%
764,000
51%
Total capital expenditures
$299,000
100%
$1,491,000
100%
Debt payments
11,000
 
681,000
 
Total capital expenditures and debt payments
$310,000
 
$2,172,000
 
(1)
Primarily consists of rehabilitation projects of older transmission, distribution, and generation assets and hardware and software upgrades at Cleco Power.
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Cleco Power

        

PROJECT (THOUSANDS)

  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   
  

 

 

    

 

 

   

Cleco Power
 
 
 
 
PROJECT (THOUSANDS)
2020
%
2020-2024
%
Environmental
$
—%
$45,000
3%
New business
50,000
18%
169,000
13%
Transmission reliability
67,000
25%
222,000
16%
Fuel optimization
—%
265,000
19%
General(1)
156,000
57%
672,000
49%
Total capital expenditures
$273,000
100%
$1,373,000
100%
Debt payments
11,000
 
186,000
 
Total capital expenditures and debt payments
$284,000
 
$1,559,000
 
(1)
Primarily consists of rehabilitation projects of older transmission, distribution, and generation assets and hardware and software upgrades.

Capital expenditures for other subsidiaries, including Cleco Cajun, in 20172020 are estimated to total $2.0$26.0 million. For the five-year period ending 2021,December 31, 2024, capital expenditures for other subsidiaries, including Cleco Cajun, are estimated to total $8.0$118.0 million. Cleco expects cash and cash equivalents on hand in addition to cash generated from operations, borrowings from credit facilities, and the net proceeds of any issuances of debt securities to be adequate to fund normal ongoing capital expenditures, working capital, and debt service requirements for the foreseeable future.

Other Cash Requirements

Cleco Power’s regulated operations and Cleco Cajun unregulated operations are Cleco’s primary sourcesources 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.

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, 2016,2019, and represent only the projected future payments that Cleco was contractually obligated to make as of December 31, 2016.2019.
 
 
 
 
 
PAYMENTS DUE
BY PERIOD
CONTRACTUAL OBLIGATIONS
(THOUSANDS)
TOTAL
LESS THAN
ONE YEAR
1-3 YEARS
3-5 YEARS
MORE
THAN 5
YEARS
Cleco
 
 
 
 
 
Long-term debt(1)
$4,781,024
$141,829
$598,210
$542,643
$3,498,342
Finance lease(2)
34,099
2,612
5,222
5,222
21,043
Operating lease(3)
36,814
4,982
6,730
6,484
18,618
Purchase(4)
209,360
120,978
55,296
18,612
14,474
Other long-term liabilities(5)
18,935
5,738
6,148
5,249
1,800
Postretirement benefits(6)
272,906
9,146
42,517
56,051
165,192
Total Cleco
$5,353,138
$285,285
$714,123
$634,261
$3,719,469
Cleco Power
 
 
 
 
 
Long-term debt(1)
$2,354,387
$77,634
$156,857
$277,169
$1,842,727
Finance lease(2)
34,099
2,612
5,222
5,222
21,043
Operating lease(3)
35,679
3,960
6,665
6,436
18,618
Purchase(4)
127,021
50,431
47,857
15,491
13,242
Other long-term liabilities(5)
10,800
1,800
3,600
3,600
1,800
Postretirement benefits(6)
61,800
24,100
37,700
Total Cleco Power
$2,623,786
$136,437
$244,301
$345,618
$1,897,430
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       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 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1)
Long-termFor more information regarding individual long-term debt existing asmaturities, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 9 — Debt” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 8 — Debt.” For Cleco, the amount above excludes the fair value adjustments related to the 2016 Merger. For Cleco and Cleco Power, the Series A GO Zone bonds with a maturity date of December 31, 2016, is debt that has2038 but a finalmandatory tender of May 2020 are included in the column representative of the maturity of January 1, 2018, or later (current maturities of long-term debt are due within one-year).date. Cleco’s anticipated interest payments related to long-term debt also are included in this category. Scheduled maturities ofcategory and do not reflect anticipated future refinancing, early redemptions, or 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.issuances.
(2)
CapitalFinance leases are maintained in the ordinary course of Cleco’s business activities, including leases for barges. Cleco’s anticipated interest payments and operating fees related to finance lease obligations are also included in this category. For more information regarding these leases, see “Financial StatementStatements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 15—Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Other Commitments—Fuel Transportation Agreement.4 — Leases — Finance Lease.
(3)
Operating leases are maintained in the ordinary course of Cleco’s business activities. These leases include utility systems, railcars, towboats, office space, operating facilities, and office equipment 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—Data — Notes to the Audited Financial Statements—Statements — Note 14—Operating4 — 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.


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

Purchase orders: Cleco has entered into purchase orders in the course of normal business activities.
(5)
Other long-term liabilities primarily consist of obligations for franchise payments, deferred compensation facilities use, and various operating and maintenance agreements.
(6)
Pension and otherPostretirement benefits obligations consist of the expected required contributions for the pension plan and the estimated present value of obligations for SERP and other postretirement obligations. For more information regarding Cleco’s defined benefit pension plan, SERP, and other postretirement obligations, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 9—10 — Pension Plan and Employee Benefits” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 9 — Pension Plan and Employee Benefits.”

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

Off-Balance Sheet Commitments and On-Balance Sheet Guarantees

Cleco Holdings and Cleco Power have entered into various off-balance sheet commitments in the form of guarantees and standby letters of credit in order to facilitate their activities and the activities of Cleco Holdings’ subsidiaries and equity investees (affiliates). Cleco Holdings and Cleco Power have also agreed to contractual terms that require them to pay third parties if certain triggering events occur. These contractual terms generally are defined as guarantees. For more information about off-balance sheet commitments and on-balance sheet guarantees, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 15—15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—“Guarantees — Off-Balance Sheet Commitments and Guarantees” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees.”
Cybersecurity
The operation of Cleco’s electrical systems relies on evolving operational and information technology systems and network infrastructures that are complex. The failure of Cleco or its vendors’ operational and information technology systems and networks due to a physical or cyberattack, or other event could significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; result in damage to Cleco’s assets or operations, or those of third parties; result in damage to Cleco’s reputation; and subject Cleco to claims by customers or third parties, any of which could have a material adverse effect on the results of operations, financial condition, or cash flows of Cleco. In addition, the Cleco Cajun Transaction could increase the risk associated with cybersecurity that could have a material adverse effect on Cleco’s results of operations, financial condition, or cash flows including phishing attacks, denial of service attacks, and employee insider attacks. Cleco continues to assess its cybersecurity tools and processes and has taken a variety of actions to monitor and address cyber-related risks. Cleco’s Chief Digital and Information Officer leads Cleco’s cybersecurity team and oversees Cleco’s cybersecurity maturity plan. Each quarter, management provides cybersecurity updates to Cleco’s Board of Managers. For more information on risks related to Cleco’s cybersecurity, see “Risk Factors — Operational Risks — Technology and Terrorism Threats.”
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Regulatory and Other Matters

Inflation

Annual inflation rates, as measured by the U.S.United States Consumer Price Index, have averaged 1%2% 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, under2019. Under established regulatory practice, historical costs have traditionally formed the basis for recovery from customers. As a result, Cleco Power’s cash flows designed to provide recovery of historical plant costs may not be adequate to replace property, plant, and equipment in future years.

Environmental Matters

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

Retail Rates of Cleco Power

Retail

For both 2019 and 2018, retail rates, (comprisedwhich includes the retail portion of baseFAC and EAC revenue, the FAC revenue, and the EAC revenue) regulated by the LPSC accounted for approximately 85%86% of Cleco Power’s 2016total base, FAC, and 2015EAC revenue.

Fuel Rates

Generally, theCleco Power’s cost of fuel used for electric generation and the cost of power purchased for utility customerspower 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. TheFor more information on the FAC and the most recent fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC 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,Audits — Fuel Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC 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.

Audits — Fuel Audit.”

Environmental Rates

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides forCleco Power an EAC to recover from customers certain costs of environmental compliance. The costs eligible for recovery are prudently incurred air emissions credits associated with complying with federal, state, and local air emission regulations that apply to the generation of electricity reduced by the sale of such allowances. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. 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,the EAC and the most recent environmental audit, see “Business—“Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Matters—Air Quality.”

On February 3, 2016,Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC 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.

Audits — Environmental Audit.”

Base Rates

Cleco Power’s annual retail earnings are subject to the terms of an FRP establishedthat was approved by the LPSC. Prior to July 1, 2014,LPSC in June 2014. For more information on the LPSC’s regulation of 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%base rates, see “Business — Regulatory Matters, Industry Developments, 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 withFranchises — Rates.”
For more information on the LPSC to extend its currentStaff’s 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 excessreviews, 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 FRPTCJA, and information on the LPSC Staff’s FRP reviews,tax dockets, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 12—13 — Regulation and Rates.Rates — FRP, “— TCJA,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — FRP” and “— TCJA.”

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

In 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 subsequentlybegan participating in energy efficiency programs in November 2014. Cleco Power has recovered approximately $3.3 million annually for each of the program years through an approved rate tariff. In January 2018, Cleco began recovering an additional $3.3 million annually for estimated costs related to programs specific to political subdivisions.
In November 2017, the LPSC initiated an audit on the first two program years to consider all program costs. On June 19, 2019, the LPSC approved the audit report and concluded the costs were reasonable and prudent, and eligible for recovery consistent with the energy efficiency rules. On December 17, 2019, the LPSC initiated an audit on program years three and four to consider all program costs. Cleco Power has responded to several sets of data requests regarding the audit. Management is unable to predict or give a reasonable estimate of the outcome of the audit.
Generally utility companies are allowed to recover from customers the accumulated decrease in revenues associated with the energy efficiency programs. In December 2018, Cleco Power filed its formala letter of intent with the LPSC to participaterecover certain accumulated decrease in revenues, also known as LCFC. On October 21, 2019, Cleco Power received notice of approval from the Phase I—Quick Start portionLPSC allowing recovery of the LPSC’s energy efficiency initiative,accumulated LCFC revenues until such a time that base rates reset, which runs November 1, 2014, throughis expected in July 31, 2017. During Phase I, 2020.
MISO Cost Benefit Analysis
Cleco Power designed several energy efficiency programs and began offering these programs to customers on November 1, 2014. In November 2014,entered into MISO in 2013. Within five years of joining MISO, the LPSC required Cleco Power began recovering approximately $3.3 million annuallyto conduct a study of estimatedthe costs forand benefits of its membership in MISO. During the program throughsecond quarter of 2017, Cleco Power submitted an approved rate tariff.

analysis with both a backward-looking, historical analysis and a forward-looking, prospective analysis of the costs and benefits of operating in MISO, as compared to a scenario where Cleco Power and Entergy Louisiana exit MISO and operate independently. Cleco Power’s analysis indicated that continued MISO membership would best serve the public interest. Cleco Power has responded to several sets of data requests on the analysis. Management is unable to predict the outcome of this analysis or give a reasonable estimate of the possible range of disallowance of costs, if any.

Wholesale Rates of Cleco Power

The rates Cleco, through Cleco Power and Cleco Cajun, charges its wholesale customers are subject to FERC’s triennial market power analysis. FERC requires a utility to pass a screening test as a condition for securing and/or retaining approval to sell electricity in wholesale markets at market-based rates. An updated market power analysis is tomust 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.

during the fourth quarter of 2020.

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

In June 2013, the LPSC unanimously approved Cleco.

Cleco Power’s MISO change of control request to transfer functional control of certainPower and Cleco Cajun’s generation dispatch and transmission assets tooperations are integrated with MISO. MISO operates a fully functioning RTO market with two major market processes: the Day-Ahead Energy and Operating Reserves Market and the Real-Time Energy and Operating Reserves Market. These marketsBoth use market-based mechanisms to manage transmission congestion across the MISO market area. In December 2013, For more information about the risks associated with Cleco’s participation in MISO, see “Risk Factors — Regulatory Risks — MISO.”
Cleco Power integrated its generation dispatch and Cleco Cajun earn transmission operations with MISO.revenues pursuant to MISO’s FERC filed tariff. The LPSC authorizedperformance obligation of transmission service is satisfied as service is provided. Revenue is recognized upon delivery of the transmission service. For Cleco Power, to defer and collect the retail portion of its MISO integration costsrevenue from the LPSC jurisdictional customers throughtransmission of electricity is recorded based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of revenue requirements with rates effective June 1 of each year. For Cleco Cajun, revenue from the FRP.transmission of electricity is recorded based on a FERC-approved annual filing rate mechanism effective June 1 of each year. Cleco Power deferred $3.7 million of integration costs and began recovering these costs over a four-year period beginning July 1, 2014.

Cajun charges transmission rates based on its cost to provide transmission services.

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. 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.

For more information about the risks associated with Cleco Power’s participation in MISO,ROE complaints, see “Risk Factors—MISO.“Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE.

Transmission, Distribution, and Generation Projects

Cleco Power is involved in several transmissionPower’s significant ongoing projects includinginclude the Layfield/Messick project, the CenlaBayou Vista to Segura Transmission Expansion project and the Terrebonne to Bayou Vista TransmissionDSMART distribution 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 readsee “—Overview— 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 itsand Cleco Cajun’s generation dispatch and transmission operations are integrated with MISO in December 2013.MISO. For more information about Cleco Power’sPower and Cleco Cajun’s integration into MISO, see “—Transmission Rates of Cleco Power.Rates.

ERO

The Energy Policy Act of 2005 added Section 215 to the Federal Power Act, which provides for a uniform system of mandatory, enforceable reliability standards. In 2006, FERC named NERC as the ERO that would overseewill be required to develop and regulateenforce the mandatory reliability standards.

The SPP RE conducts a

A NERC Reliability StandardStandards audit is conducted every three years for Cleco Power and Cleco Cajun. On October 17, 2019, Cleco Power’s NERC Reliability Standards audit was completed. The final report was issued on October 31, 2019. Cleco Power is unable to determine the timing of NERC’s approval of the audit report due to the impact of the COVID-19 pandemic. The Cleco Cajun NERC Reliability Standards audit occurred during April 2019. There were no violations or areas of concern discovered during the Cleco Cajun audit.
A NERC CIP audit is also conducted every three years. 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 NERC CIP audit has been delayed due to the impact of the COVID-19 pandemic; however, it is scheduledexpected to begin in Aprilbe complete by the end of the third quarter of 2020. Cleco Cajun’s CIP audit occurred during June 2019. The preliminary findings have been received by Cleco Cajun.
Management is unable to predict the final financial outcome of thisthe current Cleco Power NERC Reliability Standards audit, the current Cleco Cajun CIP audit, or any future audits, or whether any findings will have a material adverse effect on the results of operations, financial condition, or cash flows of 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.

Cleco. For a discussion

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of risks associated with FERC’s regulation of Cleco Power’s transmission system, see “Risk Factors—Factors — Regulatory Risks — Reliability and Infrastructure ProtectionCIP Standards Compliance.”

Retail Electric Markets

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

electric utility that is within 300 feet of the respective customer. If the customer is beyond 300 feet from any existing utility service, they may choose their electric supplier. The LPSC’s review of the “300-foot rule” is currently under review by the LPSC in Docket No. R-32763.R-32763 has been ongoing since April 2013. On February 5, 2020, the docket was closed due to no substantive actions in the proceedings since October 2014. Management is unable to predict if this docket will be reopened for reconsideration in the time of completionfuture 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, in October 2017, Cleco Power filed a request with the LPSC to initiate an IRP processprocess. In February 2018, Cleco Power filed the data assumptions to be used in October 2013.its IRP analysis. The IRP process included the conduct ofincludes conducting stakeholder meetings and considerationreceiving feedback from stakeholders. LPSC acknowledgment of feedback provided by stakeholders.a completed IRP process was received with no objections or discussions on January 22, 2020.
The IRP report describes how Cleco Power filedplans to meet its forecasted load requirements on a reliable and economic basis. The IRP withis used as a guide in future decision-making and does not represent firm operational commitments. LPSC acknowledgment of a completed IRP process does not represent approval of any actions stated in the 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.

report.

Service Quality Program (SQP)

Plan (“SQP”)

In October 2015, the LPSC proposed an SQP containing 21 requirements for Cleco Power. The SQP has provisions relating to employee headcount, customer service, reliability, vegetation management, and reporting. On February 1,In April 2016, the SQP was approved by the LPSC. The SQP will remain in effect until 2021. Prior to the expiration of the SQP, a new five-year program must be negotiated and submitted to the LPSC for approval. Cleco Power is required to file afiled its annual SQP monitoring report annually, beginningon April 1, 2019.
Franchises
Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state law. These franchises are for fixed terms, which vary from 10 years to more than 50 years. Historically, Cleco Power has been substantially successful in the timely renewal of franchises as each neared the end of its term. Cleco Power’s next municipal franchise expires in April 2017.

Franchises

2022. For more information on franchises, see “Business—“Business — Regulatory Matters, Industry Developments, and Franchises—Franchises — Franchises.”

Recent Authoritative Guidance

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

GENERAL

Cleco Holdings’ predecessor was incorporated on October 30, 1998, under the laws of the state of Louisiana.

Cleco Holdings is a public utility holding company whichthat holds investments in several subsidiaries, including Cleco Power. SubstantiallyPower and Cleco Cajun. Prior to the Cleco Cajun Transaction, substantially all of itsCleco Holdings’ operations arewere conducted through Cleco Power. Cleco Holdings, subject to certain limited exceptions, is exempt from regulation as a public utility holding company pursuant to provisions of the Public Utility Holding Company Act of 2005.

Cleco Holdings’ predecessor was incorporated on October 30, 1998, under the laws of the state of Louisiana. On April 13, 2016, Cleco Holdings completed its merger with Merger Sub whereby Merger Sub merged with and into Cleco Corporation, with Cleco Corporation surviving the 2016 Merger, and Cleco Corporation converting to a limited liability company and changing its name to Cleco Holdings, as a direct, wholly owned subsidiary of Cleco Group and an indirect, wholly owned subsidiary of Cleco Partners. For more information

Cleco Power is a regulated electric utility engaged principally in the generation, transmission, distribution, and sale of electricity within Louisiana. Cleco Power owns ten generating units with a total nameplate capacity of 3,360 MW and serves approximately 288,000 customers in Louisiana through its retail business. Additionally, Cleco Power supplies wholesale power in Louisiana and Mississippi. Cleco Power was organized as a limited liability company under the laws of the state of Louisiana on the Merger, see “Financial Statements and Supplementary Data—Notes to the Financial Statements—Note 3—Business Combinations.”

December 12, 2000. Cleco Power’s predecessor was incorporated on January 2, 1935, under the laws of the state of Louisiana.

Cleco Power wasCajun, 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, 1998,28, 2017, under the laws of the state of Louisiana, is a merchant energy subsidiaryan unregulated electric utility 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 twoeight generating unitsassets with a total nameplaterated capacity of 775 MW.3,555 MW and supplies wholesale power and capacity in Arkansas, Louisiana, and Texas. On February 4, 2019, the Cleco Cajun Transaction was completed. For more information on the transfer of Coughlin to Cleco Power,Cajun Transaction, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 18—Coughlin Transfer.3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations.

At DecemberMarch 31, 2016,2020, Cleco had 1,2031,484 employees. At December 31, 2016,Cleco’s mailing address is P.O. Box 5000, Pineville, Louisiana 71361-5000, and its telephone number is (318) 484-7400. Cleco’s website is located at https://www.cleco.com. Cleco Power had 1,022 employees.

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 resultsAnnual 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 operations, see “Management’s Discussioncharge, through Cleco’s website after those reports or filings are filed electronically with or furnished to the SEC. Cleco’s electronically filed reports can also be obtained on the SEC’s website located at https://www.sec.gov. Cleco’s governance guidelines, code of conduct for financial managers, ethics and Analysisbusiness standards, and the charters of Financial Conditionits boards of managers’ audit, leadership development and Resultscompensation, business planning and budget review, governance and public affairs, and asset management committees are available on its website and available in print upon request. Information on Cleco’s website or any other website is not incorporated by reference into this prospectus and does not constitute a part of Operations—Results of Operations—Comparison of the Years Ended December 31, 2016, and 2015—this prospectus.

OPERATIONS
Cleco Power.”

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—Operations — Results of Operations—Operations — Comparison of the Years Ended December 31, 2016,2019, and 2015—2018 — Cleco Power—Power — Significant Factors Affecting Cleco Power” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Comparison of the Three Months Ended March 31, 2020, and 2019 — Cleco Power.”

Power Generation

As of DecemberMarch 31, 2016,2020, Cleco Power’s aggregate net electric generating capacity was 3,1683,214 MW. This amount reflects the maximum production capacity these units can sustain over a specified period of time. On March 1, 2019, Cleco Power began to operate Dolet Hills Power Station from June through September of each year; however, Dolet Hills Power Station will continue to be available to operate in other months, if needed. In September 2016, Teche Unit 1,January 2020, Cleco Power’s joint
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owner in Dolet Hills Power Station unilaterally entered into a 23-MW natural gassettlement with the Arkansas Public Service Commission to seek regulatory approval to retire the Dolet Hills Power Station by 2026. This settlement does not bind Cleco Power to agree to retire the Dolet Hills Power Station by the end of 2026.
In April 2020, Cleco Power and SWEPCO mutually agreed to not develop additional mining areas for future lignite extraction and subsequently provided notice to the LPSC of the intent to cease mining at the Dolet Hills and Oxbow mines by June 2020, subject to LPSC review and approval. Early closure of the mines would most likely result in increased costs billed through fuel, which management currently believes are recoverable. Management does not believe an early closure of the mines would have an adverse impact on the recovery value of the plant. Cleco Power has the ability to secure alternative fuel sources and expects to have sufficient lignite fuel available to continue seasonal operations of the Dolet Hills Power Station through at least the 2020 and 2021 seasonal operations periods. Also in April 2020, Cleco Power announced its intent to seek regulatory approval to retire the Dolet Hills Power Station at the end of 2021, subject to recovery mechanisms. This does not bind Cleco Power to a specific retirement plan and Cleco Power will continue to evaluate the cost of operating the Dolet Hills Power Station compared with other alternatives and decide the best course of action for the Dolet Hills Power Station within the LPSC regulatory requirements and recovery mechanisms.
In August 2019, the St. Mary Clean Energy Center was placed into service. The St. Mary Clean Energy Center is a 47 net MW generating unit was retired. that is fueled by waste heat from Cabot Corporation’s carbon black manufacturing plant in Franklin, Louisiana. The unit is expected to generate more than 300,000 MWh of zero additional carbon emitting energy each year.
The following table sets forth certain information with respect to Cleco Power’s generating facilities:

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    
  

 

 

   

 

 

    

facilities as of March 31, 2020:
GENERATING STATION
YEAR OF
INITIAL
OPERATION
NAMEPLATE
CAPACITY
(MW)(1)
NET
CAPACITY
(MW)(2)
PRIMARY
FUEL USED
FOR
GENERATION
GENERATION
TYPE
Brame Energy Center
 
 
 
 
 
Nesbitt Unit 1
1975
440
424
natural gas
steam
Rodemacher Unit 2
1982
157(3)
148(3)
coal
steam
Madison Unit 3
2010
641
625
petroleum coke/coal
steam
Acadia Unit 1
2002
580
548
natural gas
combined cycle
Coughlin Unit 6
2000
264
252
natural gas
combined cycle
Coughlin Unit 7
2000
511
486
natural gas
combined cycle
Teche Unit 3
1971
359
327
natural gas
steam
Teche Unit 4
2011
33
34
natural gas
combustion
Dolet Hills Power Station
1986
325(4)
323(4)
lignite
steam
St. Mary Clean Energy Center
2019
50
47
waste heat
steam
Total generating capability
 
3,360
3,214
 
 
(1)
Nameplate capacity is the capacity at the start of commercial operations.
(2)
Based on capacity testing of the generating units and operational tests performed during May, June, July,between April and August 2016.2019. These amounts do not represent generating unit capacity for MISO planning reserve margins.
(3)
Represents Cleco Power’s 30% ownership interest in the capacity of Rodemacher Unit 2, a 523-MW generating unit.
(4)
Represents Cleco Power’s 50% ownership interest in the capacity of Dolet Hills Power Station, a 650-MW generating unit.

The following table sets forth the amounts of power generated by Cleco Power for the years indicated:
YEAR
THOUSAND MWh
PERCENT OF TOTAL ENERGY
REQUIREMENTS
2019
12,552
103.0%
2018
11,848
94.6%
2017
10,864
91.1%
2016
12,759
103.6%
2015
12,564
100.2%
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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 itsPower’s generation dispatch and transmission operations are integrated with MISO. The amount of power generated by Cleco Power is dictated by the availability of Cleco Power’s generating fleet and the manner in which MISO dispatches each generating unit. Depending on how generating units are dispatched by MISO, the amount of power generated may be greater than or less than total energy requirements. Generating units are dispatched by referencing each unit’s economic efficiency as it relates to the overall MISO market. For more information on MISO, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations — Financial Condition—Condition — Regulatory and Other Matters—Matters — Transmission Rates of Cleco Power.Rates.

Fuel and Purchased Power

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

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

  LIGNITE  COAL  NATURAL GAS  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

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

In December 2013,

Cleco Power integrated its generation dispatch and transmission operations with MISO. Consequently,is a participant in the MISO nowmarket. MISO makes economic and routine dispatch decisions regarding Cleco Power’s generating units. Since joining MISO, powerPower purchases have beenare 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 willmay have a higher LMP.LMPs. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power’s pricing zone.zones. For information on Cleco Power’s ability to pass on to its customers substantially all of its fuel and purchased power expenses, see “—Regulatory Matters, Industry Developments, and Franchises—Franchises — Rates.”

For information on the cost benefit analysis of Cleco Power’s MISO membership, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Retail Rates of Cleco Power — MISO Cost Benefit Analysis.”

Coal, Petroleum Coke, and Lignite Supply

Cleco Power uses coal for generation at Rodemacher Unit 2. During 2016,2019, 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’s2, utilizing short-term spot 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.agreements. The coal supply agreements were fixed-price contracts. The remainder ofFor 2020, Cleco Power’sPower intends to meet its coal needs for 2017 willthrough short-term spot coal agreements which are expected to be met with spot purchases. With respect tofixed-price contracts. For the transportation of coal, Cleco Power’sPower had an agreement with Union Pacific Railroad Company for transportation ofto transport coal from Wyoming’s Powder River Basin to Rodemacher Unit 22. The transportation agreement was for three years and expired on December 31, 2016. A new transportation2019. On January 1, 2020, Cleco Power renewed its agreement with Union Pacific Railroad began on January 1, 2017,Company to continue this transportation agreement for a term of 3 years.three additional years, expiring December 31, 2022. Cleco Power leases 231115 railcars to transport its coal under two long-term leases, one expiring ina lease that expires on March 2017, under which management is evaluating future options, and the other expiring in31, 2021. A lease for 85 railcars expired on March 2021.

31, 2020.

The continuous supply of coal may be subject to interruption due to adverse weather conditions or other factors that may disrupt transportation to the plant site. At DecemberMarch 31, 2016,2020, Cleco Power’s coal inventory at Rodemacher Unit 2 was approximately 76,000138,000 tons (approximately a 32-day58-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 2016,2019, Cleco received its petroleum coke supply from multiple refineries located along the upper and lower Mississippi River with some spot cargo purchases being delivered from upper Mississippi refineries.River. Cleco purchased slightly more than one million600,000 tons of petroleum coke during 2016,2019, 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 completed2019. For 2020, Cleco has contracted for 810,000 tons of petroleum coke supply in 2017. Petroleum coke spot purchasesfrom multiple refineries located along the upper and lower Mississippi River through one-year agreements ending December 31, 2020. The agreements are typically short-term in nature, ranging from one-priced according to six-month terms. Each of the agreements is either a fixed price spot purchase or priced per theAdvisian Worley Group (formerly Jacobs ConsultancyConsultancy) Pace Petroleum Coke Quarterly Monthly Price Index or the “PACE” Monthly Index.

During 2016,2019, Cleco purchased approximately 268,000375,000 tons of Illinois Basin coal. Cleco Power uses Louisiana waterways, such as the Mississippi River and the Red River, to deliver both petroleum coke and Illinois Basin coal to the Madison Unit 3 plant site. The continuous supply of petroleum coke and Illinois Basin coal may be subject to interruption due to adverse weather conditions or other factors that may disrupt transportation to the plant site. Savage ServicesInland Marine is Cleco Power’s exclusive transportation coordinator and provider. The amended and restatedCleco Power has a 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.Inland Marine that is set to expire in March 2033. At DecemberMarch 31, 2016,2020, Cleco Power’s petroleum coke inventory at Madison Unit 3 was approximately 257,000333,000 tons and Cleco Power’s Illinois Basin coal inventory at Madison Unit 3 was approximately 95,000298,000 tons. The total fuel inventory was 352,000631,000 tons (approximately a 70-day111-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 conductedoperated 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.to meet projected dispatch needs. For information regarding deferred mining costs and obligations associated with this mining agreement see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 4—6 — Regulatory Assets and Liabilities—Liabilities — Mining Costs,” Note 15—““Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees—Guarantees — Off-Balance Sheet Commitments and Guarantees,” and “—Long-Term Purchase Obligations.Obligations,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Off-Balance Sheet Commitments and Guarantees.” For more information on Oxbow, see “Financial Statements and Supplementary Data—Data — Notes to the Audited the Financial Statements—Statements — Note 13—14 — Variable Interest Entities” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 13 — Variable Interest Entities.”

The continuous supply of lignite may be subject to interruption due to adverse weather conditions or other factors that may disrupt mining operations or transportation to the plant site. During 2019, the cost of lignite per MWh increased primarily due to the mine continuing to incur fixed costs, despite fewer tons of lignite mined compared to prior years. At DecemberMarch 31, 2016,2020, Cleco Power’s lignite inventory at Dolet Hills was approximately 251,000415,000 tons (approximately a 40-day66-day supply).

Natural Gas Supply

During 2016,2019, Cleco Power purchased 30.346.8 million MMBtu of natural gas for the generation of electricity. The annual and average per-day quantities of gas purchased by Cleco Power from each supplier are shown in the following table:
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NATURAL GAS SUPPLIER

 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
 

 

 

  

 

 

  

 

 

 

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

Natural gas was available without interruption throughout 2016.2019. Cleco Power expects to continue to meet its natural gas requirements with purchases on the spot market through daily, monthly, and seasonal contracts with various natural gas suppliers. However, future supplies to Cleco Power remain vulnerable to disruptions due to weather events and transportation issues. Large industrial users of natural gas, including electric utilities, generally have low priority among gas users in the event pipeline suppliers are forced to curtail deliveries due to inadequate supplies. As a result, prices may increase rapidly in response to temporary supply interruptions. During 2016,2019, in order to partially address potential natural gas fuel curtailments and interruptions, Cleco contracted for natural gas firm transportation with several interstate pipelines for a period of one year ending in late 2017. In2020. Additionally, in September 2019, Cleco Power completed the construction of the Coughlin Pipeline project. The new pipeline connects the Pine Prairie Energy Center to Cleco’s Coughlin Power Station. It is expected to increase reliability for natural gas delivery and mitigate exposure to transportation cost increases.
Cleco uses gas storage in order to supply gas to Cleco Power’s generating facilities in the event of an interruption of supply due to events of force majeure and to operationally balance gas supply to the units, gas storage will continue to be used.units. The storage volume is contracted by paying a capacity reservation charge at a fixed rate. There are also variable charges incurred to withdraw and inject gas from storage. At DecemberMarch 31, 2016,2020, Cleco Power had 1.71.4 million MMBtu of gas in storage. Currently, Cleco Power anticipates that its diverse supply options and 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 20162019 and 20152018 system peak demands, which occurred on August 2, 2016,September 6, 2019, and August 10, 2015,January 17, 2018, were 2,4902,492 MW and 2,7002,879 MW, respectively. Sales and system peak demand are affected by weather and are typically highest during the summer air-conditioning season; however, peaks may occur during the winter season as well. 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,condition, and cash flows, see “Risk Factors—Factors — Operational Risks — Future Electricity Sales” and “—Weather Sensitivity.” For information on the financial effects of seasonal demand on Cleco Power’s quarterly operating results, see “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 20—19 — Miscellaneous Financial Information (Unaudited).”

Reserve margin is the net capacity resources (either owned or purchased) less native load demand, divided by native load demand. Members of MISO submit their forecasted native load demand to MISO each year. During 2016,2019, Cleco Power’s reserve margin was 23.8%31.7%, which was above MISO’s unforced planning reserve margin
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benchmark of 7.6.%7.9%. During 2015,2018, Cleco Power’s reserve margin was 21.3%21.2%, which was also above MISO’s unforced planning reserve margin benchmark of 7.1%8.4%. Cleco Power expects to meet or exceed MISO’s unforced planning reserve margin benchmark of 7.8%8.9% in 2020. For more information on MISO, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Regulatory and Other Matters — Transmission Rates.”
Customers
Cleco Power did not have a significant customer that accounted for 10% or more of Cleco or Cleco Power’s consolidated revenue in 2019, 2018, or 2017.

For more information regarding Cleco Power’s sales and revenue, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

Capital Investment Projects

For a discussion of certain Cleco Power major capital investment projects, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Operations — Overview — Cleco Power—Layfield/Messick Project,” “—Cenla Transmission Expansion Project,” “—St. Mary Clean Energy Project,” “—Terrebonne toPower — Bayou Vista to Segura Transmission Project,”Project” and “—Coughlin Pipeline DSMART 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’sCleco Power’s capital expenditures, financing, and related matters, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations — Financial Condition—Condition — Liquidity and Capital Resources—Resources — Cash Generation and Cash Requirements—Requirements — Capital Expenditures.”
Cleco Cajun
Power Generation
On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in NRG South Central. As a result, Cleco Cajun became a new reportable segment. For more information about the Cleco Cajun Transaction, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 3 — Business Combinations” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 2 — Business Combinations.”
The following table sets forth certain information with respect to Cleco Cajun’s generating facilities:
GENERATING
STATION
COMMENCEMENT
OF COMMERCIAL
OPERATION
RATED
CAPACITY
(MW)
NET
CAPACITY
(MW)(1)
PRIMARY
FUEL USED
FOR
GENERATION
GENERATION
TYPE
Bayou Cove (2)
2002
225(5)
223(5)
natural gas
combustion
Big Cajun I
 
 
 
 
 
Unit 1 and Unit 2
1972
220
184
natural gas
steam
Unit 3 and Unit 4
2001
210
198
natural gas
combustion
Big Cajun II
 
 
 
 
 
Unit 1
1981
580
558
coal
steam
Unit 2
1982
540
574
natural gas
steam
Unit 3
1983
341(6)
334(6)
coal
steam
Cottonwood (3)
2003
1,263
1,155
natural gas
combined cycle
Sterlington (4)
1971 - 1975
176
99
natural gas
combustion
Total generating capability
 
3,555
3,325
 
 
(1)
Based on capacity testing of the generating units and operational tests performed between December 2018 and September 2019. These amounts do not represent generating unit capacity for MISO planning reserve margins.
(2)
Units 2, 3, and 4.
(3)
Units 1, 2, 3, and 4. Upon closing of the Cleco Cajun Transaction, Cottonwood Energy entered into the Cottonwood Sale Leaseback.
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For more information on the Cottonwood Sale Leaseback, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 4 — Leases — Lessor Agreements — Cottonwood Sale Leaseback Agreement” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 4 — Leases — Cottonwood Sale Leaseback Agreement.”
(4)
Units 1-4 and 6-10
(5)
Represents Cleco Cajun’s 225 MW ownership interest in the capacity of Bayou Cove, a 300-MW generating unit.
(6)
Represents Cleco Cajun’s 58% ownership interest in the capacity of Big Cajun Unit 3, a 588-MW generating unit.
Fuel and Purchased Power
Cleco Cajun uses coal and natural gas for its power generation resources. Cleco Cajun procures these fuels under contracts from a variety of suppliers and transporters. Cleco Cajun maintains an inventory of coal supply on-site at its coal generating facilities.
Sales
Cleco Cajun sells wholesale electric supply in Louisiana, Texas, and Arkansas. It furnishes supply to its wholesale customers primarily through all-requirements power supply and service agreements, which require Cleco Cajun to provide the electric capacity, energy, and other services necessary to serve most of its customers’ load requirements. Cleco Cajun procures the entirety of the power required to fulfill these obligations through its participation in the MISO market.
Cleco Cajun’s business experiences seasonality, as it bills its customers based on actual electric energy consumed. This usage tends to be greater during periods of high and low temperatures as compared to periods of moderate temperatures.
Competition
Competition for Cleco Cajun’s customers is limited through 2025, when the majority of the wholesale electric supply contracts terminate. Cleco Cajun currently intends to fully participate in co-operative requests for proposals for load after 2025. Within MISO, competitors typically comprise of investor-owned utilities, independent power producers, power marketers and power plant developers. These entities typically compete on the basis of price, reliability, and residual risk to the purchasing customer and its end users.
Customers
Cleco Cajun did not have a significant customer that accounted for 10% or more of Cleco’s consolidated revenue in 2019. For more information regarding Cleco Cajun’s sales and revenue, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”
Capital Expenditures and Financing
For information on Cleco Cajun’s capital expenditures, financing, and related matters, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Cash Generation and Cash Requirements — Capital Expenditures.”
REGULATORY MATTERS, INDUSTRY DEVELOPMENTS, AND FRANCHISES

Rates

Cleco Power’s electric operations are subject to the jurisdiction of the LPSC with respect to retail rates, standards of service, accounting, and other matters. 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.
Cleco Cajun is subject to the jurisdiction of FERC with respect to transmission tariffs, interconnections with other utilities, reliability, and the transmission of power. The rates Cleco, through Cleco Power and Cleco Cajun, charges its wholesale customers are subject to FERC’s triennial market power analysis.
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Cleco Power’s annual retail earnings are subject to an FRP that was approved by the LPSC in June 2014. Under the terms of an FRP established by the LPSC. Prior to July 1, 2014, Cleco Power’s current FRP, Cleco Power is 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 isare 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 allowsOn June 28, 2019, Cleco Power to request recovery of additional capital project costs during its four-year term. Cleco Power was scheduled to filefiled 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.

Cleco Power has responded to several sets of data requests relating to the new FRP.

Generally, theCleco Power’s cost of fuel used for electric generation and the cost of power purchased for utility customerspower 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. TheFor more information on the FAC and the most recent fuel audit, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC 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,Audits — Fuel Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC 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.

Audits — Fuel 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. 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,the EAC and the most recent EAC audit, see “Environmental Matters—Air Quality.“Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit.

On February 3, 2016,

For more information on 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 approvedstaff’s FRP reviews, amounts accrued by the LPSC on February 17, 2017. Cleco Power currently has EAC filings for 2016 subject to audit. Management is unable to predict or giveas a reasonable estimateresult of the possible range ofTCJA, and information on 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,tax dockets, see “Financial Statements 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 responsesSupplementary Data — Notes to the non-confidential requestsAudited Financial Statements — Note 13 — Regulation and is waiting on the completion of a confidentiality agreement to respondRates — FRP,” “— TCJA,” “Financial Statements and Supplementary Data — Notes 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.

Unaudited Interim Financial Statements — Note 12 — Regulation and Rates — FRP” and “— TCJA.”

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

Franchises

Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state law. These franchises are for fixed terms, which vary from 10 years to more than 50 years. Historically, Cleco Power has been substantially successful in the timely renewal of franchises as each neared the end of its term. Cleco Power’s next municipal franchise expires in August 2020.

April 2022.

Franchise Renewals

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

in 2019:
RENEWAL DATE

DATE

CITY/TOWN/VILLAGE
TERM
TERM
NUMBER OF
CUSTOMERS
March 2015
January 2019
Zwolle
Jeanerette
30
22 years
914
2,849
May 2015
June 2019
Merryville
Loreauville
30
27 years
454
384
June 2015
July 2019
Eunice
Opelousas
33
10 years
5,190
9,604
July 2015
December 2019
Converse
Evergreen
30
27 years
233
July 2015Madisonville34 years598
August 2015Pleasant Hill30 years382
September 2015Noble30 years108
September 2015Plaucheville30 years147
May 2016Elizabeth10 years*219
July 2016McNary30 years89
214
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*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—Operations — Financial Condition—Condition — Regulatory and Other Matters—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—Operations — Financial Condition—Condition — Regulatory and Other Matters—Matters — Market Restructuring—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—Operations — Financial Condition—Condition — Regulatory and Other Matters—Matters — Market Restructuring—Restructuring — Retail Electric Markets.”

Legislative and Regulatory Changes and Matters

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

the ability of electric utilities to recover stranded costs,

the impact of the TCJA on regulated public utilities,
the role of electric utilities, independent power producers, and competitive bidding in the purchase, construction, and operation of new generating capacity,

the role of electric utilities and independent transmission providers in competitive bidding in the construction of new transmission facilities,
the pricing of transmission service on an electric utility’s transmission system, or the cost of transmission services provided by an RTO/ISO,
FERC’s assessment of market power and a utility’s ability to buy generation assets,

mandatory transmission reliability standards,

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, and

FERC’s increased ability to impose financial penalties, andpenalties.

the Dodd-Frank Act.

ManagementAt this time, 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.

Cleco.

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

ENVIRONMENTAL MATTERS

Environmental Quality

Cleco is subject to federal, state, and local laws and regulations governing the protection of the environment. Violations of these laws and regulations may result in substantial fines and penalties. Cleco has obtained the environmental permits necessary for its operations, and management believes Cleco is in compliance in all
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material respects with these permits, as well as all applicable environmental laws and regulations. Environmental requirements affecting electric power generating facilities are complex, change frequently, and have become more stringent over time as a result of new legislation, administrative actions, and judicial interpretations. Therefore, the capital costs and other expenditures necessary to comply with existing and new environmental requirements are difficult to determine. Cleco Power may request recovery of the costs to comply with certain environmental laws and regulations from its retail customers. If revenue relief were to be approved by the LPSC, then Cleco Power’s retail rates could increase. If the LPSC were to deny Cleco Power’s request to recover all or part of its environmental compliance costs, then Cleco Power would bear those costs directly. Such a decision could negatively impact perhaps significantly, the results of operations, financial condition, or cash flows of the Company.Cleco. For Cleco Power’s expected capital expenditures including AFUDC, related to environmental compliance were $6.4 million during 2016in 2020, see “Management’s Discussion and are estimated to be $4.5 million in 2017.

Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Cash Generation and Cash Requirements — Capital Expenditures.”

Air Quality

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

The EPA has proposed and adopted rules under the authority of the CAA relevant to the emissions of SO2 and NOx from Cleco’s generating units. The CAA contains a regional haze program with the goal of returning certainClass I Federal areas of the nation to natural visibility by 2064. States are required to develop regional haze State Implementation Plans (SIP)(“SIP”) and revise them every ten years. A SIP must include several components, including requirements for the installation of Best Available Retrofit Technology (BART)(“BART”) for eligibleapplicable EGUs in Louisiana. The LDEQ now must determine whatEPA issued a final approval of the BART requirements will be for BART-eligible EGUsLouisiana SIP in December 2017. Although the approval was appealed to the United States Court of Appeals for the controlFifth Circuit by the Sierra Club and the National Parks Conservation Association, the court denied all the challenges to the EPA’s approval of SO2the Louisiana Regional Haze SIP. Because the Louisiana SIP mandates use of existing controls and NOx.participation in the Cross State Air Pollution rule as BART, Cleco does not believe the Louisiana SIP will have a material impact on the results of operations, financial condition, or cash flows of Cleco. The second planning period for the regional haze program will take place in 2021-2028. The SIP is due to be submitted to the EPA by July 31, 2021. Until the LDEQ determines what BARTthe reasonable progress requirements are for Cleco units and completes its update of the SIP, Cleco is unable to predict if the adopted rules will have a material impact on the results of operations, financial condition, or cash flows of the Company. Cleco.
The CAA also established the Acid Rain Program to address the effects of acid rain and imposed restrictions on acid rain-causing SO2 emissions from certain generating units. The CAA requires these EGUs to possess a regulatory “allowance”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 20162019 and expects to have sufficient allowances for 20172020 operations under the Acid Rain Program.

The Acid Rain Program also established emission rate limits on NOx emissions for certain generating units. Cleco Power is able to achieve complianceCompliance with the acid rain permit limits for NOx has been achieved 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 NOx 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 NOx 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 NOx 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 onin October 26, 2016 with publication in the Federal Register. The EPA proposed Federal Implementation Plans (FIP)(“FIP”) that update the existing EGU CSAPR NOx ozone seasonozone-season emission budgets and implement the budgets through the existing CSAPR NOx ozone-season allowance trading program. The FIP requiresrequired implementation beginningbegan with the 2017 ozone season. Management doesCleco is in compliance with the revised FIP rules. These rules did not believehave a material impact on the results of operations, financial condition, or cash flows of Cleco.
In October 2015, the EPA promulgated a revision to the 2015 ozone NAAQS, lowering the level of both the primary and secondary standards to 70 ppb. Under the CAA, each state is required to submit a SIP that provides for the implementation, maintenance and enforcement of each primary and secondary NAAQS. In particular, each SIP must contain adequate provisions prohibiting emissions activity within the state which will contribute significantly to non-attainment or interfere with maintenance by any other state with respect to any such primary or secondary ambient air quality standard. This “good neighbor” SIP is to be submitted to the EPA by the state
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within three years of promulgation of a new or revised NAAQS. The EPA determined that the SIP submittal by Louisiana meets the SIP completeness criteria. Cleco is in compliance with the rule. This rule did not have a material impact on the results of operations, financial condition, or cash flows of Cleco.
For more information on the legal proceedings of the MATS ruling, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit” and “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — LPSC Audits — Environmental Audit.”
On February 7, 2019, the EPA published in the Federal Register a proposed rule titled National Emission Standards for Hazardous Air Pollutants: Coal-and Oil-Fired Electric Utility Steam Generating Units — Reconsideration of Supplemental Findings and Residual Risk and Technology Review. The EPA proposes to find, after considering the cost of compliance relative to the hazardous air pollutant (“HAP”) benefits, that regulation of HAP emissions under section 112 of the CAA is not appropriate and necessary which would reverse the EPA’s prior conclusions. However, the EPA further proposes that this new determination will not remove the Coal-and Oil-Fired source category from the CAA list of sources that must be regulated and will not affect the existing HAP emissions standards. In addition, the proposal presents the results of the required residual risk and technology review which indicate that residual risks due to HAP emissions from this source category are acceptable and that the current standards provide an ample margin to protect human health. However, until the EPA has finalized the proposal, Cleco cannot predict the potential impacts of the final rule.
On April 12, 2019, the EPA published in the Federal Register proposed amendments to the National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines to address the results of the required periodic residual risk and technology review of the regulations. The EPA is proposing to find that risks from this source category due to air toxics emissions are acceptable and that the existing rule provides an adequate margin of safety to protect public health. The EPA also identified no new cost-effective controls under the technology review that would achieve further emissions reductions from the source category. In addition, the EPA is proposing through this rulemaking to remove the stay of effectiveness of the emission standards for new lean premix and diffusion flame gas-fired turbines that was promulgated in 2004. If the lifting of the stay were to be finalized as proposed, an emission limit for formaldehyde could be applied to new or reconstructed lean premix and diffusion flame turbines. Until the EPA has finalized the rule, Cleco cannot determine if the rule will have a material impact on the results of operations, financial condition, or cash flows of 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

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.

Cleco.

In August 2015, the EPA released the final guidelines referred to as the CPP. These guidelines provide each state with standards for CO2 emissions from the state’s utility industry. The EPA derived the limits for each state through a strategy involving a combination of unit efficiency improvements, dispatching away from boilers to combined cycle units, and applying renewable energy. The CPP requires significant reductions of CO2 emissions. The CPP sets interim and final CO2 emission goals for each state. The interim emission goals begin in 2022, with final emission goals required by 2030. The rule is currently under review by electric utilities and state regulators. OnIn February 9, 2016, the U.S.United States Supreme Court issued a stay of the CPP which will stayto remain in place until the D.C. Circuit Court of Appeals rulesruled on the merits followed by a U.S.and any ruling from the United States 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.

Court.

In August 2015, the EPA released the New Source Performance Standards (NSPS)(“NSPS”) rules for CO2 emissions from new, modified, or reconstructed units. The rules set requirements and conditions with respect to CO2 emission standards for new units and those that are modified or reconstructed. Cleco does not anticipate a modification or reconstruction of its existing sources that would trigger the application of the CO2 emission limits.
In March 2017, the President of the United States signed a broad executive order. Among other measures, the order directed the EPA to review the CPP, the proposed FIP for the CPP, and the greenhouse gas new source performance standards (GHG NSPS). On July 8, 2019, the EPA published in the Federal Register a final rule to replace the CPP, formally titled Repeal of the CPP: Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations and informally known as the Affordable Clean Energy, or ACE, Rule. The state agency will have to set standards of performance for each affected generating unit and submit the implementation plan to the EPA for approval by
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July 8, 2022, with compliance expected within 24 months thereafter. Until the state agency has set standards for the affected generating units, management cannot determine the future regulatory requirements and impact on Cleco’s existing affected units or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.
In December 2018, following a review as directed by the President of the United States, the EPA published proposed rules to replace the August 2015 NSPS rules for CO2 emissions from new, modified, or reconstructed units. As with the current NSPS rules, the proposed rules set requirements and conditions with respect to CO2 emission standards for new, modified, or reconstructed units. Cleco does not anticipate a future modification or future reconstruction of its existing units, as defined in the proposal, that would trigger the application of the proposed CO2 emission limits.

Until the EPA finalizes the rule, management cannot state what the final standards will entail or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of Cleco.

Until all directions of the executive order are carried out, management cannot predict what the final standards will entail or what controls the EPA and the state of Louisiana may require of Cleco in a final state implementation plan for existing units. However, any new rules that require significant reductions of CO2 emissions could require significant capital expenditures or curtailment of operations of certain EGUs to achieve compliance.
The enactment of federal or state renewable portfolio standards (RPS)RPS mandating the use of renewable and alternative fuel sources such as wind, solar, biomass, and geothermal energy could result in certain changes in Cleco’s

business or its competitive position. These changes could include additional costs for renewable energy credits, alternate compliance payments, or capital expenditures for renewable generation resources. RPS legislation has been enacted in many states, and Congress is considering various bills that would create a national RPS. Cleco continues to evaluate the impacts of potential RPS legislation on its business based on the RPS programs in other states.

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 effectbecame effective in April 2010. The EPA established a new one-hour standard at a level of 100 ppb to supplement the existing annual standard. In January 2012, the EPA determined that no area in the country was violating the standard. However,In April 2018, the LDEQ expects to operate new monitors at two portionsEPA published, following the required review of highways in the Baton Rouge and New Orleans areas.NAAQS, a final action that retains the ambient air standards for NO2. The EPA may redesignate areas based on new data it receives from states. Due to the fact that fossil fuel-fired EGUs are a significant source of NO2 emissions in the country, a non-attainment designation could result in utilities such as Cleco being required to substantially reduce itstheir 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 notifiedJanuary 2018, the EPA that DeSoto Parish was in compliance with the NAAQS SO2requirement and recommendedpublished a designation of attainment. In February 2016, the EPA responded indicating that it intends to classify a portion of DeSoto Parishfinal rule designating all areas containing Cleco generation facilities 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,either attainment/unclassifiable or unclassifiable. Therefore, there is no adverse impact to Cleco’s generating units.

In the past, Cleco Power received notices from

On March 18, 2019, the EPA requesting information relatingpublished, following the required review of the NAAQS, a final action that retains the ambient air standards for SO2. The EPA may redesignate areas based on new data it receives from states. Due to the Brame Energy Centerfact that fossil fuel-fired EGUs are a significant source of SO2 emissions in the country, a non-attainment designation could result in utilities such as Cleco being required to substantially reduce their SO2 emissions. However, because the EPA has not yet completed any new designations, Cleco cannot predict the likelihood or potential impacts of such a rule on its generating units at this time.
On May 2, 2019, Louisiana Generating notified the EPA and the Dolet Hills Power Station. The purpose ofLDEQ that it has elected not to Retrofit (as such term is defined in 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.

Consent Decree) Big Cajun II, Unit 1.

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)(“CWA”) for
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wastewater discharges from its generating stations. Wastewater discharge permits have fixed dates of expiration, and Cleco applies for renewal of these permits within the applicable time periods.

In March 2011, the EPA proposed regulations which would establish standards for cooling water intake structures at existing power plants and other facilities pursuant to Section 316(b) of the CWA. The EPA published its final rule in August 2014. The standards are intended to protect fish and other aquatic wildlife by minimizing capture, both in screens attached to intake structures (impingement mortality), and in the actual intake structures themselves (entrainment mortality). The proposed standards would (1) set a performance standard, dealing with fish impingement mortality or reduce the flow velocity at cooling water intakes to less than 0.5 feet per second and (2) require entrainment standards to be determined on a case-by-case basis by state-delegated permitting authorities. Facilities subject to the proposed standards are required to complete a number of studies within a 45-month period and then comply with the rule as soon as possible after the next discharge permit renewal, by a date determined by the permitting authorities. Portions of the final rule could apply to a number of Cleco’s fossil fuel steam electric generating stations. Until the required studies are conducted, including technical and economic evaluations of the control options available, and regulatory agency officials have reviewed the studies and made determinations, Cleco remains uncertain as to which technology options or retrofits will be required to be installed on its affected facilities. The costs of required technology options and retrofits may be significant, particularly if closed cycle cooling is required.

The CWA requires the EPA to periodically review and, if appropriate, revise technology-based effluent limitations guidelines for categories of industrial facilities, including power generating facilities. In SeptemberNovember 2015, the EPA released the revised steam electric effluent limitation guidelines.Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category rule (“ELG rule”). The rule is focused on reducing the discharge of metals in wastewater from generating facilities to surface waters. In April 2017, the EPA administrator indicated that it is appropriate and in the public interest to reconsider the rule.
In September 2017, the EPA published a rule postponing for a two year period the earliest compliance dates for some of the wastewater streams that fall under the rule. On November 22, 2019, the EPA published proposed revisions to the ELG rule that would revise the technology-based effluent limitations guidelines and standards applicable to flue gas desulfurization and bottom ash transport waste waters. The rule may require costly technological upgrades at Cleco’s facilities, particularly if additional wastewater treatment systems are required to be installed or if waste streams must be eliminated. Management is currently evaluatingUntil the effect ofEPA finalizes the rule, management cannot predict what the final rulestandards will entail, what controls the EPA and is not able to predictthe state of Louisiana may require of Cleco, or if the new rule will have a material impact on the results of operations, financial condition, or cash flows of the Company.

Cleco.

Solid Waste Disposal

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

In April 2015, the EPA published a final rule in the Federal Register for regulating the disposal and management of CCRs from coal-fired power plants.plants (“CCR rule”). The federal regulation classifies CCRs as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act and allows beneficial use of CCRs with some restrictions. The rule establishes extensive requirements for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. ManagementIn September 2017, the EPA administrator indicated that it is currently evaluatingappropriate and in the effectpublic interest to reconsider the provisions of the final CCR rule. In August 2018, the Court of Appeals for the D.C. Circuit vacated several requirements in the CCR rule requirementswhich included eliminating the previous acceptability of compacted clay material as a liner for impoundments. As a result, on December 2, 2019, the EPA published a proposed rule titled Hazardous and is not ableSolid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; A Holistic Approach to predictClosure Part A: Deadline To Initiate Closure. The proposed regulation would set deadlines for costly modifications including retrofitting of clay-lined impoundments with compliant liners or closure of the impoundments. Until the EPA has finalized the regulation, management cannot determine if the rule will have a material impact on the results of operations, financial condition, or cash flows of the Company.Cleco.
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Cleco Power continues to be subject to state regulations pertaining to the disposal of coal ash. As a result, Cleco Power has an ARO for the retirement of certain ash disposal facilities. As part of the Cleco Cajun Transaction, Cleco recognized $15.3 million of AROs primarily related to the retirement of Cleco Cajun’s ash management areas. All costs of the CCR rule for Cleco Power are expected to be recovered from its customers in future rates. The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to the

uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. Cleco 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 balancebalances 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.Cleco. At December 31, 2016,2019, management’s analysis confirmed that no additional adjustments were needed to update Cleco or Cleco Power’s ARO balance.

On

In December 16, 2016, the Water Infrastructure Improvements for the Nation Act (WIIN Act)(“WIIN Act”), including the WIIN Act’s provisions regarding CCRs was signed into law. The WIIN Act’s CCR provisions allow for implementation of the federal CCR rule through a state-based permit program. However, until the state of Louisiana has evaluated the WIIN Act and made a decision on implementing a state-based option, Cleco cannot determine if the effects of the Actrule will have a material impact on the Company.

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

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

Toxic Substances Control Act (TSCA)

(the “TSCA”)

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

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

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

Electric and Magnetic Fields (EMFs)

(“EMFs”)

The possibility that exposure to EMFs emanating from electric power lines, household appliances, and other electric devices may result in adverse health effects and damage to the environment has been a subject of some public attention. Lawsuits alleging that the presence of electric power transmission and distribution lines has an adverse effect on health and/or property values have arisen in several states. Neither Cleco nor Cleco Power is not a partyare parties 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 more information on Cleco Power’s generating facilities, see “Business—Operations—“Business — Operations — Cleco Power—Power — Power Generation.”

Electric Generating Stations

As of DecemberMarch 31, 2016,2020, Cleco Power either owned or had an ownership interest in fivesix steam electric generating stations, three combined cycle units, and one gas turbine with a combined nameplate capacity of 3,3103,360 MW, and a combined electric net generating capacity of 3,1683,214 MW. The nameplate capacity is the capacity at the start of commercial operations, and the net generating capacity is the result of capacity tests and operational tests performed during 2016,2019, as required by MISO. This amount reflects the maximum production capacity these units can sustain over a specified period of time. For more information on Cleco Power’s generating facilities, see “Business—Operations—“Business — Operations — Cleco Power—Power — Power Generation.”

Electric Substations

As of DecemberMarch 31, 2016,2020, Cleco Power owned 8486 active transmission substations and 219249 active distribution substations.

Electric Lines

As of DecemberMarch 31, 2016,2020, Cleco Power’s transmission system consisted of 67 circuit miles of 500-kiloVolt (kV)500kV lines; 549561 circuit miles of 230-kV lines; 672 circuit miles of 138 kV lines; and 29 circuit miles of 69-kV lines. As of March 31, 2020, Cleco Power’s distribution system consisted of 3,6233,398 circuit miles of 34.5-kV lines and 8,3128,718 circuit miles of other lines.

General Properties

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

Title

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

Substantially all of Cleco Power’s property, plant, and equipment are subject to a lien ofunder Cleco Power’s Indenture of Mortgage, which does not impair the use of such properties in the operation of its business. As of DecemberMarch 31, 2016,2020, no mortgage bonds were outstanding under the Indenture of Mortgage. Some of the unsecured and unsubordinated indebtedness of Cleco Power will be effectively subordinated to, and thus have a junior position to, any mortgage bonds that Cleco Power may have outstanding from time to time with respect to the assets subject to the lien of the Indenture of Mortgage. Cleco Power may issue mortgage bonds in the future under its Indenture of Mortgage, and holders of mortgage bonds would have a prior claim on certain Cleco Power material assets upon dissolution, winding up, liquidation, or reorganization.
CLECO CAJUN
Cleco Cajun has electric generating stations and electric operating properties located in Louisiana and Texas. Cleco Cajun considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For more information on Cleco Cajun’s generating facilities, see “Business — Operations — Cleco Cajun.”
Electric Generating Stations
As of March 31, 2020, Cleco Cajun has ownership interest in five electric generating stations which, combined, consist of 14 gas turbine units and five steam electric generating units located in Louisiana as well as four combined cycle units located in Texas. These generating facilities have a combined rated capacity of 3,555 MW. For more information on Cleco Cajun’s generating facilities, see “Business — Operations — Cleco Cajun.”
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General Properties
Cleco Cajun owns various properties throughout Louisiana, which include a regional office, telecommunications equipment, and other general-purpose assets.
Title
Cleco Cajun’s assets are owned in fee simple and are not subject to non-ordinary course of business liens or encumbrances.
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LEGAL PROCEEDINGS

CLECO

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

RISK OVERVIEW

Market

Cleco is exposed to counterparty credit risk, inherent in Cleco’s market risk-sensitive instruments and positions includes potential changes in value arising from changes inliquidity risk, 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 marketrate 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 pricesprice risk. Cleco has implemented a governance framework, inclusive of power, FTRs,risk policies and natural gas. Management’s views on marketprocedures to manage these and other risks.

Counterparty Credit Risks
When Cleco enters into bilateral commodity derivative or physical commodity transactions, Cleco may be exposed to counterparty credit risk. Cleco is exposed to counterparty credit risk are not necessarily indicative of actual results, nor do they represent the maximum possible gains orwhen a counterparty fails to meet their financial obligations causing Cleco to incur replacement losses. The views do represent, within the parameters disclosed, what management estimates may happen.

Cleco maintains a master netting agreement policymonitors and monitorsmanages its credit risk exposure through reviewscredit risk management policies and procedures that include:
routine reviewing of counterparty credit quality aggregate counterpartyand credit exposure,
entering into standard industry master agreements with specific terms and conditions for credit exposure and aggregate counterparty concentration levels. Cleco manages these risks by establishing appropriate creditnon-performance, and concentration limits on transactions with counterparties
exchanging guarantees or forms of cash equivalent collateral for financial assurance.
For more information, see “Management’s Discussion and requiring contractual guarantees, cash deposits, or lettersAnalysis of credit from counterparties or their affiliates, as deemed necessary. Cleco Power has agreements in place with various counterparties that authorize the nettingFinancial Condition and Results of financial buysOperations — Financial Condition — Liquidity and sellsCapital Resources — General Considerations and contract payments to mitigate credit risk for transactions entered into for risk management purposes.

Credit-Related Risks.”

Liquidity Risks
Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows. Future actions or inactions of the federal government, including a failure to increase the government debt limit, could increase the actual or perceived risk that the U.S.United States may not pay its obligations when due and may disrupt financial markets, including capital markets, potentially limiting availability and increasing costs of capital. The inability to raise capital on favorable terms could negatively affect Cleco’s ability to maintain and expand its businesses. After assessing the current operating performance, liquidity, and credit ratings of Cleco Holdings and Cleco Power, management believes that Cleco will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. Cleco Holdings and Cleco Power pay fees and interest under their respective credit facilities based on the highest rating held. On April 8, 2016, S&PFor more information, see “Management’s Discussion and Moody’s updated the credit ratings for Cleco HoldingsAnalysis of Financial Condition and Cleco Power, taking into consideration the anticipated completionResults of the Merger. S&P credit ratings were maintained at Cleco Power at BBB+ (stable)Operations — Financial Condition — Liquidity and downgraded at Cleco Holdings to BBB- (stable). Moody’s credit ratings were maintained at Cleco Power at A3 (stable)Capital Resources — General Considerations 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.

Credit-Related Risks.”

Interest Rate Risks

Cleco monitors its mix of fixed- and variable-rate debt obligations in light of changing market conditions and from time to time may alter that mix, for example, by refinancing balances outstanding under its variable-rate credit facility with fixed-rate debt. 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.

At DecemberMarch 31, 2016, Cleco had no short-term variable-rate debt outstanding.2020, Cleco Holdings had no borrowings$88.0 million of short-term debt outstanding under its $100.0$175.0 million credit facility.facility at an all-in interest rate of 2.50%. 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 DecemberMarch 31, 2016,2020, Cleco Holdings had a $300.0$330.0 million long-term variable rate bank term loanloans outstanding. Amounts outstanding under theOne bank term loan bearhas a balance of $300.0 million outstanding, at an interest atrate of LIBOR plus 1.625%. At December, for an all-in interest rate of 2.275% at March 31, 2016, the2020. Another bank term loan has a balance of $30.0 million outstanding, at an interest rate of LIBOR plus 1.625%, for an all-in interest rate of 2.275% at March 31, 2020. The weighted average rate for all outstanding term loan debt was 2.265%3.11%. Each 1% increase in the all-in interest rate applicable to suchCleco’s short- and long-term variable rate debt would result in a decrease in Cleco’sCleco Holdings’ pretax earnings of $3.0$4.2 million.
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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

At March 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.

At December 31, 2016,2020, Cleco Power had no short- or long-term variable-rate debt.

At December 31, 2016, Cleco Power had no borrowings$150.0 million of short-term debt outstanding under its $300.0 million credit facility. Thefacility at an all-in interest rate of 1.875%. Cleco Power’s borrowing costs under the Cleco Powerits $300.0 million credit facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%.

Please refer Each 1% increase in the interest rate applicable to “—Cleco Power’s short-term debt would result in a decrease in Cleco Power’s pretax earnings of $1.5 million.

Cleco may enter into contracts to mitigate the volatility in interest rate risk. These contracts include, but are not limited to, interest rate swaps and treasury rate locks. For each reporting period presented, Cleco did not enter into any contracts to mitigate the volatility in interest rate risk.
Commodity Price Risks”Risks
Cleco Power and Cleco Cajun’s financial performance can be impacted by changes in commodity prices that impact fuel costs, generation revenues, and customer supply and revenue. Cleco’s Energy Market Risk Management Policy authorizes hedging commodity price risk with physical or financially settled derivative instruments within approved guidelines and limits of authority. Some of these transactions may qualify for the normal purchase, normal sale (“NPNS”) exception under derivative accounting guidance. Contracts that do not qualify for NPNS accounting treatment or are not elected for NPNS accounting treatment are marked-to-market and recorded on the balance sheet at their fair value.
Cleco Power and Cleco Cajun, individually, may be exposed to transmission congestion price risk as a discussionresult of controls, transactions,physical transmission constraints present between MISO LMP nodes when serving customer load. Cleco Power and Cleco Cajun are awarded and/or purchase FTRs in auctions facilitated by MISO. FTRs are accounted for as derivatives not designated as hedging instruments for accounting purposes.
During 2019, Cleco Cajun entered into other commodity derivative contracts including fixed price physical forwards and swap transactions. During the three months ended March 31, 2020, Cleco Cajun entered into other commodity derivative contracts including fixed price physical forwards and financially settled swap transactions.
The following tables present the fair values of derivative instruments and their respective line items as recorded on Cleco’, Consolidated Balance Sheet at March 31, 2020:
Cleco
DERIVATIVES NOT DESIGNATED AS
HEDGING INSTRUMENTS
(THOUSANDS)
BALANCE SHEET
LINE ITEM
AT MARCH 31, 2020
Commodity-related contracts
FTRs
Current
Energy risk management assets
$1,779
Current
Energy risk management liabilities
(683)
Other commodity derivatives
Current
Energy risk management assets
213
Current
Energy risk management liabilities
(9,014)
Non-current
Other deferred credits
(3,480)
Commodity-related contracts, net
$(11,185)
Cleco monitors the Value at Risk (“VaR”) of its other commodity derivative contracts requiring derivative accounting treatment. Cleco applies a parametric VaR covariance analytical approach within a 5-day holding period at a 95% confidence interval. VaR is defined as the minimum expected loss over a given holding period at a given confidence level based on observable market price volatilities.
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The following table presents the VaR of other commodity derivative contracts for the three months ended March 31, 2020, as well as the VaR at March 31, 2020, based on these assumptions:
 
 
FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)
AT MAR. 31, 2020
HIGH
LOW
AVERAGE
Cleco
$4,558
$4,997
$2,087
$4,264
For more information on the accounting treatment and marketfair value maturities associated with Cleco Power’s energyof FTRs and other commodity activities.

derivatives, see “Financial Statements and Supplementary Data — Notes to the Audited Financial Statements — Note 2 — Summary of Significant Accounting Policies — Derivatives and Other Risk Management Activity,” “Note 8 — Fair Value Accounting — Commodity Contracts,” “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies — Derivatives and Other Risk Management Activity” and “Note 7 — Fair Value Accounting — Commodity Contracts.”

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

None.
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None.

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)

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)

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

As of May 22, 2020, the Board of Managers of Cleco Holdings is comprised of 12 managers, as set forth below. Cleco Power’sThe Board of Managers of Cleco Power is comprised of 13 managers, including the same 12 managers that comprise the BoardsBoard of Managers of Cleco Group and Cleco Holdings, plus one additional manager, Melissa Stark. The Board of Managers of Cleco Holdings and the Board of Managers of Cleco Power are collectively referred to below as “the Boards.” The managers’ ages, dates of election,appointment, employment history, and committee assignments as of FebruaryMay 22, 2017,2020, are also set forth below.

David Agnew Each of Ms. Scott and Messrs. Gallot, Gilchrist, and Wainer serve pursuant to one-year agreements which are considered for renewal annually by the Boards. Mr. Fontenot serves by virtue of his position as the CEO, and the other managers are designated for membership by BCI, John Hancock Financial, or MIRA.

Andrew Chapman joined MIRA in 2006. During his 13 years with MIRA, Mr. Chapman has served as a director of utility companies owned in part by MIRA’s funds, including Puget Sound Energy, Duquesne Light Company, Aquarion Water Company, Cleco, and entities related to those holdings. Along with Cleco, he now serves on the board for the entity holding Lordstown Energy Center, a gas-fired power plant in eastern Ohio. Mr. Chapman is employed by MIRA and acts as MIRA’s liaison with federal, state and local governments in the United States. Mr. Agnew is 5165 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 chairChair of the Business Planning and Budget Review Committee and a member of the Asset Management Committee, the Leadership Development and Compensation Committee, the Governance and Public Affairs Committee and the Audit Committee. Mr. Chapman 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.

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

Richard Dinneny

William “Bill” Fontenot has served as the President and CEO of Cleco Holdings since January 2018 and CEO of Cleco Power since February 2019. Mr. Fontenot is 57 years old and was appointed to the Boards in 2018. He is a member of the Asset Management Committee, the Business Planning and Budget Review Committee, and the Governance and Public Affairs Committee. During Mr. Fontenot’s 33 years of service, he managed the development and restructuring efforts of generation projects valued at over $900.0 million, as well as led the development and construction of the $1.0 billion power plant, Madison Unit 3. His previous background was in marketing and the development of merchant power businesses.
Mr. Fontenot serves on the boards of the Council for a Better Louisiana, Association of Edison Illuminating Companies, Southeastern Electric Exchange, and the Central Louisiana Community Foundation. He is a member of St. Rita Catholic Church.
Mr. Fontenot holds a Bachelor’s of Science degree in electrical engineering from Louisiana State University.
Paraskevas “Paris” Fronimos is a Senior Portfolio Manager,Principal on the Infrastructure and Renewable Resources for bcIMC, where he has responsibility for all aspectsResource Investments team of investing in infrastructure transactions.BCI. He is 5445 years old and became a member of the Boards of Managers in 2016.2019. Mr. DinnenyFronimos 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 chairChair of the Asset Management Committee and a member of the Business Planning and Budget Review Committee.

Mr. FayFronimos joined BCI in 2017 and works with the Macquarie Group in 2003, workingmanagement teams of portfolio companies to unlock and deliver shareholder value. He is primarily engaged with energy and utility companies in the Risk Management division. In 2005, he transferredAmericas, serving as a Director of Tribus Services Inc., a United States utility services company, an Alternate Director of Nova Transportadora do Sudeste, a Brazilian natural gas pipeline, and an Alternate Director of Isagen, a Colombian power producer. Prior to MIRA, where heBCI, Mr. Fronimos was partemployed by Nova Scotia Power, a Canadian power utility, as a fuels portfolio manager. He has more than 15 years of experience in the team that acquired a major ownership interest in a leading Australian retirement home business,energy and subsequently became the asset managerutilities space, having worked on environmental and then led the successful divestiture of the business. From 2008 until 2012, energy policy, developing greenfield energy projects, advising on transactions, and driving fleet and fuel supply optimization activities, including commodity pricing and hedging.
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. FayFronimos holds a Bachelorbachelor’s degree in Mineral Resources Engineering from the Technical University of CommerceCrete and a Master’s in Business Administration (specializing in Natural Resources and Energy) from Monashthe University where he majored in Finance with minors in Accounting and Economics.

of Alberta. He is an Energy Risk Professional (ERP®) certified by the Global Association of Risk Professionals.

Richard “Rick” Gallot, Jr. is the President of Grambling State University. He is 5054 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.
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Mr. Gallot serves on the board of Origin Bancorp, Inc. (Nasdaq: OBNK). He recently served as a Louisiana state senator for District 29, where he held the position of vice-chairmanVice-chair of the Commerce Committee and was a member of the Agriculture, Forestry, Aquaculture, and Rural Development Committee and the Revenue and Fiscal Affairs Committee. He previously served as a member of the Louisiana House of Representatives for District 11, where he served as chairChair 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.

Law and has been a licensed Louisiana Attorney since 1990.

David Randall “Randy” Gilchrist is the President and CEO of Gilchrist Construction Company (GCC)(“GCC”), a central Louisiana-based infrastructure contractor specializing in road and bridge construction. He is 5760 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 presidentPresident of Associated General Contractors, chairmanChair of Driving Louisiana Forward, chairmanChair of the Central Louisiana Chamber of Commerce, and vice chairmanVice Chair of Central Louisiana Economic Development Alliance. He has also served on the boards of The Rapides Foundation and Rapides Healthcare System.

Recep Kendircioglu

Gerald Hanrahan is a Managing Director at John Hancock Financial Services inSenior Industry Advisor to the Power and Infrastructure Group. HeTeam at John Hancock. The Power and Infrastructure Team is 41responsible for transactions in public utility, independent power project and infrastructure financing areas for John Hancock and manages a portfolio of over $21.0 billion in assets spanning over 300 individual investments. Mr. Hanrahan is 59 years old and became a member of the Boards of Managers in 2016. Mr. Kendircioglu2018. He is a member of the Asset Management Committee.

Mr. KendirciogluHanrahan joined John Hancock as a director in 2007,2001, served as managing director from 2003 to 2011, and served as Team Leader - Vice President from 2011 until 2016. He has worked in the financing area of the power industry since 1990. Before joining John Hancock, Mr. Hanrahan worked for four years in the Boston and London offices of InterGen, where he is responsible for the originationcoordinated all financing activities on $2.7 billion in power projects in Turkey, Colombia and execution of debt and equity investmentsEgypt. Before that, he spent nine years in the infrastructurestructured finance and utility sectors.

financial advisory divisions of Bank of Tokyo Capital Corporation in Boston.

Mr. KendirciogluHanrahan holds a Masters inof Business Administration from Rice University. He is a Chartered Financial Analyst, a certified Financial Risk ManagerBabson College and a memberBachelor’s of the Boston Security Analysts Society.

Science degree from Northeastern University.

Christopher Leslie is Executive Chairman of MIRA Americas. Prior to taking that role in July 2016, Mr. Leslie was the CEO of MIP,Macquarie Infrastructure Partners Inc. (“Macquarie”), the manager of MIRA’s U.S.-basedUnited States-based private infrastructure funds, Macquarie Infrastructure Partners I, II and III, which collectively manage more than $7$7.0 billion in U.S.United States and Canadian infrastructure investments. Mr. Leslie is 5255 years old and became a member of the Boards of Managers in 2016. He is the chairChair 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

Jon Perry is a Senior Principal within the interim CEO of Cleco GroupInfrastructure & Renewable Resources Department at BCI, where he is responsible for sourcing, executing 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). Shemanaging infrastructure investments. He is 6544 years old and became a member of the Boards of Managers in 2016. Ms. Scott2018. Mr. Perry is the chairChair of Cleco’s Boardsthe Audit Committee.
Mr. Perry serves on the board of ManagersNoverco Inc. (“Noverco”), an investment holding company, which through its subsidiaries, distributes natural gas. Noverco also offers power generation, gas storage, and marketing services. He has over 10 years of experience in the utility and energy sectors. Prior to working with BCI, he held positions as Manager, Mergers and Acquisitions at TransAlta, a leading Canadian independent power producer and Manager, Regulatory and Financial Reporting at FortisAlberta, a regulated distribution utility. Before then, Mr. Perry held financial and investor relations positions in Canadian junior and mid-cap oil and gas companies.
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Mr. Perry holds a Bachelor of Medical Laboratory Sciences from University of British Columbia. He is also serves asa Chartered Accountant in the Province of Alberta and is a Chartered Financial Analyst charter holder.
Aaron Rubin is a Managing Director at MIRA, where he is responsible for MIRA’s North American power and utilities investment team. He is 42 years old and became a member of the Boards in 2018. Mr. Rubin is a member of the Business Planning and Budget Review Committee.
Since joining MIRA in 2008, Mr. Rubin has had extensive responsibility for investment origination and execution as well as for management of portfolio investments. He has also served as the CEO of the Moscow-based Macquarie Russia & CIS Infrastructure Fund, and has been a director of a number of MIRA portfolio companies in the energy, transportation, and communications sectors. Mr. Rubin is currently a director of Lordstown Energy Center, a 940 MW gas-fired power plant construction project in Ohio. Mr. Rubin is also the director of the UK subsidiary of Wheelabrator Technologies, Inc. Prior to joining MIRA, Mr. Rubin was a Vice President in JPMorgan’s North American mergers and acquisitions team.
Mr. Rubin holds a Bachelor of Commerce and a Bachelor of Laws degree from the University of Queensland.
Peggy Scott currently serves as the Chair of the Boards. She served as Chairperson and Interim CEO of Cleco Holdings from February 9, 2017, through December 31, 2017. She also serves on Cleco’s Audit Committee and Governance and Public Affairs Committee.

Presently, Ms. Scott joined BCBSadvises diverse industries, including healthcare and technology. She is 68 years old and became a member of the Boards in 20052016.

Ms. Scott serves on the boards of The Eastern Company (Nasdaq: EML) and Health Insurance Innovations, Inc. (Nasdaq: HIIQ). Previously, she served as the Executive Vice President, Chief Financial Officer/Treasurer,Operating Officer and CFO of Blue Cross Blue Shield of Louisiana (“BCBS”) and as Chief Strategy Officer. She became the Executive Vice President and Chief Operations Officer in 2008.Prior to BCBS, Ms. Scott was an office Managing Partner with Deloitte Touche Tohmatsu Limited and held executive positions in United States and International companies where she led transformations, growth strategies, and operations in seven foreign countries.
Ms. Scott was named one of the first womanten Outstanding Young Women of America, featured in the U.S. to receive the IMA/Robert HalfWall Street Journal as National Financial Executive of the Year award. She was the first Louisiana resident to be named toyear, and inducted into the American Institute of CPA’s Business and IndustryCPAs’ Hall of FameFame. She is in 2007. In April 2014, Ms. Scott was inducted inthe Louisiana State University’s E.J. Ourso College of Business’sAlumni Hall of Distinction.

Distinction, named a Tulane Outstanding Alumnus and holds a Ronald Reagan presidential citation.

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

Melissa Stark currently serves as the managing principal and owner of Co Issuer Corporate Staffing, LLC, (CICS) which she established in 2003 to provide independent directors and officers for special purpose entities. She is 5457 years old and was appointed in 2016 as a special independent manager of Cleco Power, whose sole purpose is to vote on any bankruptcy-related matters, as specified in Cleco Power’s Second Amended and Restated CompanyOperating Agreement. From 2001 to 2017, Ms. Stark concurrently servesserved 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—President - Fixed Income Research at Duff & Phelps (now known as Fitch) andwhere she covered high yield bonds in the retail industry. She served as Vice President—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 heldBusiness.
Steven Turner is a number of financial analyst positions.

Steven Turner is aSenior Portfolio Manager within the Infrastructure & Renewable Resources Department at bclMC,BCI, where he is responsible for sourcing, executing, and managing infrastructure investments. He is 4447 years old and became a member of the Boards of Managers in 2016. Mr. Turner is the Chair of the Governance and Public Affairs Committee and a member of the Business Planning and Budget Review Committee and Asset Managementthe Leadership Development and Compensation Committee.

Mr. Turner serves on the boardsboard of Corix Infrastructure Inc., a privately-held waste/wastewater and utility holding company based in Vancouver, British Columbia. He is also a past director of Macquarie Utilities Inc. and Aquarion Water Company, the parent companies to a suite of New England-based water utilities. 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.
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Mr. Turner has over 1015 years of experience in equity capital markets. Prior to joining bcIMC,BCI, he held positions as an Associate with Ventures West Management, a leading Canadian venture capital firm and as an Associate Equity Analyst with Raymond James Ltd., a full service brokerage firm.

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

holder and a holder of the ICD.D designation.

Bruce Wainer is the CEO of Wainer Enterprises, a family-owned commercial development company on Louisiana’s Northshore and in New Orleans. He is 5761 years old and became a member of the Boards of Managers in 2016. HeMr. Wainer is a member of the Business Planning and Budget Review Committee and Asset Managementthe Governance and Public Affairs Committee. He is the developer of some of the most successful commercial developments in the New Orleans area and past chairman of the Northshore Business Council. His business affiliations include partner at Wainer Brothers, All State Financial Company and Circle West Trailer Park Company; president of Quality Properties, Inc., Regent Lands, Inc., Flowers, Inc., Upside Down Cajun Brands, Inc., Louisiana Properties, Inc., Tamco, Inc., Riverhill, Inc., Metro Credit Services, Inc. and Pan American Investors, Inc., and manager of Advance Mortgage Company, LLC.
Executive Officers of Cleco
The names of the executive officers of Cleco and certain subsidiaries, their positions held, five-year employment history, ages, and years of service as of May 22, 2020, are as follows. Executive officers are appointed annually to serve for the ensuing year or until their successors have been appointed.
NAME OF EXECUTIVE
POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
William G. Fontenot
Cleco Holdings
President and CEO since January 2018.
Cleco Power
CEO since February 2019; President and CEO from January 2018 to February 2019; Interim CEO from February 2017 to December 2017; Chief Operating Officer from April 2016 to February 2017; Senior Vice President - Utility Operations from March 2012 to April 2016.
Cleco Cajun
CEO since February 2019.
(Age 57; 33 years of service)
Kazi K. Hasan
Cleco Holdings
Cleco Power
CFO since October 2018; Chief Risk Officer, AES Corporation from late 2014 to May 2018.
Cleco Cajun
CFO since February 2019.
(Age 49; 1 year of service)
Anthony L. Bunting
Cleco Holdings
Cleco Power
Chief Transformation Officer since February 2019; Chief Administrative Officer from April 2016 to February 2019; Vice President - Transmission & Distribution Operations from March 2012 to April 2016. (Age 60; 28 years of service)
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NAME OF EXECUTIVE
POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Robert R. LaBorde, Jr.
Cleco Holdings
Chief Operations Officer since February 2019; Vice President Generation Operations & Environmental Services from April 2016 to February 2019.
Cleco Power
Vice President - Generation Operations from November 2012 to April 2016. (Age 52; 28 years of service)
Justin S. Hilton
Cleco Power
President since February 2019.
Cleco Holdings
Cleco Power
Vice President MISO Operations from April 2016 to February 2019; General Manager Transmission Strategy from March 2012 to April 2016.
(Age 50; 30 years of service)
Robert E. Adrian
Cleco Cajun
Chief Operating Officer since November 2018; CEO, eServices, LLC from January 2012 to November 2018.
(Age 60; 1 year of service)
J. Robert Cleghorn
Cleco Power
Vice President Regulatory Strategy since April 2016.
Cleco Holdings
Cleco Power
General Manager Regulatory Strategy & Planning from March 2012 to April 2016.
(Age 61; 32 years of service)
Gregory A. Coco
Cleco Power
Vice President Transmission & Distribution Operations since April 2016.
Cleco Holdings
General Manager Brame Energy Center from March 2013 to April 2016.
Cleco Power
(Age 60; 38 years of service)
Patrick M. Dupuy
Cleco Holdings
Interim Vice President Asset Optimization since February 2019; Plant Manager, Dolet Hills Power Station from November 2002 to February 2019.
(Age 57; 34 years of service)
Kristin L. Guillory
Cleco Cajun
President since September 2019.
Cleco Holdings
Cleco Power
Treasurer from February 2018 to September 2019; General Manager Finance and Assistant Treasurer from May 2016 to February 2018; Manager Finance, Risk and Analytics & Assistant Treasurer from December 2013 to May 2016.
(Age 37; 15 years of service)
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NAME OF EXECUTIVE
POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Sidney D. Jacobson
Cleco Holdings
Vice President Risk Management since May 2020; Director Risk Management from January 2019 to May 2020; Managing Director, Pivotal Risk Advisors from October 2015 to January 2019; Partner, Energy Consulting Practice, Sungard Consulting Services from July 2011 to October 2015.
(Age 53; 1 year of service)
Jeremy J. Kliebert
Cleco Holdings
Associate General Counsel since March 2019; Vice President, Deputy General Counsel, Chief Data Privacy Officer, Chief IP Counsel, and Chief Privacy Counsel, Albemarle Corporation from December 2017 to March 2019; Vice President, Deputy General Counsel, Chief IP Counsel and Data Privacy Counsel, Albemarle Corporation from January 2015 to December 2017.
(Age 44; 1 year of service)
F. Tonita Laprarie
Cleco Holdings
Cleco Power
Controller & Chief Accounting Officer since July 2016; General Manager Audit & Risk from March 2014 to July 2016.
Cleco Cajun
Controller & Chief Accounting Officer since February 2019.
(Age 55; 19 years of service)
Mark A. Madsen
Cleco Holdings
Chief Digital & Information Officer since May 2019; Chief Information Officer, Vice President of IT - Waste Management Inc. from March 2010 to January 2019.
(Age 50; 1 year of service)
Sybil S. Montegut
Cleco Holdings
Vice President Enterprise Analytics since May 2020; Director Innovation and Transformation from January 2020 to May 2020; General Manager Transformation Office from March 2018 to January 2020; Supervisor Corporate Analytics from May 2016 to March 2018; Senior Investor Relations Analyst from November 2012 to May 2016.
(Age 42; 11 years of service)
Normanique G. Preston
Cleco Holdings
Chief Human Resources & Diversity Officer since September 2019; Vice President Human Resources from August 2018 to September 2019; Vice President - Human Resources, Dynegy, Inc. from November 2015 to June 2018.
(Age 53; 1 year of service)
Joel M. Prevost
Cleco Holdings
Cleco Power
Vice President Asset Management since April 2016; General Manager T&D Engineering & Construction from March 2012 to April 2016.
(Age 59; 38 years of service)
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NAME OF EXECUTIVE
POSITION AND FIVE-YEAR EMPLOYMENT HISTORY
Eric A. Schouest
Cleco Power
Vice President Governmental Affairs since September 2019.
Cleco Cajun
President from February 2019 to September 2019; Interim President from May 2018 to February 2019.
Cleco Holdings
Cleco Power
Vice President Governmental Affairs from March 2018 to May 2018; Vice President Marketing South from August 2016 to March 2018; General Manager Governmental Affairs/Regulatory Sales from February 2013 to August 2016.
(Age 55; 18 years of service)
Dean C. Sikes
Cleco Holdings
Cleco Power
Vice President Engineering, Construction & Project Management since April 2016; General Manager Generation Engineering & Construction from March 2013 to April 2016.
(Age 56; 32 years of service)
Vincent Sipowicz
Cleco Holdings
Treasurer since May 2020; Director Investor Relations, AES Corporation from 2015 to May 2020; Director Corporate Finance/Treasury, AES Corporation from 2012 to 2015.
(Age 46; <1 year of service)
Marty A. Smith
Cleco Power
Vice President Marketing since May 2018; Vice President Marketing North from January 2017 to May 2018; General Manager Distribution Engineering & Real Estate from February 2013 to April 2016.
Cleco Holdings
General Manager Corporate Safety from April 2016 to January 2017.
(Age 58; 28 years of service)
Russell L. Snyder
Cleco Power
Vice President Generation Operations since February 2019; General Manager Southern Gas Fleet from May 2016 to February 2019; Manager - Power Plant (>500 MW) from February 2010 to May 2016.
(Age 59; 35 years of service)
Terry J. Whitmore
Cleco Holdings
Vice President Transmission Services since February 2019.
Cleco power
General Manager Transmission Strategy from May 2016 to February 2019; Manager - Transmission Strategy & Support from March 2012 to May 2016.
(Age 56; 30 years of service)
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Audit Committee
Cleco has a separately-designated standing audit committee. The members of Cleco’s Audit Committee are Andrew Chapman, Randy Gilchrist, Jon Perry (who serves as Chair of the committee) and Peggy Scott. The Boards have determined that Andrew Chapman is the Senior Vice PresidentAudit Committee financial expert.
Code of InfrastructureBusiness Conduct & Renewable Resources at bcIMC, where he is responsible forEthics and Related Party Transactions
Cleco has adopted a Code of Conduct that applies to its principal executive officer, principal financial officer, principal accounting officer, and treasurer. Cleco also has adopted Ethics & Business Standards applicable to all employees and the overall managementBoards. In addition, the Boards have adopted Conflicts of Interest and Related Policies to prohibit certain conduct and to reflect the expectation of the firm’s infrastructureBoards that their members engage in and renewable resource investmentspromote honest and setting strategic directionethical 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 group. Hepolicy shall be referred to the Governance and Public Affairs Committee. Any recommendations by the Governance and Public Affairs Committee to implement a waiver shall be referred to the full Boards for a final determination. The Code of Conduct for Financial Managers, Ethics & Business Standards, and Conflicts of Interest and Related Policies are posted on Cleco’s website at https://cleco.com; About Us-Leadership-Codes of Conduct. Each of these documents is 45 years oldalso available free of charge by request sent to: Public Relations, Cleco, P.O. Box 5000, Pineville, LA 71361-5000.
Communications with the Boards
The Corporate Governance Guidelines provide for communications with the Boards by interested persons. In order for employees and becameother interested persons to make their concerns known to the Boards, Cleco has established a procedure for communications with the Boards through the Board’s Chair. The procedure is intended to provide a method for confidential communication, while at the same time protecting the privacy of the members of the Boards. Any interested person wishing to communicate with the Boards, or the non-management members of the Boards, may do so by addressing such communication as follows:
Chair of the Boards of Managers
c/o Corporate Secretary
Cleco Holdings
P. O. Box 5000
Pineville, LA 71361-5000
Upon receipt, Cleco’s Corporate Secretary will forward the communication, unopened, directly to the Chair of the Boards. The Chair will, upon review of the communication, make a determination as to whether it should be brought to the attention of the other non-management members and/or the management member of the Boards of Managers in 2016. Mr. Webb is a member ofand whether any response should be made to the Leadership Development and Compensation Committee. Currently, Mr. Webb serves as a director onperson sending the boards of Open Grid Europe GmbH and is a member ofcommunication, unless 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.communication was made anonymously.
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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.

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

2019 Business Highlights

In 20162019, the Company successfully completed the regulatory approvals for the Merger. Following the Merger, the Company reestablished the organization asperformed well as its governing structure while achieving solid operatingoperationally and financial performance.financially and initiated transformational strategic projects. 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

Completed the START project which includes replacement of and improvement to Cleco’s enterprise business applications
Implemented several key elements of the safety strategy focused on improving employee and contractor safety to build a stronger safety culture which resulted in fewer recordable injuries as compared to 2018
Continued capture of potential cost savings identified in the 2017 benchmarking opportunity assessment
Increased efforts related to cybersecurity
Completed the human resources strategy related to succession planning as well as diversity and inclusion
Effective Utility Operations

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

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

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

Compensation Philosophy

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

philosophy of the Committee are:
Executives should be rewarded on performance, and incentives should align interests between management and the Committee;Company;

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

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

Newly hired and/or promoted executives should be transitioned to median over time as they become more proficient in their roles;
The mix of fixed compensation (base salary and retirement benefits) and variable/at-risk compensation (annual incentive and long-term incentive) should align with market by emphasizing variable/at-risk compensation; and

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

Compensation Program Elements

The Committee targets total compensation (made up of the elements described below) to be competitive with the median of the Comparator Group (as defined below), but individual positioning may vary above or below the
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median depending on each executive’s experience, performance, and contribution to the Company. For 2016,2019, we believe that we accomplished our philosophy through the following compensation and benefit components:

2019 PAY ELEMENT
DESCRIPTION

2016 Pay Element

Description

Base Salary

Fixed pay element

Delivered in cash

Annual Cash Incentive

(PFP Plan)

(STIP)

Performance-based annual incentive plan that pays out in cash

EBITDA is primary measure for the named executive officers

Additional metrics include safety, system reliability, andcustomer service, generation fleet availability,

and milestone measures
Long-Term Incentives
Performance-based incentive paid in cash currently with a three-year cycle
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

Payout is contingent on average ROE and total EBITDA, each weighted at 50%
Benefits
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
SERP (closed to new participants in 2014)

Nonqualified Deferred Compensation Plan

Perquisites
Perquisites

Limited to executive physicals, spousal/companion travel, and relocation assistance

Roles and Responsibilities

Leadership Development and Compensation Committee

(the “Compensation Committee”)

The Compensation Committee, which consists of one Louisiana independent member of the board of managers of the Company (“Board ManagerManager”) and three investor Board Managers, is responsible for developing and overseeing the Company’s executive compensation program. The Compensation Committee met fiveseven times during 2016,2019, including three telephonefour telephonic meetings. The CEOGeneral Counsel and Chief AdministrativeCompliance Officer attendattended the Committee’sCompensation Committee meetings on behalf of management but dodid not participate in the Compensation Committee’s executive sessions.

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

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

engaging and evaluating an independent compensation consultant;

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

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

annually evaluating the performance of the CEO and the CFO and recommending to the Board adjustments in the CEO’sCEO and CFO’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;
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annually reviewing the Committee’s charter and revising as necessary; and

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

reviewing and making recommendations on efforts to promote diversity and inclusion.
The Compensation Consultant

After the Merger, the

The Compensation Committee engaged Pay Governance to consult on matters concerning executive officers’ compensation and benefits. All executive compensation adjustments and award calculations for 20162019 were reviewed by Pay Governance on behalf of the Compensation Committee. Pay Governance acted at the direction of the Compensation Committee and was independent of management. Pay Governance was responsible for:

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

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

reviewing the Company’s Board Managerof Managers compensation program;

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

attending the Compensation Committee meetings.

Before engaging Pay Governance, the

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

independent, and its services to the Compensation Committee do not create any conflicts of interest. The Compensation Committee has the sole authority to approve Pay Governance’s compensation and determine the nature and scope of its services, and determine the agreement.services. 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 todiscusses with the Compensation Committee regarding base salary adjustments, cash incentives, and long-term incentive awards.awards for executives other than himself. The CEO participates in meetings of the Compensation Committee to discuss executive compensation, including measures and performance targets but is subsequently excused to allow the independent members of the Compensation Committee to meet in executive session.

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 Compensation Committee believes that compensation and benefits for our executive officers who successfully enhance investors’ value should be competitive with the compensation and benefits offered by similar companies in our industry to attract and retain the high quality executive talent required by the Company. The Compensation Committee examines our executive officers’ compensation against comparable positions using publicly available proxy data for a group of 1613 industry peers (Peer Group)(the “Peer Group”) and utility industry survey data to help design and benchmark our executive officer compensation. This evaluation includes base salary, annual and long-term incentive plan targets, other potential awards, retirement benefits, and target total compensation. The Peer Group is used to track comparable performance of the long-term incentive plan. The combination of the Peer Group and the utility industry survey data is referred to as the “Comparator Group.”

The Peer Group, approved by the Committee in October 2016, had several revisions from our 2015 Peer Group. Companies

Vectren Corporation was removed from the Peer Group were Calpine, AGL Resources, Pinnacle West Capital, Alliant Energy, and Vectren. Companies addedin 2019 due to the Peer Group were Westar Energy, UIL Holdings, Otter Tail Corporation, Empire District Electric Company, and MGE Energy.its acquisition by another company. The Compensation Committee will continue to evaluate the Peer Group annually as companies are often acquired, taken private, or grow at a rate that renders them inappropriate for comparison purposes. The Compensation Committee evaluates the Peer Group to ensure that peer companies are of similar scope in relation to revenues, assets, and employee count and have a good operational fit.

2019 PEER GROUP

2016 Peer Group Companies

ALLETE, Inc.
Hawaiian Electric Industries, Inc.
Pinnacle West Capital Corporation
ALLETE, Inc.
Alliant Energy Corporation
IDACORP, Inc.
PNM Resources, Inc.
Avista Corporation
NorthWestern Corporation
Portland General Electric Company
Avista CorporationMGE Energy Inc.TECO Energy, Inc.
Black Hills Corporation
NorthWestern Corporation
OGE Energy Corp.
UIL Holdings Corporation
El Paso Electric Company
OGE Energy Corp.Westar Energy, Inc.
The Empire District Electric Company
Otter Tail Corporation
Great Plains Energy IncorporatedPNM Resources, Inc.
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In setting executive compensation levels in 2016,2019, the Compensation Committee also used utility industry survey data from the most recent Willis Towers Watson Energy Services Executive Compensation Database. Survey data provides a broader energy industry perspective. This survey data is used in conjunction with the Peer Group data as a competitive market reference point for the Compensation Committee to consider in determining pay levels.

Decisions Made in 20162019 with Regard to Each Compensation and Benefit Component

Base Salary

We strive

The Compensation Committee strives to set base salary levels for the executive officers as a group, including the named executive officers, at a level approximating +/-10% of the Comparator Group market median for 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.

total remuneration.

Base salaries for the named executive officers in 20162019 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

NAME
2019 BASE SALARY
2019 % CHANGE
Mr. Fontenot
$650,000
13.0%
Mr. Hasan
$400,000
0.0%
Ms. Callis
$285,000
5.6%
Mr. Bunting
$300,000
22.0%
Mr. LaBorde
$265,000
10.4%
Mr. Hilton(1)
$260,000
20.9%
(1)
Mr. Hilton is a Cleco Power employee.
Annual Cash Incentive

We maintain

The Company maintains the PFP Plan,STIP, an annual, performance-based cash incentive plan. The PFP PlanSTIP 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, theThe Compensation Committee targets PFP PlanSTIP 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 PlanSTIP opportunities for the named executive officers in 2016:

2019:
NAME
TARGET AS % OF
BASE SALARY

Name

Mr. Fontenot
Target as %
of Base Salary
100%

Mr. Olagues

Hasan
80
50%

Ms. Taylor

Callis
50
50%

Mr. Bunting

50
50%

Mr. Fontenot

LaBorde
50
50%

Mr. Crump

Hilton(1)
50
50%

(1)
Mr. Hilton is a Cleco Power employee.
The 2016 PFP Plan2019 STIP award for the named executive officers was based entirely on the corporate and individual performance measures described below. This includes measures that apply to non-named executive officers and employees. The 2016 PFP Plan2019 corporate performance measures consisted of the four metricselements listed below based on the business unit (weighting):

 
CONSOLIDATED
BUSINESS UNIT
 
 
SAFETY
EBITDA
EFORd
PEAK
EAF
CUSTOMER
SATISFACTION
LPSC
SAIDI
EBITDA
MILESTONE
MEASURES
Cleco Power
10%
20%
10%
15%
 
5%
20%
20%
Support Group(1)
10%
20%
7.5%
7.5%
7.5%
2.5%
25%
20%
Cleco Cajun
10%
20%
5%
15%
 
 
30%
20%
(1)
Support Group business unit weighting evenly split (50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting)
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EBITDA (70%)

System Average Interruption Duration Index or SAIDI (7.5%)

Equivalent Availability Factor or EAF (7.5%)

Safety (15%)

In establishingThe Compensation Committee included Milestone Measures in the 2016 PFP Plan2019 STIP corporate metrics for EMT and other corporate officers weighted at 20%. These Milestone Measures were associated with progress milestones on key strategic corporate projects related to affordability, the START project, cybersecurity, and the Human Resources strategy. The Committee believed it was most important to reward senior executives forput the overallgreatest emphasis on financial performance ofwith EBITDA at both the Company,business unit and therefore weighted EBITDA

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

The CEOmeasures.

Management recommended the PFP PlanSTIP financial performance and other measures to the Committee following the close of the Merger.Compensation Committee. Based on the historical performance relative to target and the relative historical performance versus the ComparatorPeer Group, the Compensation Committee reviews, revises as appropriate, and approves the PFP PlanSTIP measures for the upcoming year.

Details Related to Corporate Performance Metrics Established to Determine 2016 PFP Plan2019 STIP Award Levels

Metric # 1: EBITDA—1: Safety Consolidated — For 2016,2019, the Company included both the frequency of incidents represented by the Total Recordable Incident Rate (“TRIR”) and the severity of incidents represented by the Days Away, Restricted or Transferred (“DART”) rate for its safety measure. Each of these measures represents 5% of the overall STIP award for the corporate measures totaling 10% for the safety metric. The targets for both safety measures were based on the average rates of the companies in the Southeastern Electric Exchange, of which Cleco is a member, over the period 2017-2018.
SAFETY - TRIR MATRIX (5%)
PERFORMANCE LEVEL
% OF TRIR TARGET AWARD PAID
Above 0.655
0%
0.586 - 0.655
50%
0.515 - 0.585
100%
0.444 - 0.514
150%
At or below 0.443
200%
2019 Result (0.490)
150%
SAFETY - DART MATRIX (5%)
PERFORMANCE LEVEL
% OF DART TARGET AWARD PAID
Above 0.359
0%
0.301 - 0.359
50%
0.242 - 0.300
100%
0.183 - 0.241
150%
At or below 0.182
200%
2019 Result (0.210)
150%
Metric # 2: EBITDA Consolidated — The following EBITDA matrix was developed to determine performance and payout ranges related to consolidated EBITDA performance in 2019. This measure represents 30% of the overall STIP award for the corporate measures for non-executives and 20% of the overall STIP award for the corporate measures for executives. The final percentage of the financial target award is interpolated based on the performance level.
EBITDA MATRIX - CONSOLIDATED (20%)
PERFORMANCE LEVEL
% OF FINANCIAL TARGET AWARD PAID
Below $496.3 million
0%
Below $534.3 and above $496.3 million
50%
Between $534.3 and $544.1 million
100%
Above $544.1 and below $582.1 million
150%
At or above $582.1 million
200%
2019 Result - $565.1 million
155.3%
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Metric # 3: EFORd — This metric represents the probability a generator will fail either completely or in part when its operation is required and is 10% of the overall STIP award for the Cleco Power measures, 7.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting), and 5% of the overall STIP award for the Cleco Cajun corporate measures. The 2019 target was based on the weighted average performance over the three-year period 2016-2018.
EFORd MATRIX - CLECO POWER (10%)
PERFORMANCE LEVEL
% OF EFORd TARGET AWARD PAID
Above 7.33%
0%
6.55% - 7.33%
50%
5.75% - 6.54%
100%
4.96% - 5.74%
150%
At or below 4.95%
200%
2019 Result (3.6%)
200%
EFORd MATRIX - CLECO CAJUN (5%)
PERFORMANCE LEVEL
% of EFORd TARGET AWARD PAID
Above 13.09%
0%
12.56% - 13.09%
50%
12.02% - 12.55%
100%
11.49% -12.01%
150%
At or below 11.48%
200%
2019 Result (7.5%)
200%
Metric # 4: Peak EAF - Cleco Cajun and Support Group — This metric represents the amount of time that the power generation plant is able to produce electricity over a peak period (defined as May through September, Monday through Friday, hours ending 0700 through 2200), divided by the amount of time in the peak period and is 15% of the overall STIP award for the Cleco Cajun corporate measures and 7.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Cajun weighting). The 2019 target was based on Cleco Cajun fleet’s weighted average of the 2018 peak EAF unit targets.
PEAK EAF MATRIX - CLECO CAJUN (15%)
PERFORMANCE LEVEL
% OF PEAK EAF TARGET AWARD PAID
Below 88.51%
0%
At or above 88.51%
100%
2019 Result (96.77%)
100%
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Metric # 5: Customer Satisfaction - Cleco Power and Support Group — The Company included Customer Satisfaction in its performance measures in 2019 using the JD Power South Midsize segment (“JD Power study”) for comparison. For the STIP metric, the Company used the 2018 performance of the JD Power study to set the target. In addition, the Company compared its overall performance against its peers in the JD Power study. This metric represents 15% of the overall STIP award for Cleco Power corporate measures and 7.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Power weighting). The Compensation Committee used discretion to decrease the payout for officers to 50% of the target based on its review of 2019 performance. The resulting payout for 2019 was calculated as follows:
CUSTOMER SATISFACTION MATRIX - CLECO POWER (15%)
PERFORMANCE LEVEL
% OF CUSTOMER SATISFACTION
TARGET AWARD PAID
Below 675
0%
675 - 715
50%
716 - 736
100%
737 - 745
150%
At or above 746
200%
2019 Result (717)
100%
Committee Discretion
(50)%
Resulting Total Payout
50%
Metric # 6: LPSC SAIDI - Cleco Power and Support Group — SAIDI measures the average amount of time a customer’s service is interrupted during the year and is measured in hours per customer per year. The 2019 LPSC SAIDI goal was based on the long-term goal of consistent performance improvement compared to the LPSC target. This metric represents 5% of the overall STIP award for the Cleco Power corporate measures and 2.5% of the overall STIP award for the Support Group corporate measures (Support Group employees weighting is 50% of the Cleco Power weighting).
LPSC SAIDI MATRIX - CLECO POWER (5%)
PERFORMANCE LEVEL
% OF LPSC SAIDI TARGET AWARD PAID
Above 2.87
0%
At or below 2.87
100%
2019 Result (2.64)
100%
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Metric # 7: EBITDA — The following EBITDA matrix was developed to determine performance and payout ranges related to EBITDA performance.performance in 2019. This measure represents 70%30% for Cleco Power, 35% for the Support Group (Support Group employees weighting 50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting), 40% for Cleco Cajun of the overall PFP PlanSTIP award for the corporate measures.measures for non-executives and 20% for Cleco Power, 25% for the Support Group (Support Group employees weighting is 50% of the Cleco Power weighting and 50% of the Cleco Cajun weighting), 30% for Cleco Cajun of the overall STIP award for the corporate measures for executives. The final percentage of the financial target award is interpolated based on the performance level.

EBITDA MATRIX (70%)

EBITDA MATRIX - CLECO POWER (20%)

Performance Level

PERFORMANCE LEVEL
% of Financial
Target Award
Paid
OF FINANCIAL TARGET AWARD PAID

At or below $410.4

Below $407.6 million

0
0%

$443.7

Below $440.7 and above $407.6 million

100
50%

$440.7 million
100%
Above $440.7 and below $473.7 million
150%
At or above $477.0$473.7 million

200
200%

2016 Result—$442.9

2019 Result - $438.7 million

98
97.0%

EBITDA MATRIX - CLECO CAJUN (30%)
PERFORMANCE LEVEL
% OF FINANCIAL TARGET AWARD PAID
Below $88.7 million
0%
Below $93.6 million and $88.7 million
50%
Between $93.6 and $103.4 million
100%
Above $103.4 and below $108.4 million
150%
At or above $108.4 million
200%
2019 Result - $126.4 million
200%

Metric # 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 of8: Milestone Measures Cleco Power’s performance. officers had an additional STIP metric for 2019. This metric represents 7.5%20% of the overall PFP PlanSTIP award for the corporate measures.

SAIDI MATRIX (7.5%measures for executives and measures progress on certain strategic initiatives. The four broad initiatives included the affordability effort (5%)

, the business application strategy (5%), cybersecurity (5%), and the Human Resources strategy (5%). The Committee evaluated the performance of each initiative and determined the 2019 result for the Milestone Measures as follows.
MILESTONE MEASURES (20%)

Performance Level

2019 RESULTS
Hours
Per Customer
Per Year
% of SAIDI
Target Award
Paid
OF MILESTONE TARGET AWARD PAID
Cleco Power
>2.660
70%

Threshold

Support Group
2.66 to 2.5950
70%

Target

Cleco Cajun
2.58 to 2.51100
2.50 to 2.43150

Maximum

<2.43200

2016 Result

2.58 Hours100
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

Total Payout for EMT Cleco Power’s planned maintenance for the year. This metric represents 7.5% of the overall PFP Plan award for the corporate measures.

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 PayoutPower: The Committee determined that a total PFP Plancalculated STIP payout at 83.6%for Cleco Power was 112% of target for the corporate measures was reasonable based on the Company’s performance in 2016.target. The resulting total PFP PlanSTIP corporate payout for 20162019 was calculated as follows:

 
% OF TARGET
x
AWARD LEVEL
=
% OF PAYOUT
Safety Consolidated
10%
 
150%
 
15%
EBITDA Consolidated
20%
 
155.3%
 
31.1%
EFORd
10%
 
200%
 
20%
Customer Satisfaction
15%
 
50%
 
7.5%
LPSC SAIDI
5%
 
100%
 
5%
EBITDA
20%
 
97%
 
19.4%
Milestone Measures
20%
 
70%
 
14%
Total
100%
 
 
 
112%
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   % 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
  

 

 

       

 

 

 

Total Payout for EMT Support Group: The calculated STIP payout for the Support Group was 128.5% of target. The resulting total STIP corporate payout for 2019 was calculated as follows:
 
% OF TARGET
x
AWARD LEVEL
=
% OF PAYOUT
Safety Consolidated
10%
 
150%
 
15%
EBITDA Consolidated
20%
 
155.3%
 
31.1%
EFORd
7.5%
 
200%
 
15%
Peak EAF
7.5%
 
100%
 
7.5%
Customer Satisfaction
7.5%
 
50%
 
3.7%
LPSC SAIDI
2.5%
 
100%
 
2.5%
EBITDA
25%
 
158.9%
 
39.7%
Milestone Measures
20%
 
70%
 
14%
Total
100%
 
 
 
128.5%
Total Payout for EMT Cleco Cajun: The calculated STIP payout for Cleco Cajun was 151.1% of target. The resulting total STIP corporate payout for 2019 was calculated as follows:
 
% OF TARGET
x
AWARD LEVEL
=
% OF PAYOUT
Safety Consolidated
10%
 
150%
 
15%
EBITDA Consolidated
20%
 
155.3%
 
31.1%
EFORd
5%
 
200%
 
10%
Peak EAF
15%
 
100%
 
15%
EBITDA
30%
 
200%
 
60%
Milestone Measures
20%
 
100%
 
20%
Total
100%
 
 
 
151.1%
The Compensation Committee also has the authority to adjust the amount of any individual PFP Plan award with respect to the total award or the corporate or individual component of theSTIP award upon recommendation by the CEO. Adjustments for PFP Planthe STIP participants, except for the named executive officers and other members of EMT, may be made by the CEO at his discretion. Adjustments are based on the annual performance review process. No adjustments were made to
Long-Term Compensation
In 2019, the 2016 PFP Plan awardsCompensation Committee continued a cash-based LTIP and issued grants for the three-year cycle for the performance period ending December 31, 2021. The metrics for the LTIP cycle issued in 2019 are weighted 50% on the three-year average ROIC and 50% on the three-year cumulative total EBITDA.
Each executive officer’s target LTIP award level is set, so in combination with other pay elements, it will deliver a total compensation opportunity comparable to that of our Peer Group. The chart below details the targeted opportunity for each of the named executive officers.

Retention Bonus

For those executives who were participants inexpressed as a percentage of base salary:

NAME
TARGET AS % OF BASE SALARY
Mr. Fontenot
231%
Mr. Hasan
110%
Ms. Callis
110%
Mr. Bunting
110%
Mr. LaBorde
110%
Mr. Hilton
110%
2017-2019 LTIP Award
The Compensation Committee approved an overall award level of 106.04% of target for the previous equity-based LTIP three-year performance cycle that ended on December 31, 2019. This award level represents an average ROE of 9.432% and a cumulative EBITDA of $1,386.85 million over the Board approved a cashthree-year performance period. This award a portion of which will be paid in 2017cash and a portion of which will be paidis included in 2018, that is designed to fill the gap created by the missed earning opportunity on the outstanding LTIP cycles at the timecolumn G of the Merger. These cash awards are intended to be paid out in the same proportion as the payout on the short-term incentive

Summary Compensation Table 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.”2019.

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Long-Term Compensation

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

Retirement Plans—Plans - Nonqualified Deferred Compensation Plan

The Company maintains a Deferred Compensation Plan so that Board Managers,members of the Boards, executive officers, and certain key employees may defer receipt and taxation of certain forms of compensation. Board ManagersMembers of the Boards may defer up to 100% of their compensation; executive officers and other key employees may defer up to 50% of their base salary and up to 100% of their annual cash incentive. The use of deferred compensation plans is prevalent within our industry and within the companies in the Peer Group. The Company does not match deferrals or contribute to the plan. Actual participation in the plan is voluntary. The notional investment options made available to participants are selected by the CFO. The allocation of deferrals among investment options is made by individual participants. The notional investment options include money market, fixed income, and equity funds. No changes were made to the plan during 2016.

2019.

Retirement Plans—Plans - SERP

The Company maintains a SERP for the benefit of the executive officers who are designated as participants by the Compensation Committee. SERP was designed to attract and retain executive officers who have contributed and will continue to contribute to our overall success by ensuring that adequate compensation will be provided or replaced during retirement.

Benefits under SERP vest after ten years of service or upon death or disability while a participant is employed by the Company. The Compensation Committee may reduce the vesting period, which typically would occur in association with recruiting efforts. Benefits, whether or not vested, are forfeited in the event a participant is terminated for cause.

Generally, benefits are based upon a participant’s attained age at the time of separation from service. The maximum benefit is payable at age 65 and is 65% of final compensation. Payments from the Company’s defined benefit pension plan (Pension Plan)(“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.

2019.

In 2011, the Compensation Committee amended SERP to eliminate the business transaction benefit previously included in SERP, as well as the requirement that a SERP participant be a party to an employment agreement to receive change in control benefits.

In July 2014, the Cleco Corporation Board of Directors voted to close SERP to new participants. With regard to current SERP participants, two participants have agreed to fix the base compensation portion of thetheir SERP calculation as of December 31, 2017.2019. Additionally, they have agreed to use target rather than actual awards under the annual incentive plan for years 2016 and 20172019 for the average incentive award portion of the SERP calculation.

A third participant’s SERP benefit will be set at a specified amount based upon the year of separation.

In the event a SERP participant’s employment is involuntarily terminated by the Company without cause, or the participant terminates his or her employment on account of good reason, occurring within the 36-month period following the Mergera change in control event for all participants who commenced participation in SERP prior to October 28, 2011, or the 24-month period following the Mergera change in control event for all participants who commenced participation in SERP on or after October 28, 2011, such participant’s benefit shall: (i) become fully vested; (ii) be increased by adding three years to an affected participant’s age, subject to a minimum benefit of 50% of final compensation; and (iii) be subject to a modified reduction determined by increasing the executive’s age by three years. 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

During 2019, the Company hashad no employment agreements butwith named executives other than the agreement with Mr. Fontenot as President & CEO. The Company may enter into employment agreements with its executives generally in connection with recruiting efforts. The standard agreement provides for a non-renewing term, generally two years, and does not contain a change in control tax gross-up provision.
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The Cleco Corporation Executive Severance Plan

In recognition of the non-renewal of executive employment contracts, the Cleco Corporation Board of Directors adopted the Cleco Corporation Executive Severance Plan (the Executive“Executive Severance Plan)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—physicals - as a condition of receiving their PFP PlanSTIP award, we require and pay for an annual physical for the executive officers and their spouses;

Spousal/companion travel—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—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 wethe Company pay real estate agent and certain other closing fees should the officer or key employee sell his/her primary residence or that wethe Company purchase the executive officer’s or key employee’s primary residence at the

greater of its documented cost (not to exceed 120% of the original purchase price) or average appraised value. Typically, this occurs when an executive officer or key employee relocates at the Company’s request; and

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—program - under the Executive Severance Plan, a covered executive officer may request the Company to purchase his/her primary residence in the event he or she is involuntarily terminated without cause or separates for good reason, either in connection with a change in control and further provided the executive officer relocates more than 100 miles from the residence to be purchased. Limits on the purchase amount are the same as the relocation program described above.

The Compensation Committee approves the perquisites based on what it believes is prevailing market practice, as well as specific Company needs. The Company believes the relocation program is an important element in attracting executive talent. 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 planPension 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.

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

Tally Sheets

At least annually, the Compensation Committee reviews tally sheets that set forth the items listed below. This review is conducted as part of the comparison of the compensation and benefit components that are prevalent within the Comparator Group. The comparison facilitates discussion with the Compensation Committee’s outside independent consultant as to the use and amount of each compensation and benefit component versus the applicable Peer Group.
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Annual compensation expense for each named executive officer—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—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—payments - reviewed pursuant to the potential separation events discussed in “Potential Payments at Termination or Change in Control.”

Trends and Regulatory Updates

As needed, and generally at least annually, the Compensation Committee reviews reports related to industry trends, legislative and regulatory developments, and compliance requirements based on management’s analysis and guidance provided by Pay Governance, as applicable. Plan revisions and compensation program design changes are implemented as needed.

Risk Assessment

The Compensation Committee also seeks to structure compensation that will provide sufficient incentives for the executive officers to drive results while avoiding unnecessary or excessive risk taking that could harm the long-term value of the Company. The Compensation Committee believes that the following actions and/or measures help achieve this goal:

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

the Compensation Committee allocates pay mix between base salary and performance-based pay to provide a balance of incentives;

the design of the incentive measures is structured to align management’s actions with the interests of the investors;

incentive payments are dependent on the Company’s performance measured against pre-established targets and goals and/or compared to the performance of companies in the Peer Group;

the range and sensitivity of potential payouts relative to target performance are reasonable;

the Compensation Committee imposes checks and balances on the payment of compensation discussed herein;

detailed processes establish the Company’s financial performance measures under its incentive plans; and

incentive targets are designed to be challenging, yet achievable, to mitigate the potential for excessive risk-taking behaviors.

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)

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.

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

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 CompanyPNM Resources, Inc.
ALLETE, Inc.Great Plains Energy IncorporatedPortland General Electric Company
Alliant Energy CorporationIDACORP, Inc.TECO Energy, Inc.
Avista CorporationNorthWestern CorporationVectren Corporation
Black Hills CorporationOGE Energy Corp.
Calpine CorporationPinnacle West Capital Corporation

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.

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 couldmay deduct in a tax year for compensation paid to the CEO, CFO, and each of the threefour 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.officers.
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The Compensation Committee took actions considered appropriate to preserve the deductibility of compensation paid to executive officers, but the Compensation Committee did not adopt a formal policy that required all compensation to be fully deductible. As a result, the Compensation Committee may have paid or awarded compensation that it deemed necessary or appropriate to achieve our business goals and to align the interests of our executives with those of Cleco Corporation shareholders,Cleco’s investors, whether or not the compensation was performance-based within the meaning offully deductible under 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

.

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 

NAME AND PRINCIPAL
POSITION
YEAR
SALARY
($)
BONUS
($)
NON-EQUITY
INCENTIVE
PLAN
COMPENSATION
($)
CHANGE IN
PENSION
VALUE AND
NONQUALIFIED
DEFERRED
COMPENSATION
EARNINGS
($)(1)
ALL OTHER
COMPENSATION
($)
TOTAL
($)
A
B
C
D
E
F
G
H
William G. Fontenot,
President & CEO
2019
$639,616
$345,000
$1,171,839
$1,402,994
$17,293
$3,576,742
2018
$552,885
$0
$819,412
$0
$12,921
$1,385,218
2017
$362,904
$0
$475,460
$2,552,193
$13,681
$3,404,238
 
 
 
 
 
 
 
 
Kazi K. Hasan,
CFO
2019
$400,008
$0
$257,005
$0
$31,324
$688,337
2018
$46,155
$0
$0
$0
$942
$47,097

Julia E. Callis,(2)
Former Chief Compliance Officer & General Counsel
2019
$282,923
$67,500
$479,222
$544,561
$13,762
$1,387,968
2018
$268,846
$0
$486,712
$0
$13,616
$769,174
2017
$253,462
$0
$285,550
$439,225
$20,292
$998,529

Anthony L. Bunting,
Chief Transformation Officer
2019
$292,523
$61,500
$465,619
$598,968
$21,262
$1,439,872
2018
$245,389
$0
$452,027
$886,982
$18,806
$1,603,204
2017
$237,431
$0
$293,520
$562,686
$11,712
$1,105,349

Robert R. LaBorde Jr.,
Chief Operations Officer
2019
$261,539
$60,000
$363,152
$519,366
$12,703
$1,216,760
2018
$239,231
$0
$356,506
$0
$28,490
$624,227
2017
$229,385
$0
$197,844
$374,676
$13,705
$815,610

Justin S. Hilton,
President - Cleco Power
2019
$253,769
$107,500
$269,359
$381,155
$7,033
$1,018,816
(1)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 2016,2019, this amount includes the change in pension value from 20152018 to 2016.2019. Negative changes in the pension value year over year are reported as $0.

(2)
Ms. Callis resigned from Cleco effective March 13, 2020.

General

The Summary Compensation Table sets forth individual compensation information for the CEO, the CFO, and the threefour 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, 2016,2019, December 31, 20152018, and

December 31, 20142017 (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,E, “Non-Equity Incentive Plan Compensation;” and Column I,G, “All Other Compensation” represent cash compensation earned by the named executive in 2016, 20152019, 2018, or 2014.2017.

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,F, “Change in Pension Value and Nonqualified Deferred Compensation Earnings,” represent changes in the actuarial value of accrued benefits during 2016, 20152019, 2018, and 2014 2017
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under the Pension Plan and SERP.SERP, as applicable. Actuarial value computations are based on assumptions discussed in “Financial Statements and Supplementary Data—Data — Notes to the Audited Financial Statements—Statements — Note 9—10 — Pension Plan and Employee Benefits.” The 20162019 changes shown in Column HF are due in part to the actuarial impact from a decrease in the discount rate used to calculate future benefits under the Pension Plan and SERP. Negative changes, if any, are reported as zero. This compensation will be payable to the named executive in future years, generally as post-employment retirement payments.

Salary

Data in Column C includes pay for time worked, as well as pay for time not worked, such as vacation, sick leave, jury duty, bereavement, and holidays. The salary level of each of the named executives is determined by a review of market data for companies comparable in size and scope to Cleco, as discussed under “Decisions“— Compensation Discussion and Analysis — Decisions Made in 20162019 with Regard to Each Compensation and Benefit Component—Component — Base Salary” in the CD&A.Salary.” In some instances, merit lump sum payments are used to recognize positive performance when base pay has reached or exceeded the Company’s base pay policy target, and are included in the salary column. Deferral of 2016, 20152019, 2018, and 20142017 base pay made by Ms. MillerMr. Fontenot and Mr. LaBorde, and of 2019 base pay made by Mr. Hasan, pursuant to the Deferred Compensation Plan also is included in the salary column and is further detailed in the “Nonqualified Deferred Compensation” table. Adjustments to base pay are recommended to the Leadership Development and Compensation Committee typically on an annual basis, and if approved, usually are implemented in January. Base salary changes made in 20162019 for our named executives and the reasons for those changes are discussed in “Decisions“— Compensation Discussion and Analysis — Decisions Made in 20162019 with Regard to Each Compensation and Benefit Component—Component — Base Salary” in the CD&A.

Salary.”

Bonus

Column D, “Bonus” includes non-plan-based, discretionary incentives earned during 2016, 2015,2019, 2018, or 2014.2017. Amounts in this column for 2019 represent special awards made to the named executive officers for completion of the Cleco Cajun Transaction. No such awards were earned in 2016, 2015, or 20142018 and 2017 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.

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,E, “Non-Equity Incentive Plan Compensation” contains cash awards earned during 20162019 that were paid in March 2020 under the STIP; earned during 2018 and paid in March 2017;2019 under the STIP; and earned during 20152017 and paid in December 2015 and/or March 2016; and earned during 2014 and paid in December 2014 and/or March 20152018 under the PFP Plan.STIP. Deferral of annual cash incentive payments made by Mr. Fontenot and Mr. HoeflingLaBorde pursuant to the Deferred Compensation Plan also is included in Column GE and is further detailed in the “Nonqualified Deferred Compensation” table.

Column E also includes cash awards earned during 2019 that were paid in March 2020 and earned during 2018 that were paid in March 2019 for the LTIP performance periods ended December 31, 2019, and December 31, 2018, respectively.

Change in Pension Value and Nonqualified Deferred Compensation Earnings

The values in Column HF represent the aggregate increase in the actuarial present value of benefits earned by each named executive officer during 2016, 20152019, 2018, and 20142017 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, 2015,2019, 2018, and 2014;2017; rather, these amounts represent the present value of future retirement payments we project will be made to each named executive. Changes in the present value of the Pension Plan and SERP benefits from December 31, 20152018, to December 31, 2016;2019; from December 31, 20142017 to December 31, 2015;2018; and from December 31, 20132016, to December 31, 20142017, 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 HF 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 theirits annual tally sheet analysis. An explanation of why the Company uses SERP and its relationship to other compensation elements can be found in SERP.“Decisions Made in 2019 With Regard to Each Compensation and Benefit Component.”
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Column HF 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, 20152019, 2018, and 2014.

2017.

All Other Compensation

Payments made to or on behalf of our named executive officers in Column I,G, “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;

Spousal travel;
For 2016,2019, for Mr. Hasan, moving expenses reimbursed by 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;Company; and

Federal Insurance Contributions Act (“FICA”) tax due currently and paid by the Company on the annual increase in the named executive officers’ future SERP benefits.

The value of the Column IG items for 20162019 for each named executive officersofficer 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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

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.

 
MR. FONTENOT
MR. HASAN
MS. CALLIS
MR. BUNTING
MR. LABORDE
MR. HILTON
Cleco Contributions to 401(k) Plan
$11,200
$16,000
$12,918
$9,554
$12,141
$6,515
Taxable Group Term Life Insurance
830
158
350
1,382
350
350
Spousal Travel
5,263
145
0
0
0
168
Moving Expenses
0
15,021
0
0
0
0
FICA Tax on SERP
0
0
494
10,325
211
0
Total Other Compensation
$17,293
$31,324
$13,762
$21,261
$12,702
$7,033
 
 
ESTIMATED FUTURE PAYMENTS
UNDER NON-EQUITY INCENTIVE
PLAN AWARDS (STIP)
ESTIMATED FUTURE PAYMENTS
UNDER NON-EQUITY INCENTIVE
PLAN AWARDS (2019-2021 LTIP GRANT)
NAME
GRANT DATE
THRESHOLD ($)
TARGET ($)
MAXIMUM ($)
THRESHOLD ($)
TARGET ($)
MAXIMUM ($)
A
B
C
D
E
F
G
H
Mr. Fontenot
01/01/19
$0
$650,000
$1,300,000
$0
$1,500,000
$3,000,000
Mr. Hasan
01/01/19
$0
$200,000
$400,000
$0
$440,000
$880,000
Ms. Callis
01/01/19
$0
$142,500
$285,000
$0
$313,500
$627,000
Mr. Bunting
01/01/19
$0
$150,000
$300,000
$0
$330,000
$660,000
Mr. LaBorde
01/01/19
$0
$132,500
$265,000
$0
$291,500
$583,000
Mr. Hilton
01/01/19
$0
$130,000
$260,000
$0
$286,000
$572,000
General

The target values for each of the Company’s incentive plans—PFP Planplans — the STIP and LTIP—the 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” inDiscussion and Analysis — Evaluation and Design of the CD&A.Compensation and Benefit Programs.” Targets for both the PFP PlanSTIP 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)

(STIP)

See “Decisions“— Compensation Discussion and Analysis — Decisions Made in 20162019 with Regard to Each Compensation and Benefit Component—Component — Annual Cash Incentive” in the CD&A for a discussion of our 2016 PFP Plan2019 STIP award calculations.

Estimated Future Payments under EquityNon-Equity Incentive Plan Awards (LTIP)

There were no awards

See “— Compensation Discussion and Analysis — Decisions Made in 2019 with Regard to Each Compensation and Benefit Component — Long-Term Compensation” for a discussion of our grants made under the LTIP in 2016.2019.
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Pension Benefits

Name

  Plan Name(s)  Number of
Years of
Credited
Service (#)
   Present Value of
Accumulated
Benefit ($)
   Payments
During Last
Fiscal Year ($)
 

Mr. 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 

NAME
PLAN NAME (s)
NUMBER OF
YEARS OF
CREDITED
SERVICE (#)
PRESENT VALUE
OF
ACCUMULATED
BENEFIT ($)
PAYMENTS
DURING LAST
FISCAL
YEAR ($)
Mr. Fontenot
Cleco Corporate Holdings LLC Pension Plan
33
$2,016,802
$0
 
Cleco Corporation SERP
33
$4,563,348
$0
Mr. Hasan(1)
Cleco Corporate Holdings LLC Pension Plan
0
$0
$0
 
Cleco Corporation SERP
0
$0
$0
Ms. Callis(2)
Cleco Corporate Holdings LLC Pension Plan
0
$0
$0
 
Cleco Corporation SERP
12
$2,229,935
$0
Mr. Bunting
Cleco Corporate Holdings LLC Pension Plan
27
$1,848,982
$0
 
Cleco Corporation SERP
27
$3,345,583
$0
Mr. LaBorde(3)
Cleco Corporate Holdings LLC Pension Plan
16
$609,978
$0
 
Cleco Corporation SERP
11
$1,758,151
$0
Mr. Hilton(4)
Cleco Corporate Holdings LLC Pension Plan
30
$1,438,362
$0
 
Cleco Corporation SERP
0
$0
$0
(1)
Mr. Hasan is not a participant in the SERP or the Pension Plan as he was hired after both plans were closed to new participants.
(2)
Ms. Callis is not a participant in the Pension Plan as she was hired after the plan was closed to new participants.
(3)
Mr. LaBorde has prior years of service credit under the Pension Plan. He is not currently a participant in the Pension Plan because he was rehired after the Pension Plan was closed to new participants in 2007.
(4)
Mr. Hilton is not a participant in the SERP as his appointment to his current position was after the plan was closed to new participants.
General

The Company provides executive officers who meet certain tenure requirements benefits from the Pension Plan and SERP. Vesting in the Pension Plan requires five years of service with the Company. With the exception of Mr. WilliamsonHasan and Mr. Miller,Ms. Callis, each of the named executive officers is fully vested in the Pension Plan. Mr. WilliamsonHasan and Mr. Miller, bothMs. Callis, having been hired after August 1, 2007, were not eligible to participate in the Pension Plan and were included in an enhanced 401(k) Savings Plan for those employees hired on or after August 1, 2007.

Mr. LaBorde is fully vested in the Pension Plan based on previous service with the Company. Having been rehired after August 1, 2007, he was no longer eligible to participate in the Pension Plan and was included in an enhanced 401(k) Plan for those employees hired (or rehired) on or after August 1, 2007.

Vesting in SERP requires ten years of service. 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. MillerFontenot, Ms. Callis, Mr. Bunting, and Mr. Hoefling received accelerated vesting upon their separation from the Company. Mr. Williamson and Ms. Miller wereLaBorde are all fully vested in the SERP atbased on years of service. Mr. Hasan and Mr. Hilton are not participants in 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, 2016.2019. These calculations were made using the projected unit credit method for valuation purposes and a discount rate of 4.27%3.43%. Other material assumptions relating to the valuation include use of the RP-2006Pri-2012 Employee and Healthy AnnuitantRetiree gender distinct mortality tables projected generationally using Scale MP-2016,MP-2019 (using White Collar for SERP present values and no collar for qualified plan present values), assumed retirement at age 65 and retirement payments in the form of joint and 100% survivor with 10 years certain payment, with the exception of Mr. Miller and Mr. Hoefling whose benefits are payable as a 10-year certain and life annuity.

payment.

The sum of the change in actuarial value of the Pension Plan during 20162019 and the change in value of SERP is included in Column H,F, “Change in Pension Value and Nonqualified Deferred Compensation Earnings,” in the Summary Compensation Table. Negative changes, if any, are reported as zero.

Pension Plan

The Cleco CorporationCorporate Holdings LLC Pension Plan, restated effective August 1, 2015,May 10, 2017, is a defined benefit plan funded entirely by employer contributions. Effective August 1, 2007, the Pension Plan was closed to new participants. Employees hired or rehired on or after August 1, 2007 are eligible to participate in an enhanced 401(k) Savings Plan. With the exception of Mr. WilliamsonFontenot, Mr. Bunting, and Mr. Miller, each of our named executives wasHilton were hired prior to August 1, 2007.
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Benefits under the Pension Plan are determined by years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last ten years of employment. Earnings include base pay, cash incentives, merit lump sums, imputed income with respect to life insurance premiums paid by the Company, pre-tax contributions to the 401(k) 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 2016,2019, the amount of earnings was further limited to $265,000$280,000 as prescribed by the IRS.

The formula for calculating the defined benefit under the Pension Plan is as follows:

1.
Defined Benefit = Annual Benefit + Supplement Benefit

2.
Annual Benefit = Final Average Earnings × Years of Service × Pension Factor

3.
Supplement Benefit = (Final Average Earnings—Earnings - Social Security Covered Compensation) × Years of Service × .0065

The pension factor varies with the retirement year. For 2016,2019, the applicable factor was 1.25%. Social Security-covered income is prescribed by the IRS based on the year of birth.

Benefits from the Pension Plan are generally paid at normal, late or early retirement dates and are subject to a limit prescribed by the IRS, generally $210,000$225,000 in 2016.2019. Normal retirement at age 65 entitles the participant to a full pension. A participant may elect to delay retirement past age 65 as long as he/she is actively employed. Years of service continue to accumulate (up to a maximum of 35) and earnings continue to count toward the final earnings calculation. If a participant chooses to retire after age 55 but before normal retirement age, the amount of the annual pension benefit is reduced by 3% per year between ages 55 and 62. For example, the normal pension benefit at age 55 is reduced by 21%.

SERP

SERP is designed to provide retirement income of 65% of an executive officer’s final compensation at normal retirement, age 65. Final compensation under SERP is based on the sum of the highest annual salary paid during the five years prior to termination of employment and the average of the three highest PFP Planpay-for-performance (PFP) plans or STIP awards paid to the participant during the preceding 60 months. Final compensation also is determined without regard to the IRS limit on compensation. SERP benefit rate at normal retirement is reduced by 2% per year for each year a participant retires prior to age 65, with a minimum benefit rate of 45% at age 55. The final benefit rate also may be reduced further if a participant separates from service prior to age 55. This actuarially determined reduction factor is equivalent to that used in our Pension Plan, which is 3% for each year from age 55 to 62. For example, if a SERP participant were to terminate service at age 50 and start receiving his or her SERP benefit at age 55, his or her SERP benefit rate would be 35.6%. This is the product of the minimum SERP benefit of 45% reduced by another 21% for early commencement. The actual SERP benefit payments are reduced if a participant is to receive benefit payments from our Pension Plan, has received certain employer contributions related to ourthe 401(k) Savings Plan and/or is eligible to receive retirement-type payments from former employers and

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 Planannual incentive plan for the year in which death occurs. If a participant dies after termination of employment, the supplemental benefit is equal to the sum of the participant’s final annual base salary and target bonus payable under the PFP Planannual incentive plan for the year in which the participant retired or otherwise terminated employment. The supplemental death benefit is not dependent on years of service.

In July 2014, Cleco Corporation’s Board of Directors closed SERP to new participants. In August 2016, the Company’s Board of Managers voted to freeze salary and bonus components used in the final compensation calculation as of December 31, 2017, for threetwo current participants, includingMs. Callis and Mr. Olagues.LaBorde. In December
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2017, the Company entered into an employment agreement with Mr. Fontenot as its CEO, the terms of which amended the calculation of Mr. Fontenot’s SERP benefit to include a fixed benefit depending upon the year Mr. Fontenot separates from the Company. In May 2018, the Company amended the calculation of Mr. Bunting’s SERP benefit to include a predetermined benefit depending on the year that Mr. Bunting separates from the Company. With regard to 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, 2016.2019. 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.

 
ESTIMATED PAYMENTS AT 55
(OR ACTUAL ATTAINED AGE IF GREATER THAN 55)
 
PENSION
SERP
TOTAL
Mr. Fontenot
$110,379
$109,621
$220,000
Mr. Hasan
$0
$0
$0
Ms. Callis
$0
$112,036
$112,036
Mr. Bunting
$97,134
$112,866
$210,000
Mr. LaBorde
$40,020
$61,478
$101,498
Mr. Hilton
$93,386
$0
$93,386
Nonqualified Deferred Compensation

Name

  Executive
officer
contributions in
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 

NAME
EXECUTIVE
OFFICER
CONTRIBUTIONS
IN 2019 ($)(1)
COMPANY
CONTRIBUTIONS
IN 2019 ($)
AGGREGATE
EARNINGS IN
2019 ($)(2)
AGGREGATE
WITHDRAWALS /
DISTRIBUTIONS IN
2019 ($)
AGGREGATE
BALANCE AT
DECEMBER 31,
2019 ($)(3)
A
B
C
D
E
F
Mr. Fontenot
$239,481
$0
$251,007
$0
$1,625,061
Mr. Hasan
$10,000
$0
$877
$0
$10,877
Ms. Callis
$0
$0
$0
$0
$0
Mr. Bunting
$0
$0
$0
$0
$0
Mr. LaBorde
$37,727
$0
$84,215
$0
$523,513
Mr. Hilton
$0
$0
$0
$0
$0
(1)
The amounts in Column B represent deferrals of salary and non-equity incentive compensation payments made to the named executive officers during 20162019 and are included in the amounts shown in Columns C and G, respectively, of the Summary Compensation Table.
(2)
The aggregate earnings shown in Column D are not included in the Summary Compensation Table. Negative returns are reflected as zero.
(3)
The aggregate balances shown in Column F include amounts reported as salary and non-equity incentive compensation payments in the Summary Compensation Table for the current fiscal year, as well as previous years and the earnings on those amounts.

Deferred Compensation

Named executives and other key employees are eligible to participate in the Company’s Deferred Compensation Plan. Participants are allowed to defer up to 50% of their base salary and up to 100% of their annual cash incentive, as reported in Columns C and G in the Summary Compensation Table. Consequently, the executive officer contributions listed in Column B above are made by the participant and not by Cleco. Mr. Fontenot, Mr. Hasan, and Ms. MillerMr. LaBorde 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 2016.2019. All deferral elections for 20162019 were made prior to the beginning of 20162019 as required by the regulations under IRC Section 409A. There are no matching contributions made by the Company.

Deferrals become general funds for use by the Company to be repaid to the participant at a pre-specified date. Short-term deferrals may be paid out as early as five years following the end of the plan year (i.e., the year in which compensation was earned). Retirement deferrals are paid at the later of termination of service or the attainment of an age specified by the participant. A bookkeeping account is maintained for each participant that records deferred salary and/or bonus, as well as earnings on deferred amounts. Earnings are determined by the
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performance of notional investment alternatives, which are similar to the investments available under the 401(k) 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, 2016:2019: termination by the executive; disability; death; retirement; constructive termination; termination by the Company for cause; and termination in connection with a changeChange in

control. 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,STIP, LTIP, and SERP.

At its October 2011 meeting, theCleco Corporation’s Compensation Committee approved the Executive Severance Plan to provide severance benefits to executive officers. In October and December 2014 and July 2015, theCleco Corporation’s Compensation Committee approved amendments to the Executive Severance Plan. At December 31, 2016,2019, all of the named executive officers, other than the former executive officers were covered by the Executive Severance Plan,

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 PlanSTIP 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 PlanSTIP award and a supplemental death benefit provided from SERP are paid to an executive officer’s designated beneficiary in the event of death in service. Both are one-time payments. The executive officer’s designated beneficiary also is eligible to receive a prorated award for each LTIP performance cycle in which the executive officer participates to the extent those performance cycles award at their completion.

Annual survivor benefits are payable to an executive officer’s surviving spouse for his/her life, or if there is no surviving spouse, to the executive officer’s designated beneficiary for a period of ten years or, if no designated beneficiary is named, to the executive officer’s estate for a period of ten years. Amounts are calculated under the provisions of the Pension Plan and SERP. Please see the discussion under the headings “Pension Plan” and “SERP,” respectively, as well as SERP provisions relating to death while in service. Survivor benefits are paid from SERP regardless of vested status in SERP at the time of death. The SERP supplemental death benefit is paid only to executives who were employed by the Company on or after December 17, 1999. All of our named executives are eligible for the death benefit.
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Retirement

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

participates to the extent those performance cycles award at their completion. Retirement benefits are provided pursuant to the Pension Plan and SERP. Payments are made monthly and are calculated using the assumptions described in the discussion following the “Pension Benefits” table.

Constructive Termination

Payments made and benefits provided upon a constructive termination are ordinarily greater than payments made on account of an executive officer’s retirement, death or disability because separation effectively is initiated by the Company. Certain payments are made contingent upon the execution of a waiver, release and covenants agreement in favor of the Company. Constructive termination also may be initiated by an executive officer if there has been (i) a material reduction in his/her base compensation, other than a reduction uniformly applicable to all executive officers; and (ii) a contemporaneous, material reduction in his/her authority, job duties, or responsibilities.

Under the terms of the Executive Severance Plan, an executive would receive constructive termination payments including up to 52 weeks of base compensation, up to $50,000 in lieu of outplacement services and reimbursement of premiums paid to maintain coverage under our medical plan for up to 18 months. The executive also would be eligible for a prorated portion of the current year’s payout under the PFP PlanSTIP and a prorated award for the LTIP performance cycles in which he/she participates to the extent those performance cycles award at their completion.

If the executive officer has vested retirement benefits and has attained eligible retirement age, he/she would receive retirement benefits as described under “Pension Benefits.”

Termination for Cause

“Cause” is defined as an executive’s (i) intentional act of fraud, embezzlement or theft in the course of employment or other intentional misconduct that is materially injurious to the Company’s financial condition or business reputation; (ii) intentional damage to Company property, including the wrongful disclosure of its confidential information; (iii) willful and intentional refusal to perform the essential duties of his/her position; (iv) failure to fully cooperate with government or independent agency investigations; (v) conviction of a felony or crime involving moral turpitude; (vi) willful, reckless, or recklessnegligent violation of the material provisions of Cleco’s Code of Conduct; (vii) intentional, reckless, or (vii)intentional acts or failures to act in a manner which materially compromises his/her ability to perform the essential duties of his/her position; or (viii) willful, reckless, or recklessnegligent 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” wasis 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 an affiliate or any “person” who on the effective date of this plan is a director, officer, or officeris the “beneficial owner” (as determined in Rule 13d-3 promulgated under the Exchange Act) of 20% or more of the combined voting power of outstanding securities of the Company or an employee stock ownership plan (within the meaning of IRC Section 4975(e)(7)) sponsored by the Company or an affiliate, is or becomes the “beneficial owner” (as determined in Rule 13d-3 promulgated under the Exchange Act), directly or indirectly, of securities of the Company representing 20%80% or more of the combined voting power of the Company’s then outstanding securities;

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%securities of the directors then in office who were directors at the beginning of such period;Company;

The Company shall beis party to a merger or consolidation with another corporationentity and, as a result of such transaction, less than 80% or more of the thencombined voting power of outstanding voting securities of the survivingCompany or resulting corporation shall beits successor in the merger (or a direct or indirect parent company of the Company or its successor in the merger) is owned in the aggregate by persons who were not “beneficial owners” (as determined in Rule 13d-3 promulgated under the former shareholdersExchange Act) of securities 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;
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The Company sells, leases, or otherwise disposes of, in one transaction or in a series of related transactions, all or substantially all of its assets;

The shareholdersowners 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 areis sold, leased or otherwise disposed of in one or a series of related transactions to a person, other than the Company or anotheran 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).

Control.

Termination must be involuntary and by the Company without cause or initiated by the executive on account of “Good Reason.” The term “Good Reason”Good reason means that the named executive officer (i) suffers a significant reduction inparticipant’s base compensation in effect immediately before the commencement of a Change in Control Period (as such term is defined in the LTIP) is materially reduced, or there is a significantmaterial reduction or termination of such participant’s rights to any employee benefit in other benefits;effect immediately prior to such period; (ii) experiences a significant reductionparticipant’s authority, duties or responsibilities are materially reduced from those in effect immediately before the commencement of a Change in Control Period, or such participant has reasonably determined that, as a result of a change in circumstances that materially affects his or her employment with the Company, he or she is unable to exercise the authority, jobpower, duties and responsibilities;responsibilities assigned to him or her immediately before the commencement of such period; or (iii) a participant is required to be away from his/hertransfer to an office significantly more in order to perform his/her job duties; or (iv) experiences a change in jobbusiness location ofthat is more than 60 miles. “Good Reason” may not be initiated bymiles from the executive based onprimary location to which he or she was assigned prior to the fact that the Company is no longer publicly traded.commencement of a Change in Control Period. No event or condition willshall constitute “Good Reason”Good Reason hereunder unless (a) a participant provides to the named executive officer gives the CompanyCommittee written notice of his/his or her objection to such event or condition withinnot later than 60 days after he/shesuch participant first learns, or should have learned, of it,such event; (b) such event or condition is not promptly corrected by the Company promptly after receipt of such notice, but in no event latermore than 30 days after receipt of such notice,thereof; and (c) such participant Separates from Service (as such term is defined in the executive resigns his/her employment with the CompanyLTIP) not more than 6015 days following the expiration of the 30-day period described in subparagraphclause (b). hereof. The executive also must satisfy the conditions included in the waiver, release and covenants agreement defined in the Executive Severance Plan.

Under the Executive Severance Plan, an executive would receive an amount up to two times the sum of annualized base salary and the average non-equity incentive plan bonus over the last three fiscal years and reimbursement of COBRA premiums for up to 24 months. Payments may also include the purchase of the executive officer’s primary residence and reimbursement of relocation expenses, but only if the executive relocates his/her primary residence more than 100 miles. No excise tax payments or gross-ups are made; instead, benefits will be reduced to avoid the imposition of the tax. The numbers shown below do not give effect to this reduction.

Subject to the “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.

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, 2016.2019. Retirement is assumed to occur at age 55 or the named executive officer’s actual attained age if greater than 55. Estimated payments under our PFP PlanSTIP 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,STIP, the performance period is the current fiscal year. The estimated payment for the home purchase and relocation is a projection of the expense to the Company to sell the named executive officer’s principal residence including any loss avoided by the named executive officer by having the right to sell the residence to the Company, plus the projected cost to the Company to relocate the named executive officer.
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Pursuant to Item 401(j) of Regulation S-K, the separation events disclosed hereinin this prospectus 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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

2019.
Mr. Fontenot
 
 
 
 
 
 
 
VALUE OF PAYMENT/BENEFIT
TERMINATION
BY
EXECUTIVE
DISABILITY
DEATH
RETIREMENT
CONSTRUCTIVE
TERMINATION
TERMINATION
FOR CAUSE
CHANGE
IN
CONTROL
Cash Severance
$0
$0
$0
$0
$650,000
$0
$1,845,349
Annual Cash
Bonus
$0
$821,907
$821,907
$821,907
$821,907
$0
$0
Long-Term Incentive
$0
$1,683,265
$1,683,265
$1,683,265
$1,683,265
$0
$3,099,932
Cash Payment in Lieu of Outplacement Services
$0
$0
$0
$0
$50,000
$0
$0
Present Value of Incremental SERP Payments(1)
$0
$886,726
$3,239,523
$0
$0
$(2,267,297)
$1,944,376
SERP Supplemental Death Benefit
$0
$0
$1,661,540
$0
$0
$0
$0
Purchase of Principal Residence/
Relocation
$0
$0
$0
$0
$0
$0
$83,500
COBRA Medical Coverage
$0
$0
$0
$0
$34,990
$0
$46,653
Total Incremental Value
$0
$3,391,898
$7,406,235
$2,505,172
$3,240,162
$(2,267,297)
$7,019,810
(1)
As of December 31, 2016, Ms. Taylor2019, Mr. Fontenot was vested in SERP payments, which would be forfeited upon termination for cause.

Mr. Bunting

Value of Payment/Benefit

 Termination
by Executive
  Disability  Death  Retirement  Constructive
Termination
  Termination
for Cause
  Change in
Control
 

Cash Severance

 $0  $0  $0  $0  $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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Mr. Hasan
 
 
 
 
 
 
 
VALUE OF
PAYMENT/BENEFIT
TERMINATION
BY
EXECUTIVE
DISABILITY
DEATH
RETIREMENT(1)
CONSTRUCTIVE
TERMINATION
TERMINATION
FOR CAUSE
CHANGE
IN
CONTROL
Cash Severance
$0
$0
$0
$0
$400,000
$0
$800,000
Annual Cash
Bonus
$0
$257,005
$257,005
$0
$257,005
$0
$0
Long-Term Incentive
$0
$146,667
$146,667
$0
$146,667
$0
$440,000
Cash Payment in Lieu of Outplacement Services
$0
$0
$0
$0
$25,000
$0
$0
Present Value of Incremental SERP Payments
$0
$0
$0
$0
$0
$0
$0
SERP Supplemental Death Benefit
$0
$0
$0
$0
$0
$0
$0
Purchase of Principal Residence/Relocation Expenses
$0
$0
$0
$0
$0
$0
$83,500
COBRA Medical Coverage
$0
$0
$0
$0
$34,990
$0
$46,653
Total Incremental Value
$0
$403,672
$403,672
$0
$863,662
$0
$1,370,153
(1)
As of December 31, 2016,2019, Mr. Hasan was not eligible for retirement.
119

TABLE OF CONTENTS

Ms. Callis (1)
 
 
 
 
 
 
 
VALUE OF PAYMENT/BENEFIT
TERMINATION
BY
EXECUTIVE
DISABILITY
DEATH
RETIREMENT(2)
CONSTRUCTIVE
TERMINATION
TERMINATION
FOR CAUSE
CHANGE
IN
CONTROL
Cash Severance
$0
$0
$0
$0
$285,000
$0
$830,461
Annual Cash
Bonus
$0
$181,779
$181,779
$0
$181,779
$0
$0
Long-Term Incentive
$0
$599,943
$599,943
$0
$599,943
$0
$907,943
Cash Payment in Lieu of Outplacement Services
$0
$0
$0
$0
$25,000
$0
$0
Present Value of Incremental SERP Payments(3)
$0
$1,473,252
$976,101
$0
$0
$(2,155,924)
$414,080
SERP Supplemental Death Benefit
$0
$0
$734,713
$0
$0
$0
$0
Purchase of Principal Residence/Relocation Expenses
$0
$0
$0
$0
$0
$0
$83,500
COBRA Medical Coverage
$0
$0
$0
$0
$20,322
$0
$27,096
Total Incremental Value
$0
$2,254,974
$2,492,536
$0
$1,112,044
$(2,155,924)
$2,263,080
(1)
Ms. Callis resigned from Cleco effective March 13, 2020.
(2)
As of December 31, 2019, Ms. Callis was not eligible for retirement.
(3)
As of December 31, 2019, Ms. Callis was vested in SERP payments, which would be forfeited upon termination for cause.
Mr. Bunting
 
 
 
 
 
 
 
VALUE OF PAYMENT/BENEFIT
TERMINATION
BY
EXECUTIVE
DISABILITY
DEATH
RETIREMENT
CONSTRUCTIVE
TERMINATION
TERMINATION
FOR CAUSE
CHANGE
IN
CONTROL
Cash Severance
$0
$0
$0
$0
$300,000
$0
$852,985
Annual Cash
Bonus
$0
$187,947
$187,947
$187,947
187,947
$0
$0
Long-Term Incentive
$0
$568,072
$568,072
$568,072
568,072
$0
$878,272
Cash Payment in Lieu of Outplacement Services
$0
$0
$0
$0
25,000
$0
$0
Present Value of Incremental SERP Payments(1)
$0
$474,070
$1,699,756
$0
0
$(2,315,525)
$913,669
SERP Supplemental Death Benefit
$0
$0
$760,155
$0
0
$0
$0
Purchase of Principal Residence/Relocation Expenses
$0
$0
$0
$0
0
$0
$83,500
COBRA Medical Coverage
$0
$0
$0
$0
22,207
$0
$29,610
Total Incremental Value
$0
$1,230,089
$3,215,930
$756,019
$1,103,226
$(2,315,525)
$2,758,036
(1)
As of December 31, 2019, Mr. Bunting was vested in SERP payments, which would be forfeited upon termination for cause.
120

Mr. FontenotTABLE OF CONTENTS

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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Mr. LaBorde
 
 
 
 
 
 
 
VALUE OF PAYMENT/BENEFIT
TERMINATION
BY
EXECUTIVE
DISABILITY
DEATH
RETIREMENT(1)
CONSTRUCTIVE
TERMINATION
TERMINATION
FOR CAUSE
CHANGE
IN
CONTROL
Cash Severance
$0
$0
$0
$0
$265,000
$0
$798,475
Annual Cash
Bonus
$0
$168,038
$168,038
$0
$168,038
$0
$0
Long-Term Incentive
$0
$420,281
$420,281
$0
$420,281
$0
$678,614
Cash Payment in Lieu of Outplacement Services
$0
$0
$0
$0
$25,000
$0
$0
Present Value of Incremental SERP Payments(2)
$0
$1,413,217
$1,287,704
$0
$0
$(1,168,675)
$381,752
SERP Supplemental Death Benefit
$0
$0
$652,154
$0
$0
$0
$0
Purchase of Principal Residence/Relocation Expenses
$0
$0
$0
$0
$0
$0
$83,500
COBRA Medical Coverage
$0
$0
$0
$0
$30,691
$0
$40,922
Total Incremental Value
$0
$2,001,536
$2,528,177
$0
$909,010
$(1,168,675)
$1,983,263
(1)
As of December 31, 2016,2019, Mr. FontenotLaBorde was not eligible for retirement.
(2)
As of December 31, 2019, Mr. LaBorde was vested in SERP payments, which would be forfeited upon termination for cause.

Mr. 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 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

  

 

 

 

Mr. Hilton
 
 
 
 
 
 
 
VALUE OF PAYMENT/BENEFIT
TERMINATION
BY
EXECUTIVE
DISABILITY
DEATH
RETIREMENT(1)
CONSTRUCTIVE
TERMINATION
TERMINATION
FOR CAUSE
CHANGE
IN
CONTROL
Cash Severance
$0
$0
$0
$0
$260,000
$0
$732,925
Annual Cash
Bonus
$0
$142,111
$142,111
$0
$142,111
$0
$0
Long-Term Incentive
$0
$308,581
$308,581
$0
$308,581
$0
$542,248
Cash Payment in Lieu of Outplacement Services
$0
$0
$0
$0
$25,000
$0
$0
Present Value of Incremental SERP Payments
$0
$0
$0
$0
$0
$0
$0
SERP Supplemental Death Benefit
$0
$0
$0
$0
$0
$0
$0
Purchase of Principal Residence/Relocation Expenses
$0
$0
$0
$0
$0
$0
$83,500
COBRA Medical Coverage
$0
$0
$0
$0
$30,691
$0
$40,922
Total Incremental Value
$0
$450,692
$450,692
$0
$766,383
$0
$1,399,595
(1)
As of December 31, 2016,2019, Mr. CrumpHilton was vested in SERP payments, which would be forfeited upon terminationnot eligible for cause.retirement.
121

DIRECTORTABLE OF CONTENTS

BOARD OF MANAGERS COMPENSATION

2016 Director

2019 Board of Managers 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 

NAME(1)
FEES EARNED OR
PAID IN CASH
AND/OR STOCK ($)
TOTAL ($)
A
B
C
Rick Gallot
$146,676
$146,676
Randy Gilchrist
$146,676
$146,676
Peggy Scott
$226,683
$226,683
Melissa Stark
$3,750
$3,750
Bruce Wainer
$146,676
$146,676
(1)
Mr. Olagues was also a named executive officerMessrs. Chapman, Fronimos, Hanrahan, Leslie, Perry, Rubin, 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 boardsBoards by the OwnerCleco Group and do not receive additional compensation for their service on the boards.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.

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” representStock” represents cash compensation earned and/or received in 2016.

2019.

A non-management directorBoard Manager may elect to participate in the Company’s Deferred Compensation Plan and defer the receipt of all or part of his or her fees. Benefits are equal to the amount credited to each director’sBoard Manager’s individual account based on compensation deferred plus applicable investment returns as specified by the director upon election to participate in the plan. Investment options are similar to those provided to participants in the 401(k) Savings Plan. Funds may be reallocated between investments at the discretion of the director.Board Manager. Accounts, which may be designated separately by deferral year, are payable in the form of a single-sum payment or in the form of substantially equal annual installments, not to exceed 15, when a directorBoard Manager ceases to serve on the board of directorsCleco’s Boards or attains a specified age.

Fees Earned or Paid in Cash and/or Stock

Directors who are Cleco employees or who are appointed

From January 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,May 2019, 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 managerBoard Manager who is not a Cleco employee or appointed by the OwnerCleco Group, except Ms. Stark, receivesreceived an annual cash retainer of $130,000.$140,000. Ms. Stark receivesreceived an annual cash retainer of $3,750. Each committee chairDuring this period, the non-management Chair was compensated with an additional retainer of $75,000. Beginning in May 2019, each Board Manager who is not a Cleco employee or appointed by the OwnerCleco Group receivesreceived an additional annual cash retainer of $20,000,$150,000, and the non-management chair of the boards receivesChair received an additional annual retainer of $50,000.

Directors$82,500. Ms. Stark’s retainer remained set at $3,750.

Board Managers are permitted to defer receipt of their fees under the Company’s Deferred Compensation Plan. 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.

2019.

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

Stock Awards

Prior to 2016, each non-management director received an annual stock award During 2019, both Messrs. Wainer and Gilchrist incurred $60 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.

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 incurredexpenses for spousal/companion travel on Cleco business.travel.

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 directorsBoard Managers who are not employed by Cleco or appointed by the OwnerCleco 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 20162019 premium for all coverage (exempt employees, officers and directors)Board Managers) 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

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.

$6,128.

Interests of the Board of Directors

Managers

In 2016,2019, no non-management member of Cleco’s boardBoards 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.Boards.
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Report of the Leadership Development and Compensation Committee

REPORT OF THE LEADERSHIP DEVELOPMENT AND COMPENSATION COMMITTEE
The Leadership Development and Compensation Committee of the boards of managersBoards (see “Boards“Management — Boards of Managers of Cleco” above and “Director“Certain Relationships and Related Party Transactions, and Director Independence — Director Independence and Related Party Transactions” below)), includes fivefour managers, one of whom meetmeets 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,November 2019, a copy of which is posted on Cleco’s web site at https://www.cleco.com; About Us; Leadership; Board Committees. A copy of this charter also is available free of charge by request sent to: Public Relations, Cleco, P.O. Box 5000, Pineville, LA 71361-5000.

The Leadership Development and Compensation Committee was constituted following the closing of the Mergerestablished 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”)Analysis and related required compensation disclosure tables be included in the Company’s 20162019 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


Steven Turner

Leadership Development and 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 participationNo members of the Leadership Development and Compensation Committee memberswere officers or employees of the Company or any of its subsidiaries during 2019, were former Company officers, or had any relationship otherwise requiring disclosure.
CEO Pay Ratio
The aggregate compensation of the executive who served in the CEO role in 2019 (Mr. Fontenot) was $3,576,742. This amount differs from the aggregate amount reflected in the Summary Compensation Table included in this prospectus because of the inclusion of the value of the Company’s contribution to health and welfare benefits. The median employee’s annual total compensation for 2019 was $115,582, calculated including the same components of total pay as was used for Mr. Fontenot. As a result, we estimate that Clecothe CEO’s 2019 annual total compensation was 30.9 times that of the median employee’s annual total compensation. The median employee was determined based on employees of the Company on December 31, 2019, using the consistently applied compensation measure of target total cash compensation (including base salary and target bonus). Target total cash compensation was annualized for those employees that were not employed for the full year of 2019.
We believe that the above pay ratio is requireda reasonable estimate calculated in a manner consistent with Item 402(u) of Regulation S-K. In addition, because the SEC rules for identifying the median employee allow companies to report.

adopt a variety of methodologies, to apply certain exclusions, and to make reasonable estimates and assumptions that reflect their compensation practices, the pay ratio reported by other companies may not be comparable to the pay ratio reported above, as other companies may have different employment and compensation practices and may utilize different methodologies, exclusions, estimates and assumptions in calculating their own pay ratios.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Directors and Management and Certain Beneficial Owners

Upon

Following 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

Cleco has no 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.

are awarded.

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS,

AND DIRECTOR INDEPENDENCE

Director Independence and Related Party Transaction Approval Policy

The boardTransactions

Cleco’s Board has adopted a written Conflictscategorical standards to assist it in making determinations of Interest and Related Policies to prohibit certain conduct and to reflect the expectationits managers’ independence. These categorical standards are posted on Cleco’s web site at http://www.cleco.com; About Us; Leadership; Corporate Governance; Governance Guidelines. A copy of the boardstandards is also available free of charge by request sent to: Public Relations, Cleco, P.O. Box 5000, Pineville, LA 71361-5000. Cleco’s Board has determined that its members engage inRick Gallot, Randy Gilchrist, Peggy Scott and promote honest and ethical conduct in carrying out their duties and responsibilities, includingBruce Wainer are independent within 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 administrationmeaning of the policy shall be referredcategorical standards adopted by Cleco’s Board.
Cleco has no relationships 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 eachreport under Item 407(a)(3) 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.Regulation S-K.

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THE EXCHANGE OFFER

Purpose and Effect of Exchange Offer

We issued and sold the Outstanding Notes on May 17, 2016September 11, 2019 in an unregistered private placement to certain initial purchasers.purchasers of the Outstanding Notes. As part of that private offering, we entered into a registration rights agreement with the initial purchasers. Under the registration rights agreement, we agreed to file the registration statement, of which this prospectus forms a part, to offer to exchange the Outstanding Notes for the Exchange Notes in an offering registered under the Securities Act. ThisThe exchange offer satisfies that obligation. We also agreed to perform other obligations under thatthe registration rights agreement. See “Registration Rights Agreement.”

By participating in the exchange offer, holders of Outstanding Notes will receive Exchange Notes that are freely tradable and not subject to restrictions on transfer, subject to the exceptions described under “—Resale of Exchange Notes” immediately below. In addition, holders of Exchange Notes generally will not be entitled to additional interest.

Resale of Exchange Notes

We believe that the Exchange Notes issued in exchange for the Outstanding Notes may be offered for resale, resold and otherwise transferred by any new noteholder without compliance with the registration and prospectus delivery provisions of the Securities Act if the conditions set forth below are met. We base this belief solely on interpretations of the federal securities laws by the staff of the Division of Corporation Finance of the Commission set forth in several no-action letters issued to third parties unrelated to us. A no-action letter is a letter from the staff of the Division of Corporation Finance of the Commission responding to a request for the staff’s views as to whether it would recommend any enforcement action to the Division of Enforcement of the Commission with respect to certain actions being proposed by the party submitting the request. We have not obtained, and do not intend to obtain, our own no-action letter from the Commission regarding the resale of the Exchange Notes. Instead, holders will be relying on the no-action letters that the Commission has issued to third parties in circumstances that we believe are similar to ours. Based on these no-action letters, the following conditions must be met:

the holder must acquire the Exchange Notes in the ordinary course of its business;

the holder must have no arrangements or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act; and

the holder must not be our “affiliate,” as that term is defined in Rule 405 of the Securities Act.

Each holder of Outstanding Notes that wishes to exchange Outstanding Notes for Exchange Notes in the exchange offer must represent to us that it satisfies all of the above listed conditions. Any holder who tenders to exchange Outstanding Notes for Exchange Notes in the exchange offer who does not satisfy all of the above listed conditions:

cannot rely on the position of the Commission set forth in the no-action letters referred to above; and

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the Exchange Notes.

The Commission considers broker-dealers that acquired Outstanding Notes directly from us, but not as a result of market-making activities or other trading activities, to be making a distribution of the Exchange Notes if they participate in the exchange offer. Consequently, these holders must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the Exchange Notes.

Each broker-dealer that receives Exchange Notes for its own account in exchange for Outstanding Notes acquired by that broker-dealer as a result of market-making activities or other trading activities must deliver a prospectus in connection with a resale of the Exchange Notes and provide us with a signed acknowledgement of

this obligation. A broker-dealer may use this prospectus, as amended or supplemented from time to time, in connection with resales of Exchange Notes received in exchange for Outstanding Notes where the broker-dealer acquired the Outstanding Notes as a result of market-making activities or other trading activities. The letter of transmittal states that by acknowledging and delivering a prospectus, a broker-dealer will not be considered to

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admit that it is an “underwriter” within the meaning of the Securities Act. We have agreed that for a period of 180 days after the expiration date of the exchange offer, we will make this prospectus available to broker-dealers for use in connection with any resale of the Exchange Notes.

Except as described in the prior paragraph, holders may not use this prospectus for an offer to resell, a resale or other retransfer of Exchange Notes. We are not making thisthe 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$300.0 million of Exchange Notes for a like principal amount of Outstanding Notes tendered and accepted in connection with the exchange offer. Holders may tender some or all of their Outstanding Notes in connection with the exchange offer, but only in denominations of $2,000 and integral multiples of $1,000. The exchange offer is not conditioned upon any minimum amount of Outstanding Notes being tendered for exchange.

The terms of the Exchange Notes are identical in all material respects to the terms of the Outstanding Notes, except that:

we have registered the Exchange Notes under the Securities Act and therefore these notesthe Exchange Notes will not bear legends restricting their transfer; and

specified rights under the registration rights agreement, including the provisions providing for payment of additional interest in specified circumstances relating to the exchange offer, will be limited or eliminated.

The Exchange Notes will evidence the same debt as the Outstanding Notes. The Exchange Notes will be issued under the same indenture and entitled to the same benefits under that indenture as the Outstanding Notes being exchanged. As of the date of this prospectus, $885.0$300.0 million in aggregate principal amount of the Outstanding Notes were outstanding. Outstanding Notes accepted for exchange in the exchange offer will be retired and cancelled and will not be reissued.

In connection with the issuance of the Outstanding Notes, we arranged for the Outstanding Notes originally purchased by qualified institutional buyers to be issued and transferable in book-entry form through the facilities of DTC, acting as depositary. Except as described under “–“— Book-Entry Transfer,” we will issue the Exchange Notes in the form of a global note registered in the name of DTC or its nominee, and each beneficial owner’s interest in it will be transferable in book-entry form through DTC.

Holders of Outstanding Notes do not have any appraisal or dissenters’ rights in connection with the exchange offer. We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Act, the Exchange Act and the rules and regulations of the Commission.

We will be considered to have accepted validly tendered Outstanding Notes if and when we have given written notice to that effect to the exchange agent. The exchange agent will act as agent for the tendering holders of Outstanding Notes for the purposes of receiving the Exchange Notes from us.

If we do not accept any tendered Outstanding Notes for exchange because of an invalid tender, the occurrence of the other events described in this prospectus or otherwise, we will return these Outstanding Notes, without expense, to the tendering holder as quickly as possible after the expiration date of the exchange offer.

Holders who tender Outstanding Notes will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes on exchange of Outstanding Notes in connection with the exchange offer. We will pay all charges and expenses, other than the applicable taxes described under “—Fees and Expenses” in connection with the exchange offer.

If we successfully complete the exchange offer, any Outstanding Notes which holders do not tender or which we do not accept in the exchange offer will remain outstanding and continue to accrue interest. The holders of Outstanding Notes after the exchange offer in general will not have further rights under the registration rights
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agreement, including registration rights and any rights to additional interest. Holders wishing to transfer the Outstanding Notes would have to rely on exemptions from the registration requirements of the Securities Act.

Expiration Date; Extensions; Amendments

The expiration date for the exchange offer is 5:00 p.m., New York City time, on   , 2017.2020. We may extend this expiration date in our sole discretion, but in no event to a date later than   , 2017,2020, 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 toof the exchange agent.offer. In addition, we will give, as promptly as practicable, written notice regarding any delay in acceptance, extension or termination of the offer to the registered holders of Outstanding Notes. If we amend the exchange offer in a manner that we determine to constitute a material change, or if we waive a material condition, we will promptly disclose the amendment or waiver in a manner reasonably calculated to notify the holders of Outstanding Notes of the amendment or waiver, and extend the exchange offer as required by law to cause the exchange offer to remain open for at least five business days following such notice.

Without limiting the manner in which we may choose to make public announcements of any delay in acceptance, extension, termination, amendment or waiver regarding the exchange offer, we shall have no obligation to publish, advertise, or otherwise communicate any public announcement, other than by making a timely release to a financial news service.

Interest on the Exchange Notes

Interest on the 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%3.375% per annum on the principal amount, payable semiannually on May 1March 15 and November 1,September 15, with the next payment due on May 1, 2017.September 15, 2020. Interest on the Exchange Notes will accrue from the date of the last periodic payment of interest on such Outstanding Notes.

March 15, 2020.

Conditions to the Exchange Offer

Despite any other term of the exchange offer, we will not be required to accept for exchange, or issue Exchange Notes for, any Outstanding Notes and we may terminate the exchange offer as provided in this prospectus, if:

the exchange offer, or the making of any exchange by a holder, violates, in our good faith determination, any applicable law, rule or regulation or any applicable interpretation of the staff of the Commission;

any action or proceeding shall have been instituted or threatened with respect to the exchange offer which, in our reasonable judgment, would impair our ability to proceed with the exchange offer; or

we have not obtained any governmental approval which we, in our sole discretion, exercised reasonably, consider necessary for the completion of the exchange offer as contemplated by this prospectus.

The conditions listed above are for our sole benefit. We may assert them regardless of the circumstances giving rise to any of these conditions or waive them in our sole discretion in whole or in part. A failure on our part to exercise any of our rights under any of the conditions shall not constitute a waiver of that right, and that right shall be considered an ongoing right which we may assert at any time prior to the expiration of the exchange offer. All such conditions, other than those subject to governmental approval, will be satisfied or waived prior to the expiration of the exchange offer.
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If we determine in our sole discretion, exercised reasonably, that any of the events listed above has occurred, we may, subject to applicable law:

refuse to accept any Outstanding Notes and return all tendered Outstanding Notes to the tendering holders;

extend the exchange offer and retain all Outstanding Notes tendered before the expiration of the exchange offer, subject, however, to the rights of holders to withdraw these Outstanding Notes; or

waive unsatisfied conditions relating to the exchange offer and accept all properly tendered Outstanding Notes that have not been withdrawn.

Any determination by us concerning the above events will be final and binding.

In addition, we reserve the right in our sole discretion, exercised reasonably, to:

purchase or make offers for any Outstanding Notes that remain outstanding subsequent to the expiration date;date of the exchange offer; and

to the extent permitted by applicable law, purchase Outstanding Notes in the open market, in privately negotiated transactions or otherwise.

The terms of any purchases or offers to purchase Outstanding Notes may differ from the terms of the exchange offer. Those purchases may require the consent of the lenders under our Senior Secured Credit Facility.

$175.0 million credit facility.

Procedures for Tendering

Except in limited circumstances, only a Euroclear participant, Clearstream participant or DTC participant listed on a DTC securities position listing with respect to the Outstanding Notes may tender Outstanding Notes in the exchange offer. To tender Outstanding Notes in the exchange offer:

holders of Outstanding Notes that are DTC participants may follow the procedures for book-entry transfer as set forth under “—Book-Entry Transfer” and in the letter of transmittal; or

Euroclear participants and Clearstream participants on behalf of the beneficial owners of Outstanding Notes are required to use book-entry transfer pursuant to the standard operating procedures of Euroclear or Clearstream. These procedures include the transmission of a computer-generated message to Euroclear or Clearstream in lieu of a letter of transmittal. See the description of “agent’s message” under “–“— Book-Entry Transfer.”

In addition, you must comply with one of the following:

the exchange agent must receive, before expiration of the exchange offer, a timely confirmation of book-entry transfer of Outstanding Notes into the exchange agent’s account at DTC, Euroclear or Clearstream according to their respective standard operating procedures for electronic tenders and a properly transmitted agent’s message as described below; or

the exchange agent must receive any corresponding certificate or certificates representing Outstanding Notes along with the letter of transmittal; ortransmittal.

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.
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Any beneficial holder whose Outstanding Notes are registered in the name of his or its broker, dealer, commercial bank, trust company or other nominee and who wishes to tender should contact the registered holder promptly and instruct it to tender on the beneficial holder’s behalf. If any beneficial holder wishes to tender on its own behalf, it must, prior to completing and executing the letter of transmittal and delivering its Outstanding Notes, either:

make appropriate arrangements to register ownership of the Outstanding Notes in its name; or

obtain a properly completed bond power from the registered holder.

The transfer of record ownership may take considerable time and may not be completed prior to the expiration date.

Signatures on a letter of transmittal or a notice of withdrawal, as described in “Withdrawal of Tenders,” must be guaranteed by a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc., a commercial bank or trust company having an office or correspondent in the United States or an “eligible guarantor institution,” within the meaning of Rule 17Ad-15 under the Exchange Act, which we refer to in this prospectus as an “eligible institution,” unless the Outstanding Notes are tendered:

by a registered holder who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

for the account of an eligible institution.

If the letter of transmittal is signed by a person other than the registered holder of any Outstanding Notes listed therein, the Outstanding Notes must be endorsed or accompanied by appropriate bond powers which authorize the person to tender the Outstanding Notes on behalf of the registered holder, in either case signed as the name of the registered holder or holders appears on the Outstanding Notes. If the letter of transmittal or any Outstanding Notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should so indicate when signing, and, unless waived by us, evidence satisfactory to us of their authority to so act must be submitted with the letter of transmittal.

We will determine in our sole discretion, exercised reasonably, all questions as to the validity, form, eligibility, including time of receipt, and acceptance and withdrawal of tendered Outstanding Notes. We reserve the absolute right to reasonably reject any and all Outstanding Notes not properly tendered or any Outstanding Notes whose acceptance by us would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects or irregularities as to any particular Outstanding Notes. Our interpretation of the form and procedures for tendering Outstanding Notes in the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, holders must cure any defects or irregularities in connection with tenders of Outstanding Notes within a period we will determine. Although we intend to request the exchange agent to notify holders of defects or irregularities relating to tenders of Outstanding Notes, neither we, the exchange agent nor any other person will have any duty or incur any liability for failure to give this notification. We will not consider tenders of Outstanding Notes to have been made until these defects or irregularities have been cured or waived. The exchange agent will return any Outstanding Notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived to the tendering holders, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

In addition, we reserve the right, as set forth under “—Conditions to the Exchange Offer,” to terminate the exchange offer.

By tendering, each holder of Outstanding Notes represents to us, among other things, that:

the holder acquired Exchange Notes pursuant to the exchange offer in the ordinary course of its business;

the holder has no arrangement or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act; and

the holder is not our “affiliate,” as defined in Rule 405 under the Securities Act.
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If the holder is a broker-dealer that will receive Exchange Notes for its own account in exchange for Outstanding Notes acquired by the broker-dealer as a result of market-making activities or other trading activities, the holder must acknowledge that it will deliver a prospectus in connection with any resale of the Exchange Notes.

Book-Entry Transfer

We understand that the exchange agent will make a request promptly after the date of this prospectus to establish accounts with respect to the Outstanding Notes at DTC for the purpose of facilitating the exchange offer. Any financial institution that is a participant in DTC’s system may make book-entry delivery of Outstanding Notes by causing DTC to transfer the Outstanding Notes into the exchange agent’s DTC account in accordance with DTC’s Automated Tender Offer Program procedures for the transfer. Any participant in Euroclear or Clearstream may make book-entry delivery of Outstanding Notes by causing Euroclear or Clearstream to transfer the Outstanding Notes into the exchange agent’s account in accordance with established Euroclear or Clearstream procedures for transfer. The exchange of Exchange Notes for tendered Outstanding Notes will only be made after a timely confirmation of a book-entry transfer of the Outstanding Notes into the exchange agent’s account and timely receipt by the exchange agent of an agent’s message.

The term “agent’s message” means a message, transmitted by DTC, Euroclear or Clearstream, and received by the exchange agent and forming part of the confirmation of a book-entry transfer, which states that DTC, Euroclear or Clearstream has received an express acknowledgment from a participant tendering Outstanding Notes that the participant has received an appropriate letter of transmittal and agrees to be bound by the terms of the letter of transmittal, and that we may enforce the agreement against the participant. Delivery of an agent’s message will also constitute an acknowledgment from the tendering DTC, Euroclear or Clearstream participant that the representations contained in the letter of transmittal and described under “—Resale of Exchange Notes” are true and correct.

Guaranteed Delivery Procedures

The following

There is no procedure for 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;Notes.

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.

For a withdrawal to be effective:

the exchange agent must receive a written notice, which may be by facsimile transmission or letter, of withdrawal at the address set forth below under “Exchange Agent,” or

for DTC, Euroclear or Clearstream participants, holders must comply with their respective standard operating procedures for electronic tenders and the exchange agent must receive an electronic notice of withdrawal from DTC, Euroclear or Clearstream.

Any notice of withdrawal must:

specify the name of the person who tendered the Outstanding Notes to be withdrawn;

identify the Outstanding Notes to be withdrawn, including the certificate number or numbers and principal amount of the Outstanding Notes to be withdrawn;

include a statement that the person is withdrawing his election to have such Outstanding Notes exchanged;

be signed by the person who tendered the Outstanding Notes in the same manner as the original signature on the letter of transmittal, including any required signature guarantees; and

specify the name in which the Outstanding Notes are to be re-registered, if different from that of the withdrawing holder.

If Outstanding Notes have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC, Euroclear or Clearstream to be
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credited with the withdrawn Outstanding Notes and otherwise comply with the procedures of the applicable facility. We will determine in our sole discretion, exercised reasonably, all questions as to the validity, form and eligibility, including time of receipt, for the withdrawal notices, and our determination will be final and binding on all parties. Any Outstanding Notes so withdrawn will be deemed not to have been validly tendered for purposes of the exchange offer and no Exchange Notes will be issued with respect to them unless the Outstanding Notes so withdrawn are validly retendered. Any Outstanding Notes which have been tendered but which are not accepted for exchange will be returned to the holder without cost to the holder promptly after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn Outstanding Notes may be re-tendered by following the procedures described under “—Procedures for Tendering” at any time prior to the expiration date.

Fees and Expenses

We will not make any payments to brokers, dealers or other persons soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and its related reasonable out-of-pocket expenses, including accounting and legal fees. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the Outstanding Notes and in handling or forwarding tenders for exchange.

Holders who tender their Outstanding Notes for exchange will not be obligated to pay any transfer taxes. If, however:

Exchange Notes are to be delivered to, or issued in the name of, any person other than the registered holder of the Outstanding Notes tendered; 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;

then the tendering holder must pay the amount of any transfer taxes due, whether imposed on the registered holder or any other persons. If the tendering holder does not submit satisfactory evidence of payment of these taxes or exemption from them with the letter of transmittal, the amount of these transfer taxes will be billed directly to the tendering holder.

Accounting Treatment

The Exchange Notes will be recorded at the same carrying value as the Outstanding Notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the completion of the exchange offer.

Consequences of Failures to Properly Tender Outstanding Notes in the Exchange

Offer

We will issue the Exchange Notes in exchange for Outstanding Notes underin 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 notesNotes that are not tendered or that are tendered but not accepted by us will, following completion of the exchange offer, continue to be subject to the existing restrictions upon transfer under the Securities Act. If we successfully complete the exchange offer, specified rights under the registration rights agreement, including registration rights and any right to additional interest, will be either limited or eliminated.

Participation in the exchange offer is voluntary. In the event the exchange offer is completed, we will not be required to register the remaining Outstanding Notes. Remaining Outstanding Notes will continue to be subject to the following restrictions on transfer:

holders may resell Outstanding Notes only if we register the Outstanding Notes under the Securities Act, if an exemption from registration is available, or if the transaction requires neither registration under nor an exemption from the requirements of the Securities Act; and
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the remaining Outstanding Notes will bear a legend restricting transfer in the absence of registration or an exemption.

We do not currently anticipate that we will register any remaining Outstanding Notes under the Securities Act. To the extent that Outstanding Notes are tendered and accepted in connection with the exchange offer, any trading market for remaining Outstanding Notes could be adversely affected.
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DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS

The following is a descriptionTHE EXCHANGE NOTES

We have summarized selected provisions of our material indebtedness, other than the Outstanding Notes. The terms ofExchange Notes below. We will issue the Exchange Notes, and we issued the Outstanding Notes, are substantially identicalunder an Indenture, dated as of September 11, 2019 (the “base indenture”), between us and Regions Bank, as trustee, as supplemented by Supplemental Indenture No. 1 thereto, dated as of September 11, 2019 (the “supplemental indenture”). We have filed the base indenture and the supplemental indenture as exhibits to the 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 closingthis “Description 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.

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, whichExchange Notes” section, when we refer to hereinthe “indenture,” we mean the base indenture as supplemented by 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 
    

 

 

 

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.”indenture. The terms of the Exchange Notes and the Outstanding Notes include those stated in the Indentureindenture and those made part of the Indentureindenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). In

We urge you to read the discussion that follows, “the Issuer,” “we,” “us”base indenture and “our” refer only to Cleco Corporate Holdings LLC, a Louisiana limited liability company (f/k/a Cleco Corporation),the supplemental indenture because they, and not to OpCothis description, define your rights as holders of the Exchange Notes.
If the exchange offer is consummated, holders of Outstanding Notes who do not exchange their Outstanding Notes for Exchange Notes will vote together with the holders of the Exchange Notes for all relevant purposes under the indenture. In that regard, the indenture requires that certain actions by the holders under the indenture (including acceleration after an event of default, as described under “— Events of Default”) may be taken, and certain rights may only be exercised, by specified minimum percentages of the aggregate principal amount of all Outstanding Notes and Exchange Notes of a series issued under the indenture. In determining whether holders of the requisite percentage in principal amount have given any notice, direction, waiver, consent or taken any subsidiaryother action permitted under the indenture, any Outstanding Notes that remain outstanding after the exchange offer will be aggregated with the Exchange Notes, and the holders of ours. References to paying principal on the Outstanding Notes are to payment at maturity or redemption. Definitions of certain defined terms usedand the Exchange Notes will vote together as a single series for all such purposes. Accordingly, all references 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.

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 millionspecified percentages in aggregate principal amount of 3.743% Senior Securedthe Notes due 2026 (the “2026 Notes”); and

$350 millionmean, at any time after the exchange offer is consummated, such percentage in aggregate principal amount of 4.973% Senior Securedthe Outstanding Notes due 2046 (the “2046 Notes”).

Interest onand the 2026Exchange Notes will accrue at a ratethen outstanding.

For purposes of 3.743% per annum. Interest onthis summary, the 2046terms “we,” “our,” “ours” and “us” refer to Cleco Corporate Holdings LLC and not any of our subsidiaries and references to the “Notes” are references to the Exchange Notes will accrue at a rate of 4.973% per annum.

Principaloffered hereby.

Ranking 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 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,

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 general unsecured obligations;

rank equally in right of payment with eachall of our other seriesexisting and future unsecured and unsubordinated indebtedness;
be subordinated to all of Notes, regardlessour secured indebtedness, to the extent of the datevalue of issuance. Unlesssuch collateral; and
be structurally subordinated to all of the context otherwise requires, all referencesliabilities of our subsidiaries.
As of March 31, 2020, we had $1.77 billion of senior unsecured and unsubordinated indebtedness outstanding, including outstanding borrowings of $88.0 million under our $175.0 million revolving credit facility, and no secured indebtedness. As of March 31, 2020, our subsidiaries had $1.53 billion of indebtedness outstanding, including outstanding borrowings of $150.0 million under Cleco Power’s $300.0 million revolving credit facility.
Subject to exceptions, and subject to compliance with the applicable requirements, set forth in the indenture, we may discharge our obligations under the indenture with respect to the “Securities” andNotes as described below under “— Defeasance.”
Structural Subordination
The Notes will be structurally subordinated to all of the “Notes” under the Indenture andliabilities of our subsidiaries with regard to the “Notes” in this “Descriptionassets and earnings of Cleco Power, Cleco Cajun and our other subsidiaries. Since a substantial portion of our operations are conducted through Cleco Power, a primary source of funds for the repayment of our indebtedness, including the Notes, is distributions and dividends from Cleco Power, which is subject to numerous restrictions on its ability to make such distributions and dividends, including from state corporate law, Cleco Power’s
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indentures and credit agreements, and state and local regulations. Cleco Power has also made certain regulatory commitments which restrict its ability to make distributions and dividends to us.
Principal, Maturity and Interest
We issued $300.0 million aggregate principal amount of the Exchange Notes” include theOutstanding Notes offered hereby and anyin September 2019. We may issue Additional Series of Notes.

Additionally, we mayNotes 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;

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.

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.

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.

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

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.

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 theOutstanding 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 AgentNotes. We 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 toissue the Notes incurredonly 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.

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 inminimum denominations of $2,000 principal amount and integral multiples of $1,000 in excess thereof.

Any notice

The Notes will mature on September 15, 2029.
Interest on the Notes will:
accrue at the rate of 3.375% per annum;
be payable semi-annually in arrears on each March 15 and September 15;
be payable to the person in whose name the Notes are registered at the close of business on the March 1 and September 1 immediately preceding the applicable interest payment date, which we refer to with respect to the Notes as “regular record dates”;
be computed on the basis of a 360-day year comprised of twelve 30-day months; and
be payable on overdue interest to the extent permitted by law at the same rate as interest is payable on principal.
If any interest payment date, the maturity date or any redemption date falls on a day that is not a business day, the required payment will be made on the next business day with the same force and effect as if made on the relevant interest payment date, maturity date or redemption date and no additional amounts will accrue on that payment for the period from and after the interest payment date, maturity date or redemption date, as the case may be, to the date of that payment on the next succeeding business day. Unless we default on a payment, no interest will accrue for the period from and after the applicable maturity date or redemption date. No interest will be paid on either the Exchange Notes or the Outstanding Notes at the time of exchange. Interest on the Exchange Notes will accrue from March 15, 2020. Assuming the Exchange Notes are issued prior to September 15, 2020, holders of Outstanding Notes that are accepted for exchange in the exchange offer will be deemed to have waived the right, if any, to receive any payment in respect of interest accrued on the Outstanding Notes from March 15, 2020 until the date of the issuance of the Exchange Notes. Holders of the Exchange Notes will receive the same interest payments that they would have received had their Outstanding Notes not been accepted for exchange in the exchange offer.
Optional Redemption
At any time and from time to time, we may redeem the Notes at our option may state thatin whole or in part on any date prior to June 15, 2029 (the “Par Call Date”) at a redemption price equal to the greater of:
100% of the principal amount of the Notes are to be refinancedredeemed; or
the sum of the present values of the remaining scheduled payments of principal and interest on the Notes to be redeemed that would be due if such Notes matured on the Par Call Date but for the redemption (not including any portion of such payments of interest accrued to the date of redemption) discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable treasury rate plus 30 basis points;
plus, in each case, accrued and unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date.
At any time on or after the Par Call Date, we may redeem the Notes, in whole or in part, at our option, by paying 100% of the principal amount of the Notes to be redeemed plus accrued and unpaid interest thereon, including additional interest, if any, to, but excluding, the redemption date.
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“treasury rate” means, with respect to any redemption date:
the yield calculated on the third business day preceding the redemption date, as follows: for the latest day that appears in the most recent statistical release published by the issuanceBoard of other IndebtednessGovernors of the Federal Reserve System designated as “Selected Interest Rates (Daily) — H.15” (or any successor publication) under the caption “Treasury Constant Maturities — Nominal,” the independent investment banker shall select two yields — one for the maturity immediately before and one for the maturity immediately after the remaining maturity of the Notes to be redeemed (assuming the Notes matured on the Par Call Date) — and shall interpolate on a straight-line basis using such yields; if there is no such maturity either before or after, the independent investment banker shall select the maturity closest to the Par Call Date that appears on the release; or
if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the applicable comparable treasury issue, calculated by us or anythe independent investment banker using a price for the comparable treasury issue (expressed as a percentage of our Affiliates, in which eventits principal amount) equal to the comparable treasury price for such redemption date.
The treasury rate will be conditional upon our (or our Affiliate’s) receipt,calculated by the independent investment banker on or beforethe third business day preceding the date fixed for redemption.
“comparable treasury issue” means the United States Treasury security selected by an independent investment banker as having an actual or interpolated maturity comparable to the remaining term (remaining life) of the Notes to be redeemed (assuming for this purpose that the Notes matured on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such Notes.
“comparable treasury price” means (a) the average of three reference treasury dealer quotations for such redemption date, after excluding the highest and lowest reference treasury dealer quotations, or (b) if the independent investment banker obtains fewer than three such reference treasury dealer quotations, the average of proceedsall such quotations.
“independent investment banker” means one of such Indebtedness sufficientMizuho Securities USA LLC, Credit Agricole Securities (USA) Inc. or Scotia Capital (USA) Inc. and their respective affiliates or successors as specified by us, or, if these firms are unwilling or unable to payselect the principalcomparable treasury issue, an independent investment banking institution of national standing appointed by us.
“reference treasury dealer” means each of (a) Mizuho Securities USA LLC and premium,Scotia Capital (USA) Inc. and their respective affiliates or successors, each of which is a primary United States government securities dealer in New York City (a “Primary Treasury Dealer”) and a Primary Treasury Dealer selected by Credit Agricole Securities (USA) Inc., provided, however, that if any of the foregoing shall cease to be a Primary Treasury Dealer, we will substitute therefor another Primary Treasury Dealer and interest, if(b) any other Primary Treasury Dealer selected by us after consultation with the independent investment banker.
“reference treasury dealer quotations” means, with respect to each reference treasury dealer and any redemption date, the average, as determined by the independent investment banker, of the bid and asked prices for the applicable comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the independent investment banker at 5:00 p.m., New York City time, on the Notes being redeemed, and ifthird business day preceding such money has not been so received, such noticeredemption date.
The trustee, at our written direction, will be of no force or effect and we will not be required to redeem such Notes. Ifsend a notice of redemption doesto each holder of Notes to be redeemed by first-class mail (or in accordance with the procedures of DTC with respect to Notes registered in the name of Cede & Co.) at least 15 and not include such a statement, notices of redemption may not be conditional and once a notice of optional redemption is sent, Notes calledmore than 60 days prior to the date fixed for redemption become irrevocably due and payable on the redemption date at the redemption price.

redemption. Unless we default inon 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 on the date fixed for redemption. If fewer than all of the Notes are to be redeemed, not more than 60 days prior to the redemption date, the particular Notes or portions thereof for redemption will be selected from the outstanding Notes not previously called by such method as the trustee deems fair and appropriate. In the case of a partial redemption of Notes registered in the name of Cede & Co., the Notes to be redeemed will be determined in accordance with the procedures of DTC.

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Purchase of Notes Upon Change of Control Repurchase Event

In the event of the occurrence of both a Change of Control and a Ratings Event (a “Change of Control Repurchase Event”) each Holderholder of a Note will have the right, at such Holder’sholder’s option, subject to the terms and conditions of the Indenture,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’sholder’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 is sent by us of the occurrence of such Change of Control Repurchase Event, at a repurchase price payable in cash equal to 101% of the principal amount of such Notes plus accrued interest, including additional interest, if any, thereon, but excluding, to the Purchase Date (the “Change of Control Purchase Price”) pursuant to an offer to repurchase on the terms set forth in the Indentureindenture (a “Change of Control Offer”).

Within 30 days after the date of the Change of Control Repurchase Event, we are obligated to mail (or send in accordance with the procedures of DTC), to each Holderholder of a Note a notice (with a copy to the Trustee)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.

that a Change of Control Repurchase Event has occurred and that each such holder has the right to require us to repurchase all or any part of such holder’s Notes at the Change of Control Purchase Price;
the Change of Control Purchase Price;
the Purchase Date;
that any Note not tendered will continue to accrue interest;
the name and address of the paying agent;
the procedures to withdraw a holder’s election to have any Notes repurchased pursuant to the Change of Control Repurchase Event; and
that holders whose Notes are being purchased only in part will be issued new Notes equal in principal amount to the unpurchased portion of the Notes surrendered, which unpurchased portion must be equal to $2,000 in principal amount or an integral multiple of $1,000 in excess of $2,000.
To exercise this right, a Holderholder must deliver a written notice (the “Change of Control Purchase Notice”) to the paying agent (initially the Trustee)trustee) at its corporate trust office, or any other office of the paying agent maintained for such purposes (or if notesNotes 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.

the portion of the principal amount of any Notes to be repurchased, which must be a minimum of $2,000 or an integral multiple of $1,000 in excess thereof;
that such Notes are to be repurchased by us pursuant to the applicable Change of Control Repurchase Event provisions of the indenture; and
unless the Notes are represented by one or more global Notes, the certificate numbers of the Notes to be repurchased.
Any Change of Control Purchase Notice may be withdrawn by the Holderholder by a written notice of withdrawal delivered to the paying agent (or if Notes are held in book entry form, in accordance with DTC’s applicable

procedures) not later than three business days prior to the Purchase Date. The notice of withdrawal shall state the principal amount and, if applicable, the certificate numbers of the Notes as to which the withdrawal notice relates and the principal amount, if any, that remains subject to a Change of Control Purchase Notice.

If a Note is represented by a global Note, DTC or its nominee will be the Holderholder of such Note and therefore will be the only entity that can require us to repurchase Notes upon a Change of Control Repurchase Event. To obtain repayment with respect to such Note upon a Change of Control Repurchase Event, the beneficial owner of such Note must provide to the broker or other entity through which it holds the beneficial interest in such Note (a) the Change of Control Purchase Notice signed by such beneficial owner, and such signature must be guaranteed by a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, Inc. or a commercial bank or trust company having an office or correspondent in the United States, and (b) instructions to such broker or other entity to notify DTC of such beneficial owner’s desire to cause us to repurchase such Notes. Such broker or other entity will provide to the paying agent (i) a Change of Control
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Purchase Notice received from such beneficial owner and (ii) a certificate satisfactory to the paying agent from such broker or other entity that it represents such beneficial owner. Such broker or other entity will be responsible for disbursing any payments it receives upon the repurchase of such Notes by us.

Payment of the Change of Control Purchase Price for a Note in registered, certificated form (a “Certificated Note”) for which a Change of Control Purchase Notice has been delivered and not withdrawn is conditioned upon delivery of such Certificatedcertificated Note (together with necessary endorsements) to the Trustee,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 Certificatedcertificated Note will be made promptly following the later of the Purchase Date or the time of delivery of such Certificatedcertificated Note.

If the paying agent holds, in accordance with the terms of the Indenture,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 Holdersholders 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 Indentureindenture applicable to a Change of Control Offer made by us and purchases all Notes properly tendered and not withdrawn in accordance with such offer.Change of Control Offer or if notice of redemption has been given pursuant to the requirements set forth in the indenture unless and until there is a default in payment of the applicable redemption price. Notwithstanding anything to the contrary contained herein, a Change of Control Offer may be made in advance of a Change of Control, conditioned upon the occurrence of such Change of Control and without regard to the occurrence of a Ratings Event, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer is made; provided any such offerChange of Control Offer will be deemed to satisfy our obligation to make a Change of Control Offer upon the occurrence of any related Change of Control Repurchase Event.

The definition of Change of Control set forth in the Indentureindenture with respect to the Notes differs from the definition of change in control in our Senior Secured Credit Facilities.the senior unsecured credit facilities. Depending on the circumstances, it is possible that a change in control may occur for purposes of our Senior Secured Credit Facilitiesthe senior unsecured credit facilities without constituting a Change of Control for purposes of the Indenture.

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 Holderholder of Notes to require us to repurchase the Notes as a result of a sale, transfer, assignment, lease, conveyance or other disposition of less than all of the assets of us and our subsidiaries, considered as a whole, may be uncertain.

Under clause (c)the third bullet point of the definition of Change of Control below, a Change of Control will occur when a majority of our board of managers (for so long as the Operating Agreement is in effect, together with any replacement or new managers appointed to such board of managers in accordance with the terms of the Operating Agreement, and to the extent the terms of the Operating Agreement are no longer in effect, together with any new managers whose election or appointment by such board of managers or whose nomination for election by our members was approved by a vote of a majority of the managers then still in office who were either managers at the beginning of such period or whose election or nomination for election was previously so approved), during any period, cease to constitute a majority of our board of managers then in office. InSan Antonio Fire & Police Pension Fund v. Amylin Pharmaceuticals, Inc. et al.(May (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.stockholders. Therefore, in certain circumstances involving a significant change in the composition of our board of managers, the Holdersholders of the Notes may not be entitled to require us to repurchase the Notes as described above.
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The Indentureindenture 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 Holdersholders 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.initial purchasers of the Outstanding Notes. Our management has no present intention to propose any anti-takeover measures although it is possible that we could decide to do so in the future.

No Note may be repurchased by us as a result of a Change of Control Repurchase Event if there has occurred and is continuing an event of default described under “—Events of Default” 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.

Sinking Fund
We are not obligated to make mandatory redemption or sinking fund payments with respect to the Notes.
Certain Material Covenants

Merger, Consolidation, Sale, Lease or Conveyance

The Indenture will provideindenture provides that we may not, directly or indirectly, (a) consolidate or merge with or into another person, whether or not we are the surviving corporation, or (b) sell, assign, transfer, convey or otherwise dispose of all or substantially all of our or our subsidiaries’ properties or assets taken as a whole, in one or more related transactions, to another person, unless:

(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

(iv)we deliver an officer’s certificate and opinion of counsel to the Trustee stating that such transaction is authorized under the Indenture.

either (A) we are the surviving corporation or (B) the person formed by or surviving any such consolidation or merger (if other than us) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation, partnership or limited liability company organized or existing under the laws of the United States, any state of the United States or the District of Columbia;
the person formed by or surviving any such consolidation or merger (if other than us) or the person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all of our obligations under the Notes and the indenture pursuant to a supplemental indenture or other documents and agreements reasonably satisfactory to the trustee;
immediately after such consolidation or merger, no event of default under the indenture exists; and
we deliver an officer’s certificate and opinion of counsel to the trustee stating that such transaction is authorized under the indenture.
In addition, we may not, directly or indirectly, lease all or substantially all of our properties or assets, in one or more related transactions, to any other person.

Limitations on Liens

We will

The indenture provides that we may not pledge, mortgage, hypothecate or grant a security interest in, or permit any mortgage, pledge, security interest or other Lien upon, any of the Issuer’sour assets or property, whether owned on the Issue Datedate of delivery of the Notes or acquired thereafter, to secure any Indebtedness, other than Permitted Liens;provided,,however,, that any Lien on such property or assets will be permitted notwithstanding that it is not a Permitted Lien if the Notes are equally and ratably secured 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).
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Reports and Other Information

Whether

The indenture provides that whether or not required by the SEC’s rules and regulations, so long as any Notes are outstanding, we will furnish to the Trustee,trustee, within the time periods specified in the SEC’s rules and regulations for a 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 annual and quarterly reports that would be required to be filed with the SEC on Forms 10-K and 10-Q if we were required to file such reports; and
all current reports that would be required to be filed with the SEC on Form 8-K if we were required to file such reports.
All such reports will be prepared, within the time periods specified above, in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on our consolidated financial statements by our independent registered public accounting firm or independent auditors. In addition, we will file a copy of each of the reports referred to in clauses (a) and (b)the two bullet points immediately above with the SEC for public availability within the time periods specified in clauses (a) and (b)the two bullet points immediately 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 Trusteetrustee 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 Trusteetrustee is for informational purposes only, and the Trustee’strustee’s receipt of such shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including the Issuer’sour compliance with any of their covenants under the Indentureindenture (as to which the Trusteetrustee 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

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;

(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.

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.

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;

(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 andfurnished 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;

(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 relatingreports to the consent, waiver or amendment.

A supplemental Indenture which changes or eliminates any covenant or other provision oftrustee if we have filed such reports with the Indenture which has expressly been included solely forSEC on 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 consentEDGAR filing system 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.

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 thatreports 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

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.

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,publicly available.

Certain Definitions
Advisor 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

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.

An Affiliate”Affiliate” of, or a person “Affiliated” with, a specific person means (a) with respect to any person that is not a Fund or a direct or indirect subsidiary of a Fund, any other person that, directly or indirectly through one or more intermediaries, Controls, is Controlled by, or is under common Control with such person and (b) with respect to any person that is a Fund or is a direct or indirect subsidiary of a Fund, any Manager or Advisor of such Fund and any other person that, directly or indirectly through one or more intermediaries, Controls, is Controlled by, or is under common Control with, any such Manager or Advisor (including, for the avoidance of doubt, any Fund or any direct or indirect subsidiary of any Fund which is Controlled by any such person).

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

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”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
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than the Permitted Holders occurs, or we merge, consolidate or amalgamate with or into any other person or any other person merges, consolidates or amalgamates with or into us, in any such event pursuant to a transaction in which our outstanding Voting Stock is reclassified into or exchanged for cash, securities or other property, other than any such transaction where (i) our outstanding Voting Stock is reclassified into or exchanged for other Voting Stock of us or for Voting Stock of the surviving corporation and (ii) the holders of our Voting Stock immediately prior to such transaction own, directly or indirectly, a majority of our Voting Stock or the surviving corporation immediately after such transaction;

(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”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”).

“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”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”Controlling and “Controlled”Controlled have meanings correlative thereto.

Credit Agreement” means the Acquisition Facilities Credit Agreement (or any amendments, modifications, refinancings or replacements thereof).

Equity Interests”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”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”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.

GAAP” means generally accepted accounting principles in the United States of America, as in effect from time to time, consistently applied.

Governmental Authority”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”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” meansIndebtedness,” as applied to 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 and other instruments or other similar instruments,

(c) allarrangements representing obligations ofcreated or assumed by such person, to payin respect of:

obligations for money borrowed, other than unamortized debt discount or premium;
obligations evidenced by a note or similar instrument given in connection with the deferred purchase priceacquisition of propertyany business, properties or services (other than trade payables not overdue for more than 180 days) thatassets of any kind;
obligations as lessee under a capital lease;
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any amendments, renewals, extensions, modifications and refundings of any such indebtedness or obligations listed in 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,

(i) three immediately preceding bullet points; and

all guarantees of such person in respect of obligations of the kind referred to in clauses (a) through (h) above, and

(j) all Indebtednessabove.

All indebtedness of thesuch 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 ona lien upon property (including accounts and contracts rights) owned by such person, even thoughalthough such person has not assumed or become liable for the payment of such indebtedness, is also deemed to be Indebtedness but onlyof such person. All indebtedness for borrowed money incurred by any other persons which is directly guaranteed as to the extentpayment of principal by such person will for all purposes 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 liabilityindenture be deemed to be indebtedness of such person, withbut no other contingent obligation of such person in respect toof indebtedness incurred by any hedge agreement (or similar agreement or arrangement) at any timeother persons shall be the maximum aggregate amount (giving effect to any netting agreements) thatdeemed indebtedness of such person would be required to pay if such hedging agreement were terminated at such time.

person.

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”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”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”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”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”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.

Permitted Contest Conditions”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 Eventevent of Defaultdefault described in clause (h)the last bullet of “—Events of Default” or such contest would not reasonably be expected to result in any criminal or unindemnified civil liability (in the case of any such civil liability, otherwise required to be indemnified by the Issuerus under the Indenture)indenture), being incurred by the Trusteetrustee or any of the Holders.

holders.

Permitted Holders”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”Liens means:

(a)

mechanics’, materialmen’s, workers’, repairmens’,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;
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(e)

Liens securing judgments that do not constitute an Eventevent of Defaultdefault described in clause (h)the last bullet 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) our business;

Liens that have been placed by a third party on the fee title of leased real property or property over which the Issuer haswe have 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 theour property and assets of the Issuer;

(i) assets;

agreements for an obligation (other than repayment of borrowed money) relating to the joint or common ownership, operation, and use of property, including Liens under joint venture or similar agreements securing obligations incurred in the conduct of operations or consisting of a purchase option, call or right of first refusal with respect to the Equity Interests in such jointly owned person or assets;

(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,,

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 Issuerus and itsour subsidiaries with respect to workers’ compensation, unemployment insurance and other types of social security; and

(m)

Liens permitted under the Credit Agreementsenior unsecured credit facilities (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

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”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”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.

“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”Subsidiary means any subsidiary that would be considered a “significant subsidiary” under Article 1 of Regulation S-X under the Exchange Act.

Subsidiary”S&P means with respect to any person (the “parent”) at any date, any corporation, limited liability company, partnership, associationS&P Global Ratings, a division of S&P Global Inc., 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.its successors.
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Taxes”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”Stock means securities of any class or classes the holders of which are ordinarily, in the absence of contingencies, entitled to vote for corporate directors (or persons performing similar functions).

Events of Default
Each of the following is an event of default under the indenture with respect to the Notes:
our failure to pay the principal of or premium, if any, on the Notes when due, including at maturity, upon required purchase, upon redemption or upon acceleration;
our failure to pay any interest, including additional interest, on the Notes for 30 days after the interest becomes due;
our failure to perform, or our breach in any material respect of, any other covenant or warranty in the indenture, other than a covenant or warranty included in the indenture solely for the benefit of another series of our debt securities issued under the indenture, for 90 days after either the trustee or holders of at least 25% in principal amount of the outstanding Notes have given us written notice of the breach in the manner required by the indenture;
the default by us or any Significant Subsidiary of ours in a scheduled payment at maturity, upon redemption or otherwise in the aggregate principal amount of $50 million or more, after the expiration of any applicable grace period, of any Indebtedness, or the acceleration of any Indebtedness of us in such aggregate principal amount so that it becomes due and payable prior to the date on which it would otherwise have become due and payable and such payment default is not cured or such acceleration default is not rescinded within 30 days after notice to us in accordance with the terms of the Indebtedness;
specified events involving bankruptcy, insolvency or reorganization of us or any Significant Subsidiary of ours; and
the failure by us to pay final judgments aggregating in excess of $50 million, which judgments are not paid, discharged or stayed for a period of 60 days;
provided, however, that no event described in the third bullet point above will be an event of default until an officer of the trustee, assigned to and working in the trustee’s corporate trust department, has actual knowledge of the event or until the trustee receives written notice of the event. (Section 501)
If an event of default occurs and is continuing with respect to the Notes, either the trustee or the holders of at least 25% in principal amount of the outstanding Notes may declare the principal amount of the Notes due and immediately payable. To declare the principal amount of the Notes due and immediately payable, the trustee or the holders must deliver a notice that satisfies the requirements of the indenture. Upon a declaration by the trustee or the holders, we will be obligated to pay the principal amount of the Notes plus accrued and unpaid interest, if any.
This right does not apply if an event of default described in the fifth bullet point above occurs, or an event of default described in the fourth bullet point above that applies to all debt securities outstanding under the indenture occurs. If one of the events of default described in the fifth bullet point above occurs and is continuing, the debt securities, including the Notes, then outstanding under the indenture will be due and payable immediately. In addition, if the event of default described in the fourth bullet point occurs and is continuing and is common to all debt securities outstanding under the indenture, either the trustee or holders of at least 25% in principal amount of all of the debt securities then outstanding under the indenture, treated as one class, may declare the principal amount of all of the debt securities then outstanding under the indenture due and payable immediately.
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At any time after any declaration of acceleration of the Notes, but before a judgment or decree for payment of the money due has been obtained by the trustee, the event of default giving rise to the declaration of acceleration will, without further act, be deemed to have been waived, and such declaration and its consequences will, without further act, be deemed to have been rescinded and annulled if:
we have paid or deposited with the trustee a sum sufficient to pay:
all overdue installments of interest, if any, on the Notes,
the principal of (and premium, if any, on) the Notes that have become due otherwise than by such declaration of acceleration and any interest thereon at the rate or rates prescribed therefor,
to the extent lawfully permitted, interest upon overdue interest, and
all sums paid or advanced by, and certain sums owed to, the trustee under the indenture; and
all events of default, other than the non-payment of the principal amount of the Notes that became due solely by such declaration of acceleration, have been cured or waived as provided in the indenture. (Section 502)
For more information regarding waiver of defaults, please read “— Modification and Waiver.”
If an event of default occurs and is continuing, the trustee will generally have no obligation to exercise any of its rights or powers under the indenture at the request or direction of any of the holders, unless the holders offer indemnity satisfactory to the trustee. (Section 603) The holders of a majority in principal amount of the outstanding Notes will generally have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee for the Notes, provided that:
the direction is not in conflict with any law or the indenture;
the trustee may take any other action it deems proper which is not inconsistent with the direction; and
the trustee will generally have the right to decline to follow the direction if an officer of the trustee determines, in good faith, that the proceeding would involve the trustee in personal liability or would otherwise be contrary to applicable law. (Section 512)
A holder of a Note may only pursue a remedy under the indenture if:
the holder has previously given the trustee written notice of a continuing event of default for the Notes;
holders of at least 25% in principal amount of the outstanding Notes have made a written request to the trustee to pursue that remedy;
the holders have offered indemnity satisfactory to the trustee against the costs, expenses and liabilities to be incurred in conjunction with such request;
the trustee fails to pursue that remedy within 60 days after receipt of the request; and
during that 60-day period, the holders of a majority in principal amount of the Notes do not give the trustee a direction inconsistent with the request. (Section 507)
However, these limitations do not apply to a suit by a holder of a Note demanding payment of the principal, premium, if any, or interest on a Note on or after the date the payment is due. (Section 508)
We will be required to furnish to the trustee annually a statement by some of our officers regarding our performance or observance of any of the terms of the indenture and specifying all of our known defaults, if any. (Section 1004)
Modification and Waiver
We may enter into one or more supplemental indentures to the indenture with the trustee without the consent of the holders of the Notes to:
evidence the succession of another corporation to us, or successive successions and the assumption of our covenants, agreements and obligations by a successor;
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add to our covenants for the benefit of the holders of any series of debt securities or to surrender any of our rights or powers;
add events of default for any series of debt securities;
add to or change any provision of the indenture to the extent necessary to issue debt securities in bearer form;
add to, change or eliminate any provision of the indenture applying to one or more series of debt securities, provided that if such action adversely affects the interests of any holder of any series of debt securities issued thereunder, the addition, change or elimination will become effective with respect to that series only when no security of that series remains outstanding;
convey, transfer, assign, mortgage or pledge any property to or with the trustee or to surrender any right or power conferred upon us by the indenture;
establish the form or terms of any series of debt securities;
provide for uncertificated securities in addition to certificated securities;
evidence and provide for successor trustees or to add to or change any provisions to the extent necessary to appoint a separate trustee or trustees for a specific series of debt securities;
correct any ambiguity, defect or inconsistency under the indenture, provided that such action does not adversely affect the interests of the holders of any series of debt securities issued thereunder;
supplement any provisions of the indenture necessary to defease and discharge any series of debt securities, provided that such action does not adversely affect the interests of the holders of any series of debt securities issued thereunder;
comply with the rules or regulations of any securities exchange or automated quotation system on which any debt securities are listed or traded;
add, change or eliminate any provisions of the indenture in accordance with any amendments to the Trust Indenture Act, provided that the action does not adversely affect the rights or interests of any holder of debt securities issued thereunder; or
conform the text of the indenture or the Notes to any provisions of this “Description of the Exchange Notes,” as described in any officer’s certificate. (Section 901)
We may enter into one or more supplemental indentures to the indenture with the trustee to add to, change or eliminate provisions of the indenture or to modify the rights of the holders of one or more series of debt securities if we obtain the consent of the holders of a majority in principal amount of the outstanding debt securities of each series affected by the supplemental indenture, treated as one class. However, without the consent of the holders of each outstanding debt security affected by the supplemental indenture, we may not enter into a supplemental indenture that:
changes the stated maturity of the principal of, or any installment of principal of or interest on, any debt security, except to the extent permitted by the indenture;
reduces the principal amount of, or any premium or interest on, any debt security;
reduces the amount of principal of an original issue discount security or any other debt security payable upon acceleration of the maturity thereof;
changes the place or currency of payment of principal, premium, if any, or interest;
impairs the right to institute suit for the enforcement of any payment on any debt security;
reduces the percentage in principal amount of outstanding debt securities of any series, the consent of whose holders is required for modification of the indenture, for waiver of compliance with certain provisions of such indenture or for waiver of certain defaults;
makes certain modifications to the provisions for modification of the indenture and for certain waivers, except to increase the principal amount of debt securities necessary to consent to any such charge;
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makes any change that adversely affects the right to convert or exchange any debt security or decreases the conversion or exchange rate or increases the conversion price of any convertible or exchangeable debt security; or
changes the terms and conditions pursuant to which any series of debt securities is secured in a manner adverse to the holders of the debt securities. (Section 902)
Holders of a majority in principal amount of the outstanding debt securities of any series may waive past defaults or noncompliance with restrictive provisions of the indenture with respect to such series. However, the consent of holders of each outstanding debt security of a series is required to:
waive any default in the payment of principal, premium, if any, or interest, or
waive any covenants and provisions of the indenture that may not be amended without the consent of the holder of each outstanding debt security of the series affected. (Sections 513 and 1006)
To determine whether the holders of the requisite principal amount of the outstanding debt securities have taken an action under the indenture as of a specified date:
the principal amount of an “original issue discount security” that will be deemed to be outstanding will be the amount of the principal that would be due and payable as of that date upon acceleration of the maturity to that date;
if, as of that date, the principal amount payable at the stated maturity of a debt security is not determinable, for example, because it is based on an index, the principal amount of the debt security deemed to be outstanding as of that date will be an amount determined in the manner prescribed for the debt security;
the principal amount of a debt security denominated in one or more foreign currencies or currency units that will be deemed to be outstanding will be the United States dollar equivalent, determined as of that date in the manner prescribed for the debt security, of the principal amount of the debt security or, in the case of a debt security described in the two preceding bullet points, of the amount described above; and
debt securities owned by us or any other obligor upon the debt securities or any of our or their Affiliates will be disregarded and deemed not to be outstanding.
An “original issue discount security” means a debt security issued under the indenture which provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration of maturity. Some debt securities, including those for the payment or redemption of which money has been deposited or set aside in trust for the holders and those that have been fully defeased pursuant to Section 1402 of the indenture, will not be deemed to be outstanding. (Section 101)
We will generally be entitled to set any day as a record date for determining the holders of outstanding debt securities of any series entitled to give or take any direction, notice, consent, waiver or other action under the indenture. In limited circumstances, the trustee will be entitled to set a record date for action by holders of outstanding debt securities. If a record date is set for any action to be taken by holders of a particular series of debt securities, the action may be taken only by persons who are holders of outstanding debt securities of that series on the record date. To be effective, the action must be taken by holders of the requisite principal amount of debt securities within a specified period following the record date. For any particular record date, this period will be 180 days or such shorter period as we may specify, or the trustee may specify, if it set the record date. (Section 104)
Satisfaction and Discharge
We may discharge our obligations under the indenture with respect to the Notes while Notes remain outstanding if (1) all outstanding Notes have become due and payable, (2) all outstanding Notes have or will become due and payable at their scheduled maturity within one year, or (3) all outstanding Notes are scheduled for redemption in one year, and in each case, we have deposited with the trustee an amount sufficient to pay and discharge all outstanding Notes on the date of their scheduled maturity or the scheduled date of redemption.
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Defeasance
If we deposit with the trustee funds or government securities sufficient to make payments on the Notes on the dates those payments are due and payable, then, at our option, either of the following will occur:
we will be discharged from our obligations with respect to the Notes (“legal defeasance”); or
with respect to the Notes, we will no longer have any obligation to comply with the events of default in the third bullet point under “— Events of Default” and the events of default described in the fourth bullet point under “— Events of Default” and the restrictions described under “— Certain Covenants — Merger, Consolidation, Sale, Lease or Conveyance” will no longer apply to us, but some of our other obligations under the indenture and the Notes, including our obligation to make payments on the Notes, will survive.
If we defease the Notes, the holders of the Notes will not be entitled to the benefits of the indenture, except for our obligations to:
register the transfer or exchange of the Notes;
replace mutilated, destroyed, lost or stolen Notes; and
maintain paying agencies and hold moneys for payment in trust.
We will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the Notes to recognize gain or loss for federal income tax purposes and that the holders would be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the deposit and related defeasance had not occurred. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the United States Internal Revenue Service or a change in law to that effect. (Sections 1401, 1402, 1403 and 1404)
Paying Agent and Registrar
We will initially designate the trustee as the sole paying agent and registrar for the Notes.
We will pay interest on the Notes to the persons in whose names the Notes are registered at the close of business on the regular record date for each interest payment. However, we will pay the interest payable on the Notes at their stated maturity to the persons to whom we pay the principal amount of the Notes.
Any money deposited with the trustee or any paying agent for the payment of principal, premium, if any, and interest on the Notes that remains unclaimed for two years after the date the payments became due, may be repaid to us upon our request. After we have been repaid, holders entitled to those payments may only look to us for payment as our unsecured general creditors. The trustee and any paying agents will not be liable for those payments after we have been repaid. (Section 1003)
Exchange and Transfer of the Notes
We will issue the Notes in registered form, without coupons. We will issue Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Holders may present Notes for exchange or for registration of transfer at the office of the security registrar or at the office of any transfer agent we designate for that purpose. The security registrar or designated transfer agent will exchange or transfer the Notes if it is satisfied with the documents of title and identity of the person making the request. We will not charge a service charge for any exchange or registration of transfer of Notes. However, we may require payment of a sum sufficient to cover any tax or other governmental charge payable for the exchange or registration of transfer. The trustee will serve as the security registrar. (Section 305)
At any time we may:
designate additional transfer agents;
rescind the designation of any transfer agent; or
approve a change in the office of any transfer agent.
However, we are required to maintain a transfer agent in each place of payment for the Notes at all times. (Sections 305 and 1002)
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In the event we elect to redeem the Notes, neither we nor the trustee will be required to register the transfer or exchange of the Notes:
during the period beginning at the opening of business 15 days before the day we send the notice of redemption for the Notes and ending at the close of business on the day the notice is sent; or
if we have selected the Notes for redemption, in whole or in part, except for the unredeemed portion of the Notes. (Section 305)
Notices
Holders will receive notices by mail (or in accordance with the procedures of DTC) at their addresses as they appear in the security register. (Section 106)
Title
We may treat the person in whose name a Note is registered on the applicable record date as the owner of the Note for all purposes, whether or not it is overdue. (Section 309)
Governing Law
New York law will govern the indenture and the Notes. (Section 112)
Regarding the Trustee
Regions Bank will be the trustee, security registrar and paying agent under the indenture for the Notes. We maintain brokerage and lending relationships with the trustee and its affiliates, each of whom may maintain other relationships with us or our affiliates in the ordinary course of business.
If an event of default occurs under the indenture and is continuing, the trustee will be required to use the degree of care and skill of a prudent person in the conduct of that person’s own affairs. The trustee will become obligated to exercise any of its powers under the indenture at the request of any of the holders of any Notes issued under the indenture only after those holders have offered the trustee indemnity satisfactory to it.
If the trustee becomes one of our creditors, its rights to obtain payment of claims in specified circumstances, or to realize for its own account on certain property received in respect of any such claim as security or otherwise will be limited under the terms of the indenture. (Section 613) The trustee may engage in certain other transactions; however, if the trustee acquires any conflicting interest (within the meaning specified under the Trust Indenture Act), it will be required to eliminate the conflict or resign. (Section 608)
Book-Entry Delivery and Settlement
We will issue the Notes in the form of one or more global Notes in definitive, fully registered form. The global Notes will be registered in the name of Cede & Co., as nominee of DTC, and will remain in the custody of the trustee.
Beneficial interests in the global Notes will be represented through book-entry accounts of financial institutions acting on behalf of beneficial owners as direct and indirect participants in DTC. Investors may hold interests in the global Notes through DTC either directly if they are participants in DTC or indirectly through organizations that are participants in DTC. DTC has advised us as follows:
DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered under Section 17A of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
DTC holds securities that its participants deposit with DTC and facilitates the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in participants’ accounts, thereby eliminating the need for physical movement of securities certificates.
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Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and other organizations.
DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is owned by the users of its regulated subsidiaries.
Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly.
The rules applicable to DTC and its direct and indirect participants are on file with the SEC.
We have provided the description of the operations and procedures of DTC in this prospectus solely as a matter of convenience. These operations and procedures are solely within the control of DTC and are subject to change by it from time to time. Neither we, the initial purchasers of the Outstanding Notes or the trustee takes any responsibility for these operations or procedures, and you are urged to contact DTC or its participants directly to discuss these matters.
We expect that under procedures established by DTC:
upon deposit of the global Notes with DTC or its custodian, DTC will credit on its internal system the accounts of direct participants designated by the initial purchasers of the Outstanding Notes with portions of the principal amounts of the global Notes; and
ownership of the Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC or its nominee, with respect to interests of direct participants, and the records of direct and indirect participants, with respect to interests of persons other than participants.
The laws of some jurisdictions may require that purchasers of securities take physical delivery of those securities in definitive form. Accordingly, the ability to transfer interests in the Notes represented by a global Note to those persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person having an interest in Notes represented by a global Note to pledge or transfer those interests to persons or entities that do not participate in DTC’s system, or otherwise to take actions in respect of such interest, may be affected by the lack of a physical definitive security in respect of such interest.
So long as DTC or its nominee is the registered owner of a global Note, DTC or that nominee will be considered the sole owner or holder of the Notes represented by that global Note for all purposes under the indenture and under the Notes. Except as provided below, owners of beneficial interests in a global Note will not be entitled to have Notes represented by that global Note registered in their names, will not receive or be entitled to receive physical delivery of certificated Notes and will not be considered the owners or holders thereof under the indenture or under the Notes for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee. Accordingly, each holder owning a beneficial interest in a global Note must rely on the procedures of DTC and, if that holder is not a direct or indirect participant, on the procedures of the participant through which that holder owns its interest, to exercise any rights of a holder of Notes under the indenture or the global Note.
Neither we nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of the Notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to the Notes.
Payments on the Notes represented by the global Notes will be made to DTC or its nominee, as the case may be, as the registered owner thereof. We expect that DTC or its nominee, upon receipt of any payment on the Notes represented by a global Note, will credit participants’ accounts with payments in amounts proportionate to their respective beneficial interests in the global Note as shown in the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in the global Note held through such participants will be governed by standing instructions and customary practice as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. The participants will be responsible for those payments.
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Initial settlement for the Notes will be made in immediately available funds. Secondary market trading between DTC participants will occur in the ordinary way in accordance with DTC rules and will be settled in immediately available funds. Although DTC has agreed to the foregoing procedures to facilitate transfers of the Notes among its participants, it is under no obligation to perform or continue to perform such procedures and such procedures may be changed or discontinued at any time.
Secondary market trading between Clearstream Banking, société anonyme (“Clearstream”) participants and/or Euroclear Bank S.A./N.V., as operator of the Euroclear System (“Euroclear”) participants will occur in the ordinary way in accordance with the applicable rules and operating procedures of Clearstream and Euroclear, as applicable.
Cross-market transfers between participants in DTC, on the one hand, and participants in Euroclear or Clearstream, on the other hand, will be effected through DTC in accordance with the DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective United States depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (European time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its United States depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the global securities through DTC, and making or receiving payment in accordance with normal procedures for same-day fund settlement. Participants in Euroclear or Clearstream may not deliver instructions directly to their respective United States depositaries.
Due to time zone differences, the securities accounts of a participant in Euroclear or Clearstream purchasing an interest in a global security from a direct participant in DTC will be credited, and any such crediting will be reported to the relevant participant in Euroclear or Clearstream, during the securities settlement processing day (which must be a business day for Euroclear or Clearstream) immediately following the settlement date of DTC. Cash received in Euroclear or Clearstream as a result of sales of interests in a global security by or through a participant in Euroclear or Clearstream to a direct participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.
Certificated Notes
Certificated Notes will be issued to each person that DTC identifies as the beneficial owner of the Notes represented by the global Notes, upon surrender by DTC of the global Notes, if (i) DTC or any successor depositary (the “depositary”) notifies us that it is no longer willing or able to act as a depositary for the global Notes or DTC ceases to be registered as a clearing agency under the Exchange Act, and a successor depositary is not appointed within 90 days of such notice or cessation, (ii) we, at our option and subject to DTC procedures, notify the trustee in writing that we elect to cause the issuance of Notes in definitive form under the indenture or (iii) upon the occurrence of certain other events as provided pursuant to the indenture.
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REGISTRATION RIGHTS AGREEMENT

We entered into a registration rights agreement with the initial purchasers of the Outstanding Notes on May 17, 2016September 11, 2019 in connection with the closing of the private offering of the Outstanding Notes. In thatthe registration rights agreement, we agreed for the benefit of the holders of the Outstanding Notes that we willto use ourcommercially reasonable best efforts to file with(a) as soon as practicable after the Commission and cause to become effectiveclosing of the private offering of the Outstanding Notes, but in any event within 365 days after the closing date of the private offering of the Outstanding Notes, file a registration statement relatingon an appropriate registration form with respect to an offerregistered offers to exchange the notesOutstanding Notes for an issue of Commission-registerednew notes with terms substantially identical in all material respects to the notesOutstanding Notes (except that the Exchange Notes arewill not be subject to additional interest provisions or restrictions on ownership or transfer), (b) cause the registration statement to be declared effective under the Securities Act within 365 days after the closing date of the private offering of the Outstanding Notes and (c) file any pre- and post-effective amendments, if applicable, and any filings required in connection with the registration and qualification of the Exchange Notes under state securities laws.
When the SEC declares the exchange offer registration statement effective, we will offer the Exchange Notes in return for the Outstanding Notes. The exchange offer will remain open for at least 20 business days (or longer if required by applicable law) after the date we send notice of the exchange offer to the holders of Outstanding Notes. For each Outstanding Note surrendered to us in the exchange offer, the holders of the Outstanding Notes will receive an Exchange Note of equal principal amount. Interest on each Exchange Note will accrue (a) from the last interest payment date on which interest was paid on the Outstanding Note surrendered in exchange therefor or (b) if no interest has been paid on the Outstanding Note, from the closing date of the private offering of the Outstanding Notes. A holder of Outstanding Notes that participates in the exchange offer will be required to make certain representations to us (as described in the registration rights agreement). We will use commercially reasonable efforts to commence the exchange offer not later than 30 days after the registration statement has become effective. Under existing interpretations of the SEC contained in several no-action letters to third parties, the Exchange Notes will generally be freely transferable after the exchange offer without further registration under the Securities Act, except that any broker-dealer that participates in the exchange offer must deliver a prospectus meeting the requirements of the Securities Act when it resells the Exchange Notes.
We will agree to use commercially reasonable efforts to make available, for a period ending on the earlier of (a) 180 days after the date the registration statement is declared effective and (b) the date upon which a broker-dealer is no longer required to deliver a prospectus, a prospectus meeting the requirements of the Securities Act for use by participating broker-dealers and other persons, if any, with similar prospectus delivery requirements for use in connection with any resale of Exchange Notes. Outstanding Notes not tendered in the exchange offer will bear interest at the rates set forth on the cover page of this prospectus and be subject to all the terms and conditions specified in the indenture, including transfer orrestrictions, but will not retain any rights under the registration rights agreement (including with respect to any increaseincreases in annual interest rate as described below).

If applicable interpretations after the consummation of the staff of the Commission doexchange offer.

If (a) we are not permit usrequired to effectfile a registration statement or consummate the exchange offer because it would violate any applicable law or applicable policies of the SEC or (b) with respect to any holder of the Outstanding Notes (i) such holder is prohibited by applicable law or SEC policy from participating in the exchange offer, (ii) such holder may not resell the Outstanding Notes acquired by it in the exchange offer to the public without delivering a prospectus and the prospectus contained in the registration statement is not appropriate or available for such resales by such holder or (iii) such holder is a broker-dealer and holds Outstanding Notes acquired directly from us or one of our affiliates, then we are required towill use ourcommercially reasonable best efforts to cause to become effective a shelf registration statement relating to resales of the notesOutstanding Notes and to keep that shelf registration statement effective, supplemented and amended and to ensure that it conforms with the requirements of the registration rights agreement, the Securities Act and the policies of the SEC for a period ofat least two years following the effective date of such shelf registration statement, or if earlier, the date on whichsuch shorter period that will terminate when all notesOutstanding Notes covered by the shelf registration statement have been sold. We will, in the event of such a shelf registration, providesold pursuant 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 resalesstatement. A holder of the notes. A noteholderOutstanding Notes that sells notesOutstanding Notes under the shelf registration statement generallywill be required to provide us with certain information for use in connection with any shelf registration statement or prospectus included therein within 20 business days after receiving a request by us to do so. Each holder as to which any shelf registration statement is being effected agrees to furnish promptly to us all information required to be disclosed in order to make the information previously provided by such holder not materially misleading.
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A holder of Outstanding Notes that sells Outstanding Notes under the shelf registration statement will be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with those sales and will be bound by the provisions of the registration rights agreement that are applicable to such a noteholderholder of Outstanding Notes (including certain indemnification obligations).

Pursuant Holders of Outstanding Notes will also be required to the termssuspend their use of the prospectus included in the shelf registration rights agreement, we agreed to use commercially reasonable efforts to (a) as soon as practicable after the closingstatement under specified circumstances upon receipt of notice from us. Under applicable interpretations 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 offersstaff of the SEC, our affiliates will not be permitted to exchange thetheir Outstanding Notes for Exchange Notes (b) causein 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. exchange offer.

If (a) any of the registration statements required to be filed by the registration rights agreement have not been filed on or before the date specified, (b) any of such registration statements have not been declared effective on or before the date specified, (c) the exchange offer has not been consummated within 30 days or 45 days, as applicable, after the registration statement has been declared effective or (d) any registration statement has been declared effective and such registration statement ceases to be effective or fails to be usable without being succeeded immediately by a post-effective amendment to such registration statement that is immediately declared effective (each, a “Registration Default”), then additional interest shall accrue on the principal amount of the Outstanding Notes at a rate of 0.25% per annum for the first 90-day period following a Registration Default and an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue (provided that the rate at which such additional interest accrues may in no event exceed 1.00% per annum in the aggregate for all Registration Defaults). Following the cure of a Registration Default, the interest rate will be reduced to the original interest rate. If a different Registration Default occurs after such reduction, the interest rate will again be increased as described above.

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

Any amounts of May 17, 2016. This Registration Default triggered additional interest to accruedue will be payable in cash 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 additionalsame original interest payment dates as interest on the Outstanding Notes is payable. The Exchange Notes will increase and begin to accrue at 0.50% per annum. Additional interest will continue to accrue onbe accepted for clearance through DTC.
This summary of the Outstanding Notes untilprovisions of the registration statement, of which this prospectus forms a part,rights agreement does not purport to be complete and is declared effective.

If we effect the exchange offer, we will be entitledsubject to, close the exchange offer not earlier than 20 business days afterand is qualified in 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 subjectentirety by reference to, all the terms and conditions specified inprovisions of the indenture, including transfer restrictions.registration rights agreement, copies of which are available from us upon request.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENCES
The precedingfollowing discussion 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.

MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain material United States federal income tax considerations, that may beas of the date of this prospectus, relevant to a beneficial owner of Outstanding Notes (for the purposes of this section, a “holder”) relating to the exchange of Outstanding Notes for Exchange Notes andpursuant to the ownership and disposition of the Exchange Notes, but does not purport to be an analysis of all potential tax effects.exchange offer. This summary is based onupon provisions of the Internal Revenue Code of 1986, as amended (the “Code”),IRC, applicable Treasury regulations, administrative pronouncements,rulings and judicial decisions, and final, temporary, and proposed Treasury Regulations, all as in effect onof the date hereof and allof this prospectus, any of which are subjectmay subsequently be changed, possibly retroactively, so as to change, possibly with retroactive effect, or toresult in United States federal income tax consequences 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 mattersthose discussed below. Accordingly, there can be no assurance

We cannot assure you that the IRS or a court will not take a different position concerningchallenge one or more of the tax consequences described in this discussion. We have not obtained, nor do we intend to obtain, a ruling from the IRS with respect to the United States federal income tax consequences described below.

If the IRS contests a conclusion set forth herein, no assurance can be given that a holder would ultimately prevail in a final determination by a court.

This summary only applies only to holders that are beneficial owners ofacquired their Outstanding Notes that purchasedupon original issuance, exchange their Outstanding Notes for Exchange Notes, and hold the Outstanding Notes in the initial offering at their original “issue price” (the first price at which a substantial amount of the notes is soldand Exchange Notes as capital assets 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 CodeUnited States federal income tax purposes (generally property held for investment). This summary does not discuss any aspect of United States federal tax law other than income taxation, and does not address thestate, local or foreign tax considerations that may be relevant to subsequent purchasers of the Outstanding Notes or Exchange Notes. Thisconsiderations. Moreover, this summary does not discussaddress all aspects of United States federal income taxation that may be relevant to holders, in light of their particular circumstances or status, ornor does it address all tax consequences that may be relevant to such holders in light of their personal circumstances or particular situations, such as:
tax consequences to investors that may be subject to special tax rulestreatment, including brokers, dealers in securities, banks, financial institutions, regulated investment companies, real estate investment trusts, tax-exempt entities, retirement plans and other tax-deferred accounts, insurance companies, partnerships or other pass-through entities for United States federal income tax purposes (or investors in such entities), certain former citizens or former long-term residents of the United States, or traders in securities that elect to use a mark-to-market method of tax accounting for their securities;
tax consequences to persons holding Outstanding Notes or Exchange Notes as a part of an integrated or conversion transaction or a straddle, or persons deemed to sell Exchange Notes under the constructive sale provisions of the IRC;
tax consequences to United States holders whose “functional currency” is not the United States dollar; and
tax consequences under the alternative minimum tax provisions of the IRC.
Investors should consult their own tax advisors concerning the United States federal income tax laws (including, for example, financial institutions, broker-dealers, tradersconsequences in securities that elect mark-to-market tax treatment, corporations treatedlight of their own specific situations, 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 noteswell 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(such as the federal estate andor gift tax laws) orand the lawlaws of any state, local, foreign or other taxing jurisdiction.

If a partnership (including anyan entity or arrangement treated as a partnership for United States federal income tax purposes) is a beneficial owner of a note,purposes holds Outstanding Notes, the tax treatment of a partner in thatof such partnership will generally depend onupon the status of the partner and the activities of the partner and the partnership. Holders of notesAny beneficial owner holding Outstanding Notes through an entity or arrangement that are partnerships and partners in those partnerships are urged to consult their tax advisors regarding themay be treated as a partnership for United States federal income tax purposes is urged to consult its own tax advisor regarding the tax consequences of the exchange offer to such partner.
Exchange of Outstanding Notes Pursuant to the Exchange Offer
The exchange of Outstanding Notes for Exchange Notes 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

(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 asconstitute a taxable sale or exchange for United States federal income tax purposes. Accordingly,

U.S. holdersexchange. As a result, (1) a holder will not recognize a taxable gain or loss as a result of exchanging such holder’s Outstanding Notes for Exchange Notes in the exchange;

exchange offer; (2) the holding period of the Exchange Notes received will include the holding period of the Outstanding Notes exchanged therefor; and (3) the adjusted tax basis of anthe Exchange Note immediately after the exchangeNotes received will be the same as the adjusted tax basis of the Outstanding NoteNotes 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.

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. holdersexchange. Holders should consult their own tax advisors before making this election.

A U.S. holder who does not elect to includeregarding 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 forpotential 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 maturityconsequences 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

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 Exchange Notes in the exchange offer.

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THE PRECEDING DISCUSSION OF UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. WE URGE EACH HOLDER TO CONSULT ITS OWN TAX ADVISOR REGARDING THE PARTICULAR UNITED STATES FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF EXCHANGING OUTSTANDING NOTES FOR EXCHANGE NOTES PURSUANT TO THE EXCHANGE OFFER, INCLUDING THE CONSEQUENCES OF ANY PROPOSED CHANGE IN APPLICABLE LAWS.
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PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe that you may transfer Exchange Notes issued in the exchange offer in exchange for the Outstanding Notes if:
any Exchange Notes to be received by you will be acquired in the ordinary course of your business; and
you have no arrangement or understanding with any person or entity to participate in the distribution (within the meaning of the Securities Act) of the Exchange Notes in connection withviolation of the provisions of the Securities Act.
You may not participate in the exchange offer if you are:
an “affiliate,” as defined in Rule 405 under the Securities Act, of us; or
a broker-dealer that will not be treatedreceive Exchange Notes for your own account in exchange for Outstanding Notes that were acquired as a taxable saleresult of market-making or exchange for United States federal income tax purposes.

Interest on the Notes

Subjectother trading activities, unless you agree to deliver this prospectus (or, to the discussion below concerning effectively connected income, backup withholding, and FATCA, paymentsextent permitted by law, make this prospectus available to purchasers) in connection with any resale 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

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

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 theyour 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.

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 athis prospectus in connection with any resale of thosesuch Exchange Notes. A broker-dealerTo date, the staff of the SEC has taken the position that broker-dealers may usefulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as the exchange offer, other than a resale of an unsold allotment from the original sale of the Outstanding Notes, with this prospectus. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received for their own account in exchange for Outstanding Notes where the broker-dealer acquired thosesuch Outstanding Notes were acquired 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,ending on     , 2020, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with those resales.

any such resale. In addition, until such date, all dealers effecting transactions in Exchange Notes may be required to deliver this prospectus.

If you wish to exchange your Outstanding Notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer — Procedures for Tendering” in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your Outstanding Notes in the exchange offer. In addition, if you are a broker-dealer who receives Exchange Notes for your own account in exchange for Outstanding Notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver this prospectus in connection with any resale by you of such Exchange Notes.
We will not receive any proceeds from any sale of Exchange Notes by broker-dealers. Broker-dealers may sell Exchange Notes received by thembroker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions transactions:
in the over-the-counter market, market;
in negotiated transactions, transactions;
through the writing of options on the Exchange NotesNotes; or
a combination of thosesuch methods of resale,resale; at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices.
Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such Exchange Notes.

Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of thosesuch 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. TheEach letter of transmittal states that by acknowledging that it will deliver and by delivering athis prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

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For athe period described in Section 4(3) of 180 days afterand Rule 174 under the expiration date ofSecurities Act that is applicable to transactions by brokers or dealers with respect to the exchange offer,Exchange Notes, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests these documents in the letter of transmittal. such documents.
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(including any broker-dealers,broker-dealers) against specifiedcertain 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.

LEGAL MATTERS

The validity of the Exchange Notes offered hereby will be passed upon for us by Locke Lord LLP,Baker Botts L.L.P., Houston, Texas. Locke Lord LLPBaker Botts L.L.P. will deliver an opinion stating that the notesExchange Notes will be binding obligations of Cleco. In rendering its opinion, Locke Lord LLPBaker Botts L.L.P. will rely on the opinion of Baker, Donelson, Bearman, Caldwell & Berkowitz, PC, New Orleans, Louisiana,Phelps Dunbar, L.L.P., with respect to certain matters regarding Louisiana law.

EXPERTS

The financial statements for Cleco Corporate Holdings LLC as of December 31, 20162019 and 2018 and for each of the three years in the period April 13, 2016 toended December 31, 2016 (Successor)2019 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 Cleco Power LLC as of December 31, 2019 and 2018 and for each of the three years in the period January 1, 2016 to April 12, 2016 (Predecessor)ended December 31, 2019 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

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.

EXCHANGE AGENT

We have appointed Wells FargoRegions Bank N.A. as exchange agent in connection with the exchange offer. Holders of Outstanding Notes should direct questions, requests for assistance or additional copies of thethis prospectus or letters of transmittal or notices of guaranteed delivery to the exchange agent as follows:

REGIONS BANK
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 ConfirmationBy Registered or Certified Mail
Corporate Trust Operations
Lakeshore Operations Center
201 Milan Parkway, 2nd Floor
Birmingham, Alabama 35211

Holders can inquire about the exchange of Outstanding Notes for Exchange Notes in the exchange offer by Telephone:

1-800-344-5128

calling Regions Bank at 1-866-512-3479. Please refer to the following numbers when making inquiries: CUSIPs: 144A: 18551Q AA5; Reg. S U1851U AA6.

Delivery of a letter of transmittal to any address or facsimile number other than the one set forth above will not constitute a valid delivery.

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INDEX TO CONSOLIDATED

TABLE OF CONTENTS

FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Consolidated Financial Statements (Audited)

F-2

F-3

Report of Independent Registered Public Accounting Firms

F-3

Report of Independent Registered Public Accounting Firms

F-4

Financial Statements of Cleco


F-5


F-6

F-7

F-9

F-11

F-12

Report of Independent Registered Public Accounting Firms

F-13

Financial Statements of Cleco Power


F-14

F-15

F-16

F-18

F-20

F-21

F-83

F-84

F-85

F-86

F-87

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

Condensed Consolidated Financial Statements (Unaudited)
Financial Statements of Cleco
Financial Statements of Cleco Power

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

TABLE OF CONTENTSManagement’s

Managements’ Reports on Internal Control Over Financial Reporting

The management of Cleco and Cleco Power isare 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’sCleco’s internal control over financial reporting is a process designed by, or under the supervision of, each of Cleco and Cleco Power’sCleco’s principal executive and financial officers and effected by Cleco and Cleco Power’sCleco’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 disclosurespurposes in the financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even

accordance with generally accepted accounting principles.

those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

BecauseAs a result of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness toin 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’Cleco’s principal executive officer and principal financial officer, conducted an assessment of the effectiveness of Cleco and Cleco Power’s respectiveCleco’s internal control over financial reporting as of December 31, 2016.2019. In making this assessment, management used the criteria in Internal Control—IntegratedControl-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’2019, Cleco’s internal control over financial reporting was effective.

not effective due to the material weaknesses in internal control over financial reporting discussed below.
On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in South Central Generating in a purchase business combination. Management has excluded South Central Generating from Cleco’s assessment of internal control over financial reporting as of December 31, 2019. South Central Generating is a wholly-owned subsidiary and represented approximately 14% of consolidated total assets as of December 31, 2019, and 30% of consolidated total revenues for the year ended December 31, 2019.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.
During the three months ended June 30, 2019, Cleco transitioned to a new enterprise business application (ERP) which required it to modify certain existing and implement new processes and internal controls to adapt to the new application. Subsequent to the implementation, a material weakness related to the design and operation of certain information technology (IT) general controls for information systems that are relevant to the preparation of the financial statements were identified.
Specifically, Cleco did not sufficiently design and maintain (i) testing and approval controls for program development to ensure the implementation of a new ERP system is aligned with business and IT requirements which contributed to deficiencies related to (ii) user access controls to ensure appropriate segregation of duties and that adequately restrict user and privileged access to certain financial applications, programs, and data to appropriate personnel, and (iii) program change management controls for certain financial systems to ensure that information technology program and data changes affecting financial IT applications and underlying accounting records are identified, tested, authorized, and implemented appropriately.
These IT deficiencies did not result in a material misstatement to the financial statements; however, the deficiencies, when aggregated, could impact maintaining effective segregation of duties, as well as the effectiveness of IT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports) that could result in misstatements potentially impacting all financial statement accounts and disclosures that would not be prevented or detected. Accordingly, management has determined these deficiencies in the aggregate constitute a material weakness.
Cleco also identified a material weakness in the design and operating effectiveness of controls over the completeness and accuracy of billed and unbilled revenue from contracts with customers. Specifically, there were deficiencies in controls to (i) verify the accuracy of billing estimates, (ii) record revenue in the appropriate period, and (iii) validate the completeness and accuracy of reports used in recording unbilled revenue.
F-2

TABLE OF CONTENTS

The deficiencies resulted in immaterial errors and out-of-period adjustments in recorded retail revenue, customer accounts receivable, and unbilled revenue for the interim periods ended June 30, 2019, and September 30, 2019. However, the identified control deficiencies could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Because of these material weaknesses, the management of Cleco concluded that Cleco did not maintain effective internal control over financial reporting as of December 31, 2019.
Remediation Plan
Cleco began taking steps to remediate the underlying cause of these material weaknesses and improve the design and operating effectiveness of its internal control over financial reporting during the three month period ending September 30 2019, and continued this effort through December 31, 2019. This plan includes, but is not limited to the following:
Providing additional training and instructional guidance to control owners on management’s expectations for control performance and related evidence to maintain.
Reassessing extent of access assigned to users to ensure the access granted is commensurate with each user’s respective roles and responsibilities.
Enabled configurations to allow for automated exception identification in key processes.
Enhancing the level of precision and addressing identified gaps in the design of existing controls.
Designing and implementing new controls (both preventive and detective) to address any gaps in how relevant risks are being addressed.
Performing additional monitoring and testing over the implementation and operating effectiveness of existing controls.
Performing an assessment of the newly implemented ERP system to identify opportunities for more comprehensive control coverage over identified risks as well as opportunities for enhanced system automation.
As the management of Cleco continues to evaluate and work to improve Cleco’s internal control over financial reporting, Cleco may take additional measures to address these control deficiencies, or Cleco may modify some of the remediation measures to improve the design and/or operating effectiveness of those measures. Management of Cleco has made significant progress in its remediation efforts. However, the material weakness in IT general controls and the material weakness over revenue will not be considered remediated until the applicable new controls operate for a sufficient period of time where management is able to conclude, through testing, that these controls are operating effectively.
Changes in Internal Control over Financial Reporting
There have been no changes in Cleco’s internal control over financial reporting that occurred during the quarter ended December 31, 2019, that have materially affected, or are reasonably likely to materially affect, Cleco’s internal control over financial reporting, with the exception of the remediation efforts discussed above.
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TABLE OF CONTENTS

Report of Independent Registered Public Accounting Firm

To the Board of Managers and Member of

Cleco Corporate Holdings LLC

Pineville, Louisiana

In our opinion,

Opinion on the Financial Statements
We have audited the accompanying consolidated statements listed in the index appearing under item 15(a)(1) present fairly, in all material respects, the financial positionbalance sheets of Cleco Corporate Holdings LLC and its subsidiaries (the “Company”) as of December 31, 20162019 and 2018, and the related consolidated statements of income, of comprehensive income, of member's equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes and schedules of condensed financial information of parent as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019 and of valuation and qualifying accounts for each of the three years in the period ended December 31, 2019 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of theirits operations and theirits cash flows for each of the three years in the period April 13, 2016 toended December 31, 2016 (Successor)2019 in conformity with accounting principles generally accepted in the United States of America. In addition,
Change in our opinion, the financial statement schedules listedAccounting Principle
As discussed in the index appearing under Item 15(a)(2) as of December 31, 2016 and for the period of April 13, 2016Note 4 to December 31, 2016 presents fairly, in all material respects, the information set forth therein when read in conjunction with the consolidated financial statements. statements, the Company changed the manner in which it accounts for leases as of January 1, 2019.
Basis for Opinion
These consolidated financial statements and financial statement schedules are the responsibility of the

Company’s management. Our responsibility is to express an opinion on thesethe Company’s consolidated financial statements and financial statement schedules based on our audit. audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our auditaudits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
New Orleans, LA
March 3, 2020
We have served as the Company’s auditor since 2016.
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TABLE OF CONTENTS

CLECO
Consolidated Statements of Income
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating revenue
 
 
 
Electric operations
$1,496,736
$1,181,907
$1,097,632
Other operations
182,832
82,332
79,580
Gross operating revenue
1,679,568
1,264,239
1,177,212
Electric customer credits
(39,963)
(33,195)
(1,566)
Operating revenue, net
1,639,605
1,231,044
1,175,646
Operating expenses
 
 
 
Fuel used for electric generation
466,831
382,556
339,346
Purchased power
280,991
168,180
152,913
Other operations and maintenance
291,031
197,032
197,608
Depreciation and amortization
216,320
170,414
166,854
Taxes other than income taxes
61,870
48,791
48,546
Merger transaction and commitment costs
7,668
19,514
5,152
Total operating expenses
1,324,711
986,487
910,419
Operating income
314,894
244,557
265,227
Interest income
6,090
6,073
1,424
Allowance for equity funds used during construction
15,397
14,159
8,320
Other income (expense), net
758
(14,328)
(6,899)
Interest charges
 
 
 
Interest charges, net
147,346
131,348
125,200
Allowance for borrowed funds used during construction
(6,037)
(4,706)
(2,287)
Total interest charges
141,309
126,642
122,913
Income before income taxes
195,830
123,819
145,159
Federal and state income tax expense
43,165
29,382
7,079
Net income
$152,665
$94,437
$138,080
The accompanying notes are an integral part of the consolidated financial statements.
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TABLE OF CONTENTS

CLECO
Consolidated Statements of Comprehensive Income
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Net income
$152,665
$94,437
$138,080
Other comprehensive (loss) income, net of tax
 
 
 
Postretirement benefits (loss) gain (net of tax benefit of $6,808, tax expense of $1,868, and tax benefit of $2,764, respectively)
(19,299)
5,296
(4,421)
Total other comprehensive (loss) income, net of tax
(19,299)
5,296
(4,421)
Comprehensive income, net of tax
$133,366
$99,733
$133,659
The accompanying notes are an integral part of the consolidated financial statements.
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TABLE OF CONTENTS

CLECO
Consolidated Balance Sheets
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Assets
 
 
Current assets
 
 
Cash and cash equivalents
$116,292
$110,175
Restricted cash and cash equivalents
11,100
11,241
Customer accounts receivable (less allowance for doubtful accounts of $3,005 in 2019 and $814 in 2018)
83,591
50,043
Other accounts receivable
35,731
27,196
Unbilled revenue
33,207
35,314
Fuel inventory, at average cost
83,061
82,836
Materials and supplies, at average cost
118,858
92,671
Energy risk management assets
7,023
23,355
Accumulated deferred fuel
22,910
20,112
Cash surrender value of company-/trust-owned life insurance policies
86,096
80,391
Prepayments
7,711
7,911
Regulatory assets
19,807
22,461
Other current assets
12,688
1,256
Total current assets
638,075
564,962
Property, plant, and equipment
 
 
Property, plant, and equipment
4,982,255
3,728,477
Accumulated depreciation
(454,874)
(303,727)
Net property, plant, and equipment
4,527,381
3,424,750
Construction work in progress
117,630
354,045
Total property, plant, and equipment, net
4,645,011
3,778,795
Equity investment in investee
17,072
18,172
Goodwill
1,490,797
1,490,797
Prepayments
25,949
2,251
Operating lease right of use assets
28,791
Restricted cash and cash equivalents
15,203
18,670
Note receivable
15,198
15,829
Regulatory assets
422,431
425,330
Intangible assets
138,103
84,307
Other deferred charges
39,668
37,701
Total assets
$7,476,298
$6,436,814
The accompanying notes are an integral part of the consolidated financial statements.
F-7

TABLE OF CONTENTS

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Liabilities and member’s equity
 
 
Liabilities
 
 
Current liabilities
 
 
Long-term debt and finance leases due within one year
$125,986
$21,128
Accounts payable
158,863
156,589
Accounts payable- affiliate
33,780
Customer deposits
58,289
61,736
Provision for rate refund
38,903
35,842
Taxes payable, net
8,931
43,674
Interest accrued
19,001
15,828
Energy risk management liabilities
4,113
468
Regulatory liabilities – other
6,675
2,496
Deferred compensation
12,115
10,753
Other current liabilities
44,683
30,536
Total current liabilities
511,339
379,050
Long-term liabilities and deferred credits
 
 
Accumulated deferred federal and state income taxes, net
657,058
608,030
Postretirement benefit obligations
283,075
249,264
Regulatory liabilities – other
2,496
Regulatory liabilities – deferred taxes, net
146,948
155,537
Restricted storm reserve
12,285
15,485
Deferred lease revenue
49,862
Intangible liabilities
31,872
Asset retirement obligations
23,173
6,881
Operating lease liabilities
25,779
Other deferred credits
27,222
20,846
Total long-term liabilities and deferred credits
1,257,274
1,058,539
Long-term debt and finance leases, net
3,064,679
2,874,485
Total liabilities
4,833,292
4,312,074
Commitments and contingencies (Note 15)
 
 
Member’s equity
2,643,006
2,124,740
Total liabilities and member’s equity
$7,476,298
$6,436,814
The accompanying notes are an integral part of the consolidated financial statements.
F-8

TABLE OF CONTENTS

CLECO
Consolidated Statements of Cash Flows
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating activities
 
 
 
Net income
$152,665
$94,437
$138,080
Adjustment to reconcile net income to net cash provided by operating activities
 
 
 
Depreciation and amortization
245,682
187,426
186,326
Provision for doubtful accounts
2,348
797
2,778
Unearned compensation expense
5,409
5,837
3,745
Allowance for equity funds used during construction
(15,397)
(14,159)
(8,320)
Loss on risk management assets and liabilities, net
10,180
Deferred lease revenue
(8,439)
Deferred income taxes
40,081
6,543
(41,966)
Deferred fuel costs
11,132
(18,549)
11,909
Cash surrender value of company-/trust-owned life insurance
(5,705)
2,726
(5,892)
Changes in assets and liabilities
 
 
 
Accounts receivable
(9,532)
3,123
(25,584)
Accounts receivable – affiliate
(1,041)
635
(622)
Unbilled revenue
2,107
1,084
(2,129)
Fuel inventory and materials and supplies
18,463
(2,981)
(44,995)
Prepayments
(14,479)
153
2,852
Accounts payable
13,507
18,898
14,705
Accounts payable – affiliate
3,175
Customer deposits
5,888
13,757
12,381
Provision for merger commitments
(1,848)
(3,273)
(12,971)
Postretirement benefit obligations
(10,981)
4,646
4,884
Regulatory assets and liabilities, net
90
3,032
12,531
Other deferred accounts
(7,147)
(9,748)
(8,380)
Taxes accrued
(3,619)
20,976
23,118
Interest accrued
3,173
1,124
(582)
Deferred compensation
1,316
(1,521)
308
Other operating
(6,909)
2,798
3,252
Net cash provided by operating activities
430,119
317,761
265,428
Investing activities
 
 
 
Additions to property, plant, and equipment
(323,791)
(291,061)
(236,932)
Allowance for equity funds used during construction
15,397
14,159
8,320
Proceeds from sale of property, plant, and equipment
739
995
17,499
Reimbursement for property loss
141
1,375
187
Return of equity investment in investee
1,100
500
Return of investment in company-owned life insurance
3,761
Return of equity investment in tax credit fund
1,625
2,775
7,502
Issuance of note receivable
(16,800)
Payment to acquire business, net of cash received
(814,969)
Other investing
574
397
(630)
Net cash used in investing activities
(1,115,423)
(288,160)
(203,554)
The accompanying notes are an integral part of the consolidated financial statements.
F-9

TABLE OF CONTENTS

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Financing activities
 
 
 
Draws on credit facilities
108,000
179,000
Payments on credit facilities
(108,000)
(179,000)
Issuances of long-term debt
700,000
50,000
125,000)
Repayments of long-term debt
(390,571)
(19,193)
(17,896)
Payment of financing costs
(5,959)
(791)
(463)
Contribution from member
384,900
Distributions to member
(71,350)
(84,065)
Other financing
(557)
(383)
(1,819)
Net cash provided by (used in) financing activities
687,813
(41,717)
20,757
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents
2,509
(12,116)
82,631
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period
140,086(1)
152,202
69,571
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period
$142,595(2)
$140,086
$152,202
 
 
 
 
Supplementary cash flow information
 
 
 
Interest paid, net of amount capitalized
$130,988
$124,154
$118,009
Income taxes (refunded) paid, net
$(19)
$272
$(6)
Supplementary non-cash investing and financing activities
 
 
 
Accrued additions to property, plant, and equipment
$16,124
$56,450
$31,083
Non-cash additions to property, plant, and equipment
$52
$1,224
$3,015
Incurrence of finance lease obligation – barges
$
$16,800
$
(1)
Includes cash and cash equivalents of $110,175, current restricted cash and cash equivalents of $11,241, and non-current restricted cash and cash equivalents of $18,670.
(2)
Includes cash and cash equivalents of $116,292, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $15,203.
The accompanying notes are an integral part of the consolidated financial statements.
F-10

TABLE OF CONTENTS

CLECO
Consolidated Statements of Changes in Member’s Equity
(THOUSANDS)
MEMBERSHIP
INTEREST
RETAINED
EARNINGS /
(ACCUMULATED
DEFICIT)
AOCI
TOTAL
MEMBER’S
EQUITY
Balances, Dec. 31, 2016
$2,069,376
$(24,113)
$1,500
$2,046,763
Distributions to member
(84,065)
(84,065)
Net income
138,080
138,080
Other comprehensive loss, net of tax
(4,421)
(4,421)
Balances, Dec. 31, 2017
$2,069,376
$29,902
$(2,921)
$2,096,357
Distributions to member
(71,350)
(71,350)
Net income
94,437
94,437
Other comprehensive income, net of tax
5,296
5,296
Reclassification of effect of tax rate change
589
(589)
Balances, Dec. 31, 2018
$2,069,376
$53,578
$1,786
$2,124,740
Contributions from member
384,900
384,900
Net income
152,665
152,665
Other comprehensive loss, net of tax
(19,299)
(19,299)
Balances, Dec. 31, 2019
$2,069,376
$591,143
$(17,513)
$2,643,006
The accompanying notes are an integral part of the consolidated financial statements.
F-11

TABLE OF CONTENTS

Report of Independent Registered Public Accounting Firm
To the Board of Managers and Member of Cleco Power LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Cleco Power LLC and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive income, of member's equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes and schedule of valuation and qualifying accounts for each of the three years in the period ended December 31, 2019 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 4 to the consolidated financial statements, the Company changed the manner in which it accounts for leases as of January 1, 2019.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States). (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. Anmisstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit includesof its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding 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

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 assessingevaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statement presentation.statements. 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,

/s/ PricewaterhouseCoopers LLP
New Orleans, LA
March 3, 2020
We have served as 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
Company’s auditor since 2016.
F-12

TABLE OF CONTENTS

CLECO

POWER
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 
  

 

 

   

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating revenue
 
 
 
Electric operations
$1,130,928
$1,191,587
$1,108,389
Other operations
$72,833
$82,330
$77,522
Affiliate revenue
$3,125
$874
$851
Gross operating revenue
$1,206,886
$1,274,791
$1,186,762
Electric customer credits
$(38,516)
$(33,195)
$(1,566)
Operating revenue, net
$1,168,370
$1,241,596
$1,185,196
Operating expenses
 
 
 
Fuel used for electric generation
$385,317
$382,556
$339,346
Purchased power
$111,208
$168,180
$152,913
Other operations and maintenance
$207,164
$202,552
$202,738
Depreciation and amortization
$172,471
$162,069
$158,415
Taxes other than income taxes
$43,742
$47,267
$46,539
Total operating expenses
$919,902
$962,624
$899,951
Operating income
$248,468
$278,972
$285,245
Interest income
$4,744
$5,052
$1,283
Allowance for equity funds used during construction
$15,397
$14,159
$8,320
Other expense, net
$(3,616)
$(8,699)
$(7,417)
Interest charges
 
 
 
Interest charges, net
$77,316
$76,009
$71,649
Allowance for borrowed funds used during construction
$(6,037)
$(4,706)
$(2,287)
Total interest charges
$71,279
$71,303
$69,362
Income before income taxes
$193,714
$218,181
$218,069
Federal and state income tax expense
$45,452
$55,924
$67,331
Net income
$148,262
$162,257
$150,738
The accompanying notes are an integral part of the Consolidated Financial Statements.consolidated financial statements.
F-13

TABLE OF CONTENTS

CLECO

POWER
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 
  

 

 

   

 

 

  

 

 

   

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Net income
$148,262
$162,257
$150,738
Other comprehensive income (loss), net of tax
 
 
 
Postretirement benefits gain (loss) (net of tax benefit of $3,408, tax expense of $968, and tax benefit of $296, respectively)
$(9,657)
$2,743
$(472)
Amortization of interest rate derivatives to earnings (net of tax expense of $90, $90, and $132, respectively)
$254
$254
$211
Total other comprehensive (loss) income, net of tax
$(9,403)
$2,997
$(261)
Comprehensive income, net of tax
$138,859
$165,254
$150,477
The accompanying notes are an integral part of the Consolidated Financial Statements.consolidated financial statements.
F-14

TABLE OF CONTENTS

CLECO

POWER
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 
  

 

 

   

 

 

 

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Assets
 
 
Utility plant and equipment
 
 
Property, plant, and equipment
$5,489,457
$5,015,004
Accumulated depreciation
$(1,905,031)
$(1,804,563)
Net property, plant, and equipment
$3,584,426
$3,210,441
Construction work in progress
$111,687
$351,828
Total utility plant and equipment, net
$3,696,113
$3,562,269
Current assets
 
 
Cash and cash equivalents
$55,489
$31,987
Restricted cash and cash equivalents
$11,100
$11,241
Customer accounts receivable (less allowance for doubtful accounts of $3,005 in 2019 and $814 in 2018)
$39,165
$50,043
Accounts receivable - affiliate
$14,481
$3,318
Other accounts receivable
$24,604
$24,523
Unbilled revenue
$33,207
$35,314
Fuel inventory, at average cost
$59,602
$82,836
Materials and supplies, at average cost
$91,941
$92,671
Energy risk management assets
$6,311
$23,355
Accumulated deferred fuel
$22,910
$20,112
Cash surrender value of company-owned life insurance policies
$17,574
$20,497
Prepayments
$4,786
$6,143
Regulatory assets
$10,973
$13,603
Other current assets
$655
$1,162
Total current assets
$392,798
$416,805
Equity investment in investee
$17,072
$18,172
Prepayments
$2,693
$2,251
Operating lease right of use assets
$28,633
Restricted cash and cash equivalents
$14,363
$18,649
Note receivable
$15,198
$15,829
Regulatory assets
$272,289
$261,569
Intangible asset
$517
$21,093
Other deferred charges
$36,854
$32,419
Total assets
$4,476,530
$4,349,056
The accompanying notes are an integral part of the Consolidated Financial Statements.consolidated financial statements.
F-15

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(Continued on next page)

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.

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Liabilities and member’s equity
 
 
Member’s equity
$1,713,392
$1,594,533
Long-term debt and finance leases, net
$1,327,372
$1,387,774
Total capitalization
$3,040,764
$2,982,307
Current liabilities
 
 
Long-term debt and finance leases due within one year
$61,587
$21,128
Accounts payable
$110,096
$146,314
Accounts payable - affiliate
$14,123
$7,843
Customer deposits
$58,289
$61,736
Provision for rate refund
$38,241
$35,842
Taxes payable, net
$38,888
$48,177
Interest accrued
$7,972
$8,252
Energy risk management liabilities
$586
$468
Regulatory liabilities - other
$6,675
$2,496
Other current liabilities
$22,802
$22,263
Total current liabilities
$359,259
$354,519
Commitments and contingencies (Note 15)
 
 
Long-term liabilities and deferred credits
 
 
Accumulated deferred federal and state income taxes, net
$657,834
$630,765
Postretirement benefit obligations
$206,270
$182,721
Regulatory liabilities - other
$2,496
Regulatory liabilities - deferred taxes, net
$146,948
$155,537
Restricted storm reserve
$12,285
$15,485
Asset retirement obligations
$7,325
$6,881
Operating lease liabilities
$25,658
Other deferred credits
$20,187
$18,345
Total long-term liabilities and deferred credits
$1,076,507
$1,012,230
Total liabilities and member’s equity
$4,476,530
$4,349,056
The accompanying notes are an integral part of the Consolidated Financial Statements.consolidated financial statements.
F-16

TABLE OF CONTENTS

CLECO

POWER
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 
  

 

 

   

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating activities
 
 
 
Net income
$148,262
$162,257
$150,738
Adjustment to reconcile net income to net cash provided by operating activities
 
 
 
Depreciation and amortization
$178,245
$168,248
$165,200
Provision for doubtful accounts
$2,348
$797
$2,677
Unearned compensation expense
$974
$1,873
$1,972
Allowance for equity funds used during construction
$(15,397)
$(14,159)
$(8,320)
Deferred income taxes
$21,799
$(11,545)
$(34,191)
Deferred fuel costs
$11,132
$(18,549)
$11,909
Cash surrender value of company-owned life insurance
$2,923
$(219)
$(260)
Changes in assets and liabilities
 
 
 
Accounts receivable
$(4,740)
$3,967
$(25,696)
Accounts receivable - affiliate
$728
$426
$1,865
Unbilled revenue
$2,107
$1,084
$(2,129)
Fuel inventory and materials and supplies
$21,121
$(2,981)
$(44,995)
Prepayments
$386
$107
$2,745
Accounts payable
$14,659
$22,419
$11,005
Accounts payable - affiliate
$5,912
$(4,700)
$1,349
Customer deposits
$5,888
$13,757
$12,381
Provision for merger commitments
$(1,848)
$(3,273)
$(12,971)
Postretirement benefit obligations
$(10,078)
$4,252
$4,849
Regulatory assets and liabilities, net
$(1,897)
$1,044
$10,544
Other deferred accounts
$(6,338)
$(5,421)
$(8,137)
Taxes accrued
$(20,881)
$16,566
$44,101
Interest accrued
$(280)
$1,169
$(59)
Other operating
$(2,541)
$2,569
$2,501
Net cash provided by operating activities
$352,484
$339,688
$287,078
Investing activities
 
 
 
Additions to property, plant, and equipment
$(313,962)
$(289,153)
$(235,252)
Allowance for equity funds used during construction
$15,397
$14,159
$8,320
Proceeds from sale of property, plant, and equipment
$739
$995
$4,078
Reimbursement for property loss
$141
$1,375
$187
Issuance of note receivable
$(16,800)
Return of equity investment in investee
$1,100
$500
Return of investment in company-owned life insurance
$3,761
Other investing
$574
$397
Net cash used in investing activities
$(292,250)
$(289,027)
$(222,167)
The accompanying notes are an integral part of the Consolidated Financial Statements.consolidated financial statements.
F-17

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(Continued on next page)

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 
  

 

 

   

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Financing activities
 
 
 
Draws on credit facility
$33,000
$106,000
Payments on credit facility
$(33,000)
$(106,000)
Issuances of long-term debt
$50,000
$125,000
Repayments of long-term debt
$(20,571)
$(19,193)
$(17,896)
Distributions to member
$(20,000)
$(121,400)
$(135,000)
Other financing
$(588)
$(1,148)
$(2,013)
Net cash used in financing activities
$(41,159)
$(91,741)
$(29,909)
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents
$19,075
$(41,080)
$35,002
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period
$61,877(1)
$102,957
$67,955
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period
$80,952(2)
$61,877(1)
$102,957
 
 
 
 
Supplementary cash flow information
 
 
 
Interest paid, net of amount capitalized
$67,391
$70,357
$65,984
Supplementary non-cash investing and financing activities
 
 
 
Accrued additions to property, plant, and equipment
$14,894
$55,718
$30,883
Non-cash additions to property, plant, and equipment
$52
$1,224
$3,015
Incurrence of finance lease obligation - barges
$
$16,800
$
(1)
Includes cash and cash equivalents of $31,987, current restricted cash and cash equivalents of $11,241, and non-current restricted cash and cash equivalents of $18,649.
(2)
Includes cash and cash equivalents of $55,489, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $14,363.
The accompanying notes are an integral part of the Consolidated Financial Statements.consolidated financial statements.
F-18

TABLE OF CONTENTS

CLECO

POWER
Consolidated Statements of Changes in Member’s 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.

(THOUSANDS)
MEMBER’S
EQUITY
AOCI
TOTAL
MEMBER’S
EQUITY
Balances, Dec. 31, 2016
$1,548,624
$(13,422)
$1,535,202
Distributions to member
$(135,000)
$(135,000)
Net income
$150,738
$150,738
Other comprehensive loss, net of tax
(261)
$(261)
Balances, Dec. 31, 2017
$1,564,362
$(13,683)
$1,550,679
Distributions to member
$(121,400)
$(121,400)
Net income
$162,257
$162,257
Other comprehensive income, net of tax
$2,997
$2,997
Reclassification of effect of tax rate change
$2,496
$(2,496)
Balances, Dec. 31, 2018
$1,607,715
$(13,182)
$1,594,533
Distributions to member
$(20,000)
$(20,000)
Net income
$148,262
$148,262
Other comprehensive loss, net of tax
$(9,403)
$(9,403)
Balances, Dec. 31, 2019
$1,735,977
$(22,585)
$1,713,392
The accompanying notes are an integral part of the Consolidated Financial Statements.

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-19

TABLE OF CONTENTSReport 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

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.

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.

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)

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.

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)

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.

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
Leases
Cleco and Cleco Power
Note 5
Revenue Recognition
Cleco and Cleco Power
Note 6
Regulatory Assets and Liabilities
Cleco and Cleco Power
Note 57
Jointly Owned Generation Units
Cleco and Cleco Power
Note 68
Fair Value Accounting
Cleco and Cleco Power
Note 79
Debt
Debt
Cleco and Cleco Power
Note 810
Common StockCleco and Cleco Power
Note 9
Pension Plan and Employee Benefits
Cleco and Cleco Power
Note 1011
Income Taxes
Cleco and Cleco Power
Note 1112
Disclosures about Segments
Cleco
Note 1213
Regulation and Rates
Cleco and Cleco Power
Note 1314
Variable Interest Entities
Cleco and Cleco Power
Note 14Operating LeasesCleco and Cleco Power
Note 15
Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees
Cleco and Cleco Power
Note 16
Affiliate Transactions
Cleco and Cleco Power
Note 17
Intangible Assets, Intangible Liabilities, and Goodwill
Cleco and Cleco Power
Note 18
Coughlin Transfer
Accumulated Other Comprehensive Loss
Cleco and Cleco Power
Note 19
Accumulated Other Comprehensive Loss
Miscellaneous Financial Information (Unaudited)
Cleco and Cleco Power
Note 20Miscellaneous Financial Information (Unaudited)Cleco and Cleco Power
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Notes to the Financial Statements

Note 1—1 — The Company

General

Cleco Holdings is a holding company composed of the following:

Cleco Power, a regulated electric utility subsidiary, which owns nine10 generating units with a total nameplate capacity of 3,3103,360 MW and serves approximately 288,000 customers in Louisiana through its retail business and supplies wholesale power in Louisiana and Mississippi. Cleco Power also owns a 50% interest in an entity that owns lignite reserves. Cleco Power owns all of the outstanding membership interests in Cleco Katrina/Rita, a special purpose entity that is consolidated with Cleco Power in its financial statements.

Midstream is a wholesale energyCleco Cajun, an unregulated electric utility subsidiary, regulated by FERC, which owns Evangeline. Prior to March 15, 2014, Evangeline ownedeight generating assets with a rated capacity of 3,555 MW and supplies wholesale power and capacity in Arkansas, Louisiana, and Texas. Cleco Cajun owns all of the outstanding membership interest in Cottonwood Energy. Upon the closing of the Cleco Cajun Transaction, Cottonwood Energy entered into the Cottonwood Sale Leaseback. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”

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 following:

Cleco Holdings, a holding company,
Support Group, a shared services subsidiary,
Diversified Lands, an investment subsidiary, and
Attala and Perryville, two subsidiaries that owned and operated transmission interconnection facilities prior to the assets being sold by Cleco on December 29, 2017.
Note 3—“Business Combinations.”

Note 2—2 — Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities

and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Principles of Consolidation

The accompanying consolidated financial statements of Cleco include the accounts of Cleco and its

majority-owned subsidiaries after elimination of intercompany accounts and transactions.

Cleco’s consolidated financial statements include the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, through December 31, 2019. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”
Goodwill

Goodwill

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 beis 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—“17 — “Intangible Assets, Intangible Liabilities, and Goodwill.”

Intangible Assets and Goodwill.”

Liabilities

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 andas well as a fair value adjustment for the valuation of the Cleco trade name. Intangible liabilities also include fair value adjustments for long-term wholesale power supply agreements and a fair value adjustment for the LTSA assumed for maintenance services related to the Cottonwood Plant. The intangible assets and liabilities are being amortized over their estimated useful lives in a manner that best reflects the economic benefitsimpact derived from such assets. assets and liabilities.

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Impairment will be

tested if there are events or circumstances that indicate that an impairment analysis should be performed. If such an event or circumstance occurs, intangible impairment testing will be performed prior to goodwill impairment testing. Impairment is

calculated as the excess of the asset’sasset and liabilities’ respective carrying amountamounts over itstheir respective fair value.values. For more information on intangible assets and liabilities, see Note 17—“17 — “Intangible Assets, Intangible AssetsLiabilities, 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

Regulation

Cleco Power is subject to regulation by FERC and the LPSC. Cleco PowerCajun is subject to regulation by FERC. Cleco complies with the accounting policies and practices prescribed by its regulatory commissions. Cleco Power’s retail rates are regulated by the LPSCLPSC. Cleco and its tariffsCleco Cajun’s rates for transmission services are regulated by FERC. Rates for wholesale power sales are based on market-based rates, pending FERC review of Cleco Power’sCleco’s generation market power analysis. Cleco Power capitalizes or defers certain costs for recovery from its customers and recognizes a liability for amounts expected to be returned to its customers based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered through the ratemaking process. Regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the ratemaking process. Pursuant to this

regulatory approval, Cleco has recorded regulatory assets and liabilities.

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

For more information regarding the regulatory assets and liabilities recorded by Cleco Power, see Note 4—“Regulatory6 — “Regulatory Assets and Liabilities.”

AROs

AROs

Cleco and Cleco Power recognizesrecognize an ARO when there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel to incur costs to remove an asset when the asset is retired. These guidelines also require an ARO which is conditional on a future event to be recorded even if the event has not yet occurred.

Cleco and Cleco Power recognizesrecognize 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, Cleco and Cleco Power capitalize 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

As part of the Resource Conservation and Recovery Act. The Subtitle D option will regulate CCRs in a manner similarCleco Cajun Transaction, Cleco recognized $15.3 million of AROs primarily related to industrial solid waste. The final rule does not require expensive synthetic liningthe retirement of existing impoundments.Cleco Cajun’s ash management areas. 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

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, 2016,2019, management’s analysis confirmed that no additional adjustments were needed to update Cleco or Cleco Power’s ARO balance.

For more information on Cleco Power’s current AROs, see Note 4—“Regulatory6 — “Regulatory Assets and Liabilities—Liabilities — AROs.”

Property, Plant, and Equipment

Property, plant, and equipment consists primarily of regulated utility generation and energy transmission and distribution assets. Regulated assets,Assets utilized primarily for retail and wholesale operations and electric transmission and distribution are stated at the cost of construction, which includes certain materials, labor, payroll taxes and benefits,
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administrative and general costs, and the estimated cost of funds used during construction. Jointly owned assets are reflected in property, plant, and equipment at Cleco Power’s and Cleco Cajun’s share of the cost to construct or purchase the respective assets. For information on jointly owned assets, see Note 5—“Jointly7 — “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 2016 Merger, theCleco’s 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.such date. 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. On August 1, 2019, Cleco and Cleco Power began amortizing the computer software related to the START project. The amounts of unamortized computer software costs on Cleco’s Consolidated Balance Sheets at

December 31, 2016,2019, and 20152018 were $10.0$168.6 million and $12.5$7.2 million, respectively. The amounts of unamortized computer software costs on Cleco Power’s Consolidated Balance Sheets at December 31, 2019, and 2018 were $166.2 million and $5.8 million, respectively. Amortization of capitalized computer software costs charged to expense in Cleco and Cleco Power’s Consolidated Statements of Income for the years ending December 31, 2016, 2015,2019, 2018, and 20142017 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 
  

 

 

   

 

 

   

 

 

 

Cleco
 
 
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Amortization
$4,917
$2,154
$2,367
Cleco Power
 
 
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Amortization
$4,321
$1,607
$1,887
Upon retirement or disposition, the cost of Cleco Power’sPower and Cleco Cajun’s depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. For Cleco’s other depreciable assets,subsidiaries, upon disposition or retirement of depreciable assets, the difference between the net book value of the property and any proceeds received for the property is recorded as a gain or loss on asset disposition on Cleco’s Consolidated Statements of Income. Any cost incurred to remove the asset is charged to expense. Annual
Cleco Cajun’s depreciation provisions expressed ason property, plant, and equipment is calculated primarily on a percentagecomposite basis over the useful lives 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%.

the assets. Depreciation on all other property, plant, and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The following table presents the useful lives of depreciable assets as follows:

for Cleco and Cleco Power:
CATEGORY (YEARS)
CLECO
CLECO POWER

CATEGORY

Utility Plants
YEARS

Utility Plants

Generation
6 – 95

Production

10 – 95

Distribution

15 – 50
15 – 50

Transmission

5 – 55
5 – 55

Other utility plant

2 – 45
5 – 45

Other property, plant, and equipment

5 – 45
5 – 45
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At December 31, 2016,2019, and 2015,2018, 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 
 

 

 

  

 

 

 

Cleco
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Utility plants
 
 
Generation
$2,812,843
$1,949,042
Distribution
1,153,086
1,081,650
Transmission
660,279
519,269
Other utility plant
350,683
174,010
Other property, plant, and equipment
5,364
4,506
Total property, plant, and equipment
4,982,255
3,728,477
Accumulated depreciation
(454,874)
(303,727)
Net property, plant, and equipment
$4,527,381
$3,424,750
Cleco Power
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Regulated utility plants
 
 
Generation
$2,633,590
$2,476,733
Distribution
1,593,104
1,523,885
Transmission
805,701
731,432
Other utility plant
457,062
282,954
Total property, plant, and equipment
5,489,457
5,015,004
Accumulated depreciation
(1,905,031)
(1,804,563)
Net property, plant, and equipment
$3,584,426
$3,210,441
On February 4, 2019, Cleco acquired $741.2 million of unregulated property, plant, and equipment as a result of the Cleco Cajun Transaction. These assets were recorded at fair market value at the date of the acquisition. For more information on the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”
During 2016,2019, Cleco Power’s regulated utility property, plant, and equipment increased primarily due to the Cenlain-service of the START project, St. Mary Clean Energy Center project, Terrebonne to Bayou Vista Transmission Expansion project, the

Layfield/MessickCoughlin Pipeline project, and general installation and 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 
 

 

 

  

 

 

 

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, 2019, and 2015,2018, Cleco Power had deferred $5.0$1.4 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 statedrecorded at the lower of cost or market value using the average cost method and are issued from stock using the average cost of existing stock. Materials and supplies are recorded when purchased and subsequently charged to expense or capitalized to property, plant, and equipment when installed.

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TABLE OF CONTENTS

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,
Reserves
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 distributionits power lines. To mitigate the exposure to potential financial loss for damage to lines, Cleco Power maintains an LPSC-approved funded storm reserve.

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 thewithin certain self-insured limits, to be covered by insurance, Cleco Power maintains reserves. At December 31, 2016,2019, and 2015,2018, the general liability and workers compensation

reserves together were $4.6$4.3 million and $5.5$4.8 million, respectively.

Additionally, Cleco maintains directors and officers insurance to protect managers from claims which may arise from their decisions and actions taken within the scope of their regular duties.

Cash Equivalents

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

Restricted Cash and Cash Equivalents

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

Cleco and Cleco Power’s restricted cash and cash equivalents consisted of:

Cleco

  
  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
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current
 
 
Cleco Katrina/Rita’s storm recovery bonds
$9,632
$9,505
Cleco Power’s charitable contributions
1,200
1,200
Cleco Power’s rate credit escrow
268
536
Total current
11,100
11,241
Non-current
 
 
Diversified Lands’ mitigation escrow
21
21
Cleco Cajun’s defense fund
719
Cleco Cajun’s margin deposits
100
Cleco Power’s future storm restoration costs
12,269
15,391
Cleco Power’s charitable contributions
2,094
2,753
Cleco Power’s rate credit escrow
505
Total non-current
15,203
18,670
Total restricted cash and cash equivalents
$26,303
$29,911
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 
 

 

 

  

 

 

 
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Cleco Power
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current
 
 
Cleco Katrina/Rita’s storm recovery bonds
$9,632
$9,505
Charitable contributions
1,200
1,200
Rate credit escrow
268
536
Total current
11,100
11,241
Non-current
 
 
Future storm restoration costs
12,269
15,391
Charitable contributions
2,094
2,753
Rate credit escrow
505
Total non-current
14,363
18,649
Total restricted cash and cash equivalents
$25,463
$29,890
Cleco Katrina/Rita has the right to bill and collect storm restoration costs from Cleco Power’s customers. As cash is collected, it is restricted for payment of administration fees, interest, and principal on storm recovery bonds. The change from December 31, 2015, to 2016 was due toDuring 2019, Cleco Katrina/Rita collecting $21.2collected $22.2 million net of administration fees partially offset by bond and interest payments. In March and September 2016, Cleco Katrina/Rita used $8.5remitted $20.6 million and $8.3 million, respectively, for scheduled storm recovery bond principal payments and $2.3$1.5 million and $2.1 million, respectively, for related interest payments.

Included

As part of the Cleco Cajun Transaction, Cleco acquired restricted cash of $0.7 million to be used by Cleco Cajun’s cooperative customers for defense funds in the Merger Commitments were $6.0 millionevent of charitable contributionspotential takeovers. There is no further obligation of Cleco with respect to be disbursed over five years and $136.0 million of rate credits to

eligible customers. On April 25, 2016, in accordance withsuch expenses, including 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 millionreplenishment of the charitable contributions and $121.5 million of the rate credits had been remitted from restricted cash.

fund.

Equity Investments

Cleco and Cleco Power account for investments in unconsolidated affiliated companies using the equity method of accounting. The amounts reported on Cleco and Cleco Power’s Consolidated Balance Sheets represent assets contributed by Cleco or Cleco Power, plus their share of the net income of the affiliate, less any distributions of earnings (dividends) received from the affiliate. The revenues and expenses (excluding income taxes) of these affiliates are netted and reported on one line item as equity income from investees on Cleco and Cleco Power’s Consolidated Statements of Income.

Cleco evaluates for impairments of equity method investments at each balance sheet date to determine if events and circumstances have occurred that indicate a possible other-than-temporary decline in the fair value of the investment and the possible inability to recover the carrying value through operations. Cleco uses estimates of the future cash flows from the investee and observable market transactions in order to calculate fair value and recoverability. An impairment is recognized when an other-than-temporary decline in market value occurs and recovery of the carrying value is not probable. There were no impairments recorded for 2016, 2015,2019, 2018, or 2014.2017. For more information on Cleco’s equity investments, see Note 13—“Variable14 — “Variable Interest Entities.”

Income Taxes

Cleco accounts for income taxes under the asset and liability method. Cleco provides for federal and state income taxes currently payable, as well as for those deferred due to timing differences between reporting income and expenses for financial statement purposes versus tax purposes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted income tax rates expected to be applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets and liabilities are

classified as non-current on Cleco and Cleco Power’s Consolidated Balance Sheets. Cleco’s income tax expense and related regulatory assets and liabilities could be affected by changes in its assumptions and estimates and by ultimate resolution of assumptions and estimates with taxing authorities. Cleco Group files a federal income tax return for all wholly owned subsidiaries. Cleco Power computes its federal and state income taxes as if it were a stand-alone taxpayer. The LPSC generally requires Cleco Power to flow the effects of state income taxes to customers immediately. The LPSC specifically requires that the state tax benefits associated with the deductions related to certain storm damages be normalized.customers. For more information on income taxes, see Note 10—“Income11 — “Income Taxes.”

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Investment Tax Credits

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

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.

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 Cleco Power’s retail customers currently are recovered from its customers through theCleco Power’s FAC. These costs are subject to audit and final determination by regulators. Excise taxes and pass-through fees collected on the sale of electricity are not recorded in utility revenue.

Unbilled Revenue

Cleco Power accrues estimated revenue monthly for energy used by customers but not yet billed. The monthly estimated unbilled revenue amounts are recorded as unbilled revenue and a receivable. During the third quarter of 2014, Cleco Power began usinguses 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’sCleco and Cleco Power’s Consolidated Statements of Income but are reflected at gross amounts on Cleco’sCleco and Cleco Power’s Consolidated Balance Sheets as a receivable until the tax is collected and as a payable until the liability is paid. Cleco currently does not have any excise taxes reflected on its income statement.

Franchise Fees

Cleco Power collects a consumer fee for one of its franchise agreements. This fee is not recorded on Cleco’sCleco and Cleco Power’s Consolidated Statements of Income as revenue and expense, but is reflected at gross amounts on Cleco’sCleco and Cleco Power’s Consolidated Balance Sheets as a receivable until it is collected and as a payable until the liability is paid.

AFUDC

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%10.71% on a pretax basis (7.39%(8.37% net of tax) for 2016, 11.46%2019, 9.58% on a pretax basis (7.09%(7.08% net of tax) for 2015,2018, and 10.46%11.07% on a pretax basis (6.47%(6.81% net of tax) for 2014.

2017.

Fair Value Measurements and Disclosures

Various accounting pronouncements require certain assets and liabilities to be measured at their fair values. Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one

time, generally the date of acquisition or debt issuance. Cleco and Cleco Power disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes. For more information about fair value levels, see Note 6—“Fair8 — “Fair Value Accounting.”

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Derivatives and Other 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. Activity

Cleco’s Energy Market Risk Management Policy authorizes hedging of commodity price risk with physical or financially settled derivative instruments. Some of these contracts may qualify for the use of variousnormal purchase, normal sale (NPNS) exception under derivative instruments, including exchange traded futuresaccounting guidance. Contracts that do not qualify for NPNS accounting treatment or are not elected for NPNS accounting treatment are marked-to-market and option contracts, forward purchase and sales contracts, and swap transactions to reduce exposure to fluctuations inrecorded on 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.

balance sheet at their fair value.

Cleco Power and Cleco Cajun are awarded and/or purchase FTRs in auctions facilitated by MISO. The majority of these FTRs are purchased in annual auctions during the second quarter, but additional FTRs may also enter into risk mitigating positionsbe purchased in monthly auctions. FTRs represent economic hedges of future congestion charges that wouldwill be incurred in serving customer load. FTRs are derivatives 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 bedesignated as hedging instruments for accounting purposes.
Cleco Power’s FTRs are marked-to-market with the resulting gainunrealized gains 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 belosses deferred as a component of deferred fuel assets or liabilities in accordance with regulatory policy. When these positions close, actualAt settlement, realized gains or losses would beare 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.Cajun’s 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 valuemarked-to-market with the resulting unrealized gains and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period basedlosses recorded on the most recent MISO FTR auction prices. Unrealizedincome statement as a component of purchased power expense. At settlement, realized gains or losses are also recorded on FTRs held by the income statement as a component of purchased power expense.

Cleco PowerCajun entered into other commodity derivative contracts during 2019. Management did not elect to apply hedge accounting to these contracts as allowed under applicable accounting standards. When these contracts are included in Accumulated deferredmarked-to-market, the resulting unrealized gain or loss is recorded on the income statement as a component of fuel on Cleco Power’s Consolidated Balance Sheets. Realizedexpense. At settlement, realized gains or losses are also recorded on settled FTRs are recorded in Fuel used for electric generation on Cleco Power’s Consolidated Statementsthe income statement as a component 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

fuel expense.

December 31, 2015. For more information on FTRs and other commodity derivatives, see Note 6—“Fair8 — “Fair Value Accounting—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 also enter into contracts to mitigate the volatility in interest rate risk. These contracts include, but are not limited to, interest rate swaps and treasury rate locks. For each reporting period presented, the years ended December 31, 2016, and 2015, ClecoRegistrants 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 participatesand Cleco Cajun participate in MISO’s Energy and Operating Reserve market where sales and purchases are netted hourly. If the hourly activity nets to sales, the result is reported in Electric operations on Cleco

and Cleco Power’s Consolidated Statements of Income. If the hourly activity nets to purchases, the result is reported in Power purchased for utility customersPurchased power on Cleco and Cleco Power’s Consolidated Statements of Income.

Leases
Cleco accounts for leases in accordance with accounting guidance effective January 1, 2019. For more information on this guidance, see — “Recent Authoritative Guidance.”
Cleco determines if a contract is a lease at its inception. If a contract is determined to be a lease, Cleco recognizes a ROU asset and lease liability at the commencement date based on the present value of lease payments over the lease term. The present value of the lease payments is determined by using the implicit interest rate if readily determinable. Cleco’s incremental borrowing rate for a term similar to the duration of the lease based on information available at the commencement date is used if the implicit interest rate is not readily determinable.
Cleco recognizes ROU assets and lease liabilities for leasing arrangements with terms greater than one year. Except for the marine transportation asset class, Cleco accounts for lease and non-lease components in a contract as a single lease component for all classes of underlying assets. Cleco’s marine transportation contracts, which include barges and towboats, contain non-lease components, such as maintenance and labor. Cleco allocates the consideration in these contracts between lease and non-lease components based on estimates of fair value from third parties that typically execute leases for this class of assets.
Expense for a lessee operating lease is recognized as a single lease cost on a straight-line basis over the lease term and reflected in the appropriate income statement line item based on the leased asset’s function. Income for
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a lessor operating lease is recognized as a single lease income item on a straight-line basis over the lease term and reflected in the appropriate income statement line item based on the lease asset’s function.
Recent Authoritative Guidance

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

In May 2014,February 2016, FASB amended the accounting guidance to account 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 ofleases. Effective 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.2019, Cleco intends to implementadopted the amended guidance using the modified retrospective approach.

Upon initial evaluation, key changes in the standardoptional transition method that management is assessing for potential areas of impact include accounting for contract modifications, contracts with pricing provisions that may require itallows an entity to recognize revenuea cumulative-effect adjustment to the opening balance of retained earnings 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 adoption, apply the new disclosure requirements beginning in the period of adoption, and continue to present comparative period information as required under previous guidance.

In addition, Cleco elected the transition practical expedient that permits an entity to not reassess prior conclusions about lease identification, lease classification, and initial issuance. The amended guidance could havedirect costs under the new standard, as well as the practical expedient that permits entities to not assess existing land easements under the new standard.
Adoption of this standard resulted in the recognition of ROU assets and lease liabilities for Cleco and Cleco Power’s operating leases of $16.1 million and $15.9 million, respectively. There was no impact to retained earnings as a materialresult of adopting this standard. Adoption of this standard did not materially impact on the Registrants’ results of operations financial condition, or cash flows of the Registrants.

liquidity, and their accounting for finance leases is substantially unchanged. For more information on Cleco’s lease obligations, see Note 4 — “Leases.”

In August 2014,June 2016, FASB amended the guidance for the presentationmeasurement of credit losses on receivables and disclosure of uncertainties about an entity’s ability to continue as a going concern.certain other assets. The amended guidance requires management to evaluate whether there is substantial doubt about its ability to continue asuse of 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 adoptioncurrent expected loss model, which may result in earlier recognition 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.credit losses. The adoption of this guidance is effective for fiscal years beginning after December 15, 2015,2019, 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,August 2018, FASB amended theissued 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

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 qualifiedallows for the equity methoddeferral of accounting ascertain implementation costs incurred in 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

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.cloud computing arrangement. The adoption of this guidance is effective for annual reporting periods beginning after December 15, 2019, including interim periods within those years. Early adoption is permitted. Management is evaluating the impact that the adoption ofdoes not expect this guidance willto have significant impact on the results of operations, financial condition, or cash flows of the Registrants.

Note 3—3 — Business Combinations

On April 13, 2016,February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in South Central Generating. This acquisition enabled Cleco to significantly increase the scale of its operations in Louisiana. As a result, Cleco Cajun owns:
a 176-MW natural-gas-fired generating station located in Sterlington, Louisiana,
a 220-MW natural-gas-fired facility and a 210-MW natural-gas-fired peaking facility, both located in Jarreau, Louisiana,
a 580-MW coal-fired generating facility, a 540-MW natural-gas-fired generating station, and 58% of a 588-MW coal-fired generating station all located in New Roads, Louisiana,
225 MW of a 300-MW natural-gas-fired peaking facility located in Jennings, Louisiana,
a 1,263-MW natural-gas-fired generating station located in Deweyville, Texas (the Cottonwood Plant),
wholesale contracts to provide electricity and capacity to nine Louisiana cooperatives, three municipalities across Arkansas, Louisiana, and Texas, and one investor-owned utility,
transmission assets, which consist of equipment and land required to connect the generation stations and the wholesale customers to the transmission grid, and
current assets consisting of cash, inventory, receivables and other miscellaneous assets.
Cleco Cajun, NRG Energy, and South Central Generating each made customary representations, warranties and covenants in the Cleco Cajun Transaction, which include customary indemnification provisions. Cleco Holdings completed its merger with Merger Sub whereby Merger Sub merged withhas agreed to guarantee the obligations of Cleco Cajun, subject to certain limitations. In addition, a lease agreement was executed and into Cleco Corporation, with Cleco Corporation survivingdelivered between Cottonwood Energy and a special-purpose entity that is a
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subsidiary of NRG Energy pursuant to which NRG Energy will lease back the Merger,Cottonwood Plant and Cleco Corporation converting towill operate it no later than May 2025. Upon closing, Cottonwood Energy became 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.

Cajun.

Regulatory Matters

On March 28, 2016,

In January 2019, the LPSC approved the Merger. The LPSC’s written order approving the Merger was issued on April 7, 2016.Cleco Cajun Transaction. Approval of the Mergertransaction was conditioned upon certain commitments, including $136.0holding Cleco Power ratepayers harmless for any adverse impacts, increased costs of debt or equity, and credit rating downgrades attributable to the Cleco Cajun Transaction; the repayment of $400.0 million of customer rate credits,Cleco Holdings’ debt by 2024; and a $7.0$4.0 million one-time contribution for economic development inannual reduction to Cleco Power’s service territoryretail customer rates. For more information about the debt and rate reduction commitments, see Note 9 — “Debt” and Note 6 — “Regulatory Assets and Liabilities,” respectively.
South Central Generating
In 2017, Louisiana Generating received insurance settlement proceeds for costs incurred to resolve a lawsuit which was brought by the EPA and the LDEQ against Louisiana Generating related to Big Cajun II, Unit 3. Entergy Gulf States, as co-owner of Big Cajun II, Unit 3, is expected to be administeredallocated a portion of the insurance settlement proceeds. Any amount allocated to Entergy Gulf States will be determined by the LED, $6.0 million of charitable contributionsongoing litigation and negotiations. South Central Generating estimated this amount to be disbursed over five years,$10.0 million. As part of the Cleco Cajun Transaction, Cleco Cajun assumed the $10.0 million contingent liability and $2.5NRG Energy indemnified Cleco for losses associated with this litigation matter. As a result, Cleco also recorded a $10.0 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 areindemnification asset, which was 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 duepurchase price allocation.
Prior to the Merger.Cleco Cajun Transaction, South Central Generating was involved in various litigation matters, including environmental and contract proceedings, before various courts regarding matters arising out of the ordinary course of business. Management is unable to estimate any potential losses that Cleco Cajun may ultimately be responsible for with respect to any one of these matters. As part of the Cleco Cajun Transaction, NRG Energy indemnified Cleco for losses, as of the closing date, associated with matters that existed as of the closing date, including pending litigation.
Accounting for the Cleco Cajun Transaction
As consideration for all of the outstanding membership interest in South Central Generating, Cleco paid cash of approximately $962.2 million, which represents the $1.0 billion acquisition price net of working capital and other adjustments of $37.8 million.
In connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings borrowed $300.0 million under a bridge loan agreement and $100.0 million under a term loan agreement. Both loan agreements are variable rate debt and have a three-year term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings to maintain (i) a debt to capital ratio (as defined in the applicable agreement) below 65% and (ii) a rating applicable to Cleco’s senior debt rating (as defined in the applicable agreement). On September 11, 2019, Cleco Holdings refinanced the remaining amounts due under the $300.0 million bridge loan agreement and a portion of the $100.0 million term loan agreement with the proceeds from the private placement of $300.0 million aggregate principal amount of senior notes. For more information, see Note 129“Regulation“Debt.” Also, in connection with the Cleco Cajun Transaction, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total capacity of $175.0 million. All other terms remained the same. Also in connection with the Cleco Cajun Transaction on February 4, 2019, Cleco Holdings made a $75.0 million draw on its credit facility, which was repaid on February 5, 2019.
The remaining cash required to finance the transaction consisted of an equity contribution from Cleco Group of $384.9 million and Rates.”

$102.3 million from cash on hand at Cleco Holdings.
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Accounting

Cleco Cajun accounted for the MergerCleco Cajun 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,a business combination, and accordingly, the Cleco consolidated assets acquired and liabilities assumed were recorded on April 13, 2016, at their estimated 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 
  

 

 

 

of the date of the acquisition. Cleco Power’smade certain measurement period adjustments at June 30, 2019. The following chart presents Cleco’s current purchase price allocation:

Purchase Price Allocation
(THOUSANDS)
AT FEB. 4, 2019
Current assets
Cash and cash equivalents
$146,494
Customer and other accounts receivable
49,809
Fuel inventory
22,060
Materials and supplies
25,659
Energy risk management assets
4,193
Other current assets
10,056
Non-current assets
Property, plant, and equipment, net
741,203
Prepayments
36,166
Restricted cash and cash equivalents
707
Intangible assets
98,900
Other deferred charges
133
Total assets acquired
1,135,380
Current liabilities
Accounts payable
38,478
Taxes payable
723
Energy risk management liabilities
241
Other current liabilities
14,570
Non-current liabilities
Accumulated deferred federal and state income taxes, net
7,165
Deferred lease revenue
58,300
Intangible liabilities
38,300
Asset retirement obligations
15,323
Operating lease liabilities
110
Total liabilities assumed
173,210
Total purchase price consideration
$962,170
The fair values of Cleco Cajun’s acquired assets and 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 andassumed liabilities were determined based on significant estimates and assumptions, including projected future cash flows and discount rates reflecting risk inherent in those future cash flows. There were also estimates made to be stated at fair value atdetermine the Merger date, considering that mostexpected useful lives of theseeach class of assets are subject to regulation by the LPSC and FERC. Under such regulation, rates charged to customers are

acquired.

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,acquisition, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the difference between the contract price and the market price of acquired long-term wholesale power supply agreements. These adjustments are classified

as IntangibleThe fair value of intangible assets on Cleco’s Consolidated Balance Sheet.of $98.9 million and intangible liabilities of $14.2 million was reflected in the purchase price allocation. The valuation of the power supply agreementsacquired intangible assets and liabilities was estimated usingby applying the income approach. The income approachmethod, which is based upon discounted projected future cash flows associated with the underlying contracts. The power supply agreement intangible assets for the power supply agreements will beand liabilities are being amortized to Electric operations on Cleco’s Consolidated Statement of Income over the remaining term of the applicable contract.agreements.

As part of the Cleco Cajun Transaction, Cleco assumed an LTSA for maintenance services related to the Cottonwood Plant. The fair value of the LTSA was estimated by applying the income method. An intangible liability of $24.1 million was reflected in the purchase price allocation and is being amortized using the straight-line method over the estimated remaining life of the LTSA of seven years. The amortization is included as a reduction to the LTSA prepayments on Cleco’s Consolidated Balance Sheet.
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On the date of the power supply agreementsacquisition, the fair value of the lease between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy was estimated by applying the income method. Deferred lease revenue of $58.3 million was reflected in the purchase price allocation and is being amortized over the term of the lease agreement. The amortization is included in ElectricOther operations revenue 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

Valuations 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 subjectperformed 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 estimateassess the fair value of certain assets acquired and liabilities assumed and were considered preliminary as a result of the short time period between the closing of the Mergeracquisition and the end of the secondfirst 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.2019. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the Merger,acquisition as more information isbecomes available. These final valuations and assessments have been completed by the end of 2019.

During the second quarter of 2019, certain modifications were made to the preliminary valuations as of February 4, 2019, due to the refinement of valuation models, assumptions, and inputs. The measurement period adjustments were based upon information obtained about 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 asat the acquisition date that, if known, would have affected the measurement of the dateamounts recognized at that date.
Measurement Period Adjustments
(THOUSANDS)
AT JUNE 30, 2019
Current assets
Customer and other accounts receivable
$1,408
Other current assets
$56
Non-current assets
Property, plant, and equipment, net
$13,297
Prepayments
$(56)
Intangible assets
$(3,600)
Other deferred charges
$1
Current liabilities
Accounts payable
$3,022
Energy risk management liabilities
$(1)
Other current liabilities
$327
Non-current liabilities
Accumulated deferred federal and state income taxes, net
$421
Deferred lease revenue
$(3,600)
Intangible liabilities
$6,400
Asset retirement obligations
$4,534
Operating lease liabilities
$3
The measurement period adjustments resulted in an increase in electric operations revenue of the Merger. Except$0.5 million, a decrease in other operations revenue of $0.1 million, and an increase in depreciation expense of $0.2 million recorded for the effectsthree months ended June 30, 2019.
During the fourth quarter of the positions related to the Merger reflected on income tax returns,2019, Cleco completed its evaluation and determination of the fair value of certain assets and liabilities acquired in the Cleco Cajun Transaction. No modifications were made to the valuation during the third or fourth quarters of 2019. Consequently, no measurement period adjustments were made.
Pro forma Impact of the Cleco Cajun Transaction
The following table includes the unaudited pro forma financial information reflecting the consolidated results of operations of Cleco as if the Cleco Cajun Transaction had taken place on January 1, 2018. The pro forma net income for the year ended December 31, 2019, was adjusted to exclude nonrecurring transaction-related expenses of $4.7 million. The pro forma net income for the year ended December 31, 2018, includes nonrecurring transaction-related expenses.
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The unaudited pro forma financial information presented in the following table is not necessarily indicative of the consolidated results of operations that would have been achieved had the transaction taken place on the dates indicated, or the future consolidated results of operations of the combined companies.
Unaudited Pro Forma Financial Information
 
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
Operating revenue, net
$1,660,362
$1,668,022
Net income
$154,898
$170,224
Note 4—Leases
Cleco maintains operating and finance leases in its ordinary course of business activities.
Effective January 1, 2019, Cleco adopted new guidance which requires organizations to recognize lease assets and lease liabilities on the balance sheet and disclose key information about leasing arrangements. A lease is deemed to exist when the right to control the use of identified property, plant, or equipment is conveyed through a contract for a certain period of time and consideration is paid. For more information on how leases are identified and on the new guidance, see Note 2 — “Summary of Significant Accounting Policies — Leases” and “— Recent Authoritative Guidance.”
Operating Leases
Cleco Power leases utility systems from two municipalities and one non-municipal public body. The first municipal lease had a term of 10 years and was set to expire on August 11, 2021. On July 9, 2019, this municipal lease was renewed for an additional term of 10 years and expires on August 11, 2031. The second municipal lease has a term of 10 years and expires on May 13, 2028. The non-municipal lease has a term of 27 years and expires on July 31, 2039. Each utility system lease contains fixed and variable components, as well as provisions for extensions.
Cleco Power has leases for 200 railcars for coal transportation. One lease for 115 railcars expires on March 31, 2021, and the other lease for 85 railcars expires on March 31, 2020. Cleco Cajun has a lease for 135 railcars for coal transportation, which commenced in February 2019 and was a short-term lease with an initial term of 12 months. On January 27, 2020, this lease was renewed and expires on March 31, 2021. This lease renews for additional one-month terms unless Cleco Cajun chooses to terminate. Cleco reassesses its need for the railcars upon the expiration of each term. Cleco pays a monthly rental fee per car. The railcar leases do not contain contingent rent payments.
Cleco Power has leases for three towboats in order to transport petroleum coke to Madison Unit 3. Each of the towboat leases has a term of 10 years and expires on March 31, 2028. Under these agreements, the rates are adjusted annually per the Producer Price Index. Each lease contains provisions for a five-year extension.
Cleco and Cleco Power’s remaining operating leases provide for office and operating facilities, office equipment, and tower rentals.
The following is a schedule by year of future minimum lease payments due under Cleco and Cleco Power’s long-term operating leases together with the present value of the net minimum lease payments as of December 31, 2016. While management believes2019:
(THOUSANDS)
CLECO POWER
CLECO
Years ending Dec. 31,
 
 
2020
$3,960
$3,994
2021
3,409
3,443
2022
3,256
3,287
2023
3,220
3,249
2024
3,216
3,235
Thereafter
18,618
18,618
Total minimum lease payments
35,679
35,826
Less: amount representing interest
7,086
7,069
Present value of net minimum operating lease payments
$28,593
$28,757
Current liabilities
$2,935
$2,978
Non-current liabilities
$25,658
$25,779
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The following table is a summary of expected operating lease payments for Cleco and Cleco Power at December 31, 2018:
(THOUSANDS)
CLECO
POWER
CLECO
HOLDINGS
TOTAL
Years ending Dec. 31,
 
 
 
2019
$4,030
$120
$4,150
2020
3,890
3,890
2021
2,789
2,789
2022
1,239
1,239
2023
1,214
1,214
Thereafter
7,235
7,235
Total operating lease payments
$20,397
$120
$20,517
Finance Lease
Prior to September 2017, Cleco Power had an agreement with Savage Services for barges in order to transport petroleum coke and limestone to Madison Unit 3 that met the positions reflectedaccounting definition of a finance lease. In September 2017, Cleco Power entered into a new agreement for use of the barges on a month-to-month basis that met the accounting definition of an operating lease. In April 2018, Cleco Power entered into an agreement with Savage Inland Marine for continued use of the 42 barges used to transport petroleum coke through March 2033. The agreement meets the accounting definition of a finance lease.
The barge lease rate contains both a fixed and variable component, of which the latter is adjusted every third anniversary of the agreement for estimated executory costs. If the barges are idle, the lessor is required to attempt to sublease the barges to third parties with the revenue reducing Cleco Power’s lease payment. This agreement contains a provision for early termination upon the occurrence of any one of four cancellation events.
For the years ended December 31, 2019, 2018, and 2017, Cleco Power paid $2.2 million, $2.0 million, and $2.5 million, respectively, in lease payments. For the years ended December 31, 2019, 2018, and 2017, Cleco Power received $1.7 million, $0.5 million, and $0.3 million, respectively, of revenue from subleases.
The following is an analysis of the leased property under the finance lease:
(THOUSANDS)
AT DEC. 31, 2019
AT DEC. 31, 2018
Barges
$16,800
$16,800
Accumulated amortization
(1,960)
(840)
Net finance lease
$14,840
$15,960
The following is a schedule by year of future minimum lease payments due under the finance lease together with the present value of the net minimum lease payments as of December 31, 2019:
(THOUSANDS)
 
Years ending Dec. 31,
 
2020
$2,203
2021
2,203
2022
2,203
2023
2,203
2024
2,203
Thereafter
17,675
Total minimum lease payments
28,690
Less: amount representing interest
12,829
Present value of net minimum finance lease payments
$15,861
Current liabilities
$617
Non-current liabilities
$15,244
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The following is a schedule by year of future minimum lease payments due under the finance lease together with the present value of the net minimum lease payments as of December 31, 2018:
(THOUSANDS)
Years ending Dec. 31,
 
2019
$2,611
2020
2,611
2021
2,611
2022
2,611
2023
2,611
Thereafter
23,655
Total minimum lease payments
36,710
Less: executory costs
5,817
Net minimum lease payments
30,893
Less: amount representing interest
14,475
Present value of net minimum lease payments
$16,418
Current liabilities
$557
Non-current liabilities
$15,861
Additional Lessee Disclosures
Cleco and Cleco Power’s total lease cost includes amounts on the income tax returnsstatement, as well as amounts capitalized as part of property, plant, or equipment or inventory. The following tables reflect total lease costs for Cleco and Cleco Power for the year ended December 31, 2019:
Cleco Power
(THOUSANDS)
FOR THE YEAR
ENDED DEC. 31,
2019
Finance lease cost
Amortization of ROU assets
$1,120
Interest on lease liabilities
1,646
Operating lease cost
4,303
Variable lease cost
515
Total lease cost
$7,584
Cleco
(THOUSANDS)
FOR THE YEAR
ENDED DEC. 31,
2019
Finance lease cost
Amortization of ROU assets
$1,120
Interest on lease liabilities
1,646
Operating lease cost
4,528
Variable lease cost
515
Total lease cost
$7,809
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The following tables present additional information related to Cleco and Cleco Power’s operating and finance leases as of and for the year ended December 31, 2019:
 
 
AT DEC. 31, 2019
(THOUSANDS)
BALANCE SHEET LINE ITEM
CLECO
POWER
CLECO
Supplemental balance sheet information
 
 
ROU assets
 
 
 
Operating
Operating lease right of use assets
$28,633
$28,791
Finance
Property, plant, and equipment
14,840
14,840
Total ROU assets
 
$43,473
$43,631
Current lease liabilities
 
 
Operating
Other current liabilities
$2,935
$2,978
Finance
Long-term debt and finance leases due within one year
617
617
Non-current lease liabilities
 
 
Operating
Operating lease liabilities
25,658
25,779
Finance
Long-term debt and finance leases, net
15,244
15,244
Total lease liabilities
$44,454
$44,618
Cleco Power
(THOUSANDS)
FOR THE YEAR
ENDED DEC. 31,
2019
Supplemental cash flow information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases
$4,203
Operating cash flows from finance leases
$1,646
Financing cash flows from finance leases
$557
ROU assets obtained in exchange for new lease liabilities
$15,749
Cleco
(THOUSANDS)
FOR THE YEAR
ENDED DEC. 31,
2019
Supplemental cash flow information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases
$4,452
Operating cash flows from finance leases
$1,646
Financing cash flows from finance leases
$557
ROU assets obtained in exchange for new lease liabilities
$15,881
 
AT DEC. 31, 2019
(THOUSANDS)
CLECO POWER
CLECO
Other supplemental information
 
 
Operating leases
 
 
Weighted-average remaining lease term
10.8 years
10.8 years
Weighted-average discount rate
4.31%
4.31%
Finance leases
 
 
Weighted-average remaining lease term
13.3 years
13.3 years
Weighted-average discount rate
10.18%
10.18%
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Lessor Agreements
Upon the closing of the Cleco Cajun Transaction, Cleco assumed two lessor contracts leasing land to farmers for a term of one year. Both of these lessor contracts are reasonable,classified as operating leases. For more information on the returns have notCleco Cajun Transaction, see Note 3 — “Business Combinations.”
Cottonwood Sale Leaseback Agreement
Upon closing the Cleco Cajun Transaction, the Cottonwood Sale Leaseback was executed. Under the terms of the lease, NRG Energy will operate the Cottonwood Plant, incur all costs, and receive all revenues from the operations of the plant. Cottonwood Energy will receive fixed lease payments of $40.0 million per year and variable lease payments for LTSA costs and property taxes paid by NRG Energy on behalf of Cleco. Cleco may terminate the lease contract under specific circumstances stated in the lease contract. The residual value under the Cottonwood Sale Leaseback is expected to be recovered through sales of power generation from the plant. The residual value of the Cottonwood Plant has been auditeddetermined using the plant’s estimated economic life.
Cleco Cajun is Cleco’s only entity with lessor arrangements. Cleco Cajun’s lease income under the Cottonwood Sale Leaseback for the year ended December 31, 2019, was as follows:
(THOUSANDS)
FOR THE YEAR
ENDED DEC. 31,
2019
Fixed payments
$36,667
Variable payments
20,415
Amortization of deferred lease liability(1)
8,438
Total lease income
$65,520
(1)
The deferred lease revenue resulting from the fair value of the lease between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy.
The remaining minimum lease payments to be received under the Cottonwood Sale Leaseback are as follows:
(THOUSANDS)
 
Years ending Dec. 31,
 
2020
$40,000
2021
40,000
2022
40,000
2023
40,000
2024
40,000
Thereafter
16,667
Total payments
$216,667
Depreciation expense associated with Cleco’s property under the Cottonwood Sale Leaseback for the year ended December 31, 2019, was $22.7 million. Cleco calculated depreciation on a straight-line basis over the useful life of the asset. Property associated with the Cottonwood Sale Leaseback was as follows:
(THOUSANDS)
AT DEC. 31, 2019
Property, plant, and equipment
$540,409
Accumulated depreciation
(22,741)
Net property, plant, and equipment
$517,668
Note 5 — Revenue Recognition
Revenue from Contracts with Customers
Retail Utility Revenue
Cleco’s retail revenue from contracts with customers is generated primarily from Cleco Power’s regulated revenue from residential, commercial, and industrial customers. Cleco Power recognizes retail revenue from these
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contracts as a series, and progress towards satisfaction of the performance obligation is measured using an output method based on kWh delivered. Accordingly, revenue from electricity sales is recognized as energy is delivered to the customer. Cleco Power bills retail customers, based on rates regulated by the applicable taxing authorities.

LPSC, on a monthly basis with payments generally due within 20 days of the invoice date.
Included in Cleco Power’s retail revenue is unbilled electric revenue, which represents the amount customers will be billed for services rendered from the last meter reading to the end of the respective accounting period. Cleco Power uses actual customer energy consumption data available from AMI to calculate unbilled revenue. Also included in Cleco Power’s retail revenue is electric customer credits, which primarily represents the accrued estimated refunds to Cleco Power’s retail customers for the tax related benefits of the TCJA.
Wholesale Revenue
Cleco’s wholesale revenue is generated primarily through the sale of energy and capacity to cooperatives, municipalities, and the MISO transmission provider. Cleco also enters into transactions through MISO for spot energy sales which are transacted in the Day-Ahead Energy and Operating Reserves Market and the Real-Time Energy and Operating Reserves Market. The electricity revenue performance obligations, representing both energy and capacity, are satisfied as a series of performance obligations, and progress towards satisfaction of the performance obligations are measured using an output method. The energy performance obligation measure of progress is based on kWh delivered. The capacity performance obligation measure of progress is based on time elapsed and is recognized each month as Cleco’s generating units stand ready to deliver electricity to the customer. Cleco recognizes wholesale revenue, inclusive of both performance obligations, under the invoice practical expedient for the amount Cleco has the right to invoice. Cleco, through Cleco Power and Cleco Cajun, charges its wholesale customers market based rates that are subject to FERC’s triennial market power analysis.
Transmission Revenue
Cleco Power and Cleco Cajun earn transmission revenues pursuant to MISO’s FERC filed tariff. The performance obligation of transmission service is satisfied as service is provided. Revenue is recognized upon delivery of the transmission service. For Cleco Power, revenue from the transmission of electricity is recorded based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of revenue requirements with rates effective June 1 of each year. For Cleco Cajun, revenue from the transmission of electricity is recorded based on a FERC-approved annual filing rate mechanism effective June 1 of each year. Cleco Cajun charges transmission rates based on its cost to provide transmission services.
Other Revenue
Other revenue from contracts with customers, which is not a significant source of Cleco’s revenue, includes Cleco Power’s Teche Unit 3 SSR revenue and miscellaneous fees. The performance obligation under these contracts is satisfied and revenue is recognized as control of the products is delivered or services are rendered.
Revenue Unrelated to Contracts with Customers
Cleco’s energy-related transactions with the following characteristics qualify as derivative contracts and are recorded pursuant to derivatives and hedging accounting guidance: a) their value is based on the notional amount or payment provisions of an underlying asset; b) they require no or a diminutive initial net investment; and c) their terms require or permit net settlement.
Cleco Cajun’s other revenue includes fixed lease payments and certain variable payments for costs paid by NRG Energy on behalf of Cleco. For more information on the Cottonwood lease agreement, see Note 4 — “Leases — Lessor AgreementsCottonwood Sale Leaseback Agreement.”
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Disaggregated Revenue
Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a new reportable segment. For more information on the transaction, see Note 4—3 — “Business Combinations.”
Operating revenue, net for the year ended December 31, 2019, and 2018, was as follows:
 
FOR THE YEAR ENDED DEC. 31, 2019
(THOUSANDS)
CLECO
POWER
CLECO
CAJUN
OTHER
ELIMINATIONS
TOTAL
Revenue from contracts with customers
 
 
 
 
 
Retail revenue
 
 
 
 
 
Residential(1)
$415,242
$
$
$
$415,242
Commercial(1)
289,197
289,197
Industrial(1)
149,711
149,711
Other retail(1)
15,046
15,046
Surcharge
22,132
22,132
Electric customer credits
(35,880)
(35,880)
Total retail revenue
855,448
855,448
Wholesale, net
226,978(1)
374,635(2)
(9,680)(3)
(1)
591,932
Transmission, net
50,874(4)
51,315(5)
(7,471)
94,718
Other
19,324(6)
2
19,326
Affiliate(7)
3,125
108
109,067
(112,300)
Total revenue from contracts with customers
1,155,749
426,058
99,389
(119,772)
1,561,424
Revenue unrelated to contracts with customers
 
 
 
 
 
Other
12,621(8)
65,560(9)
78,181
Total revenue unrelated to contracts with customers
12,621
65,560
78,181
Operating revenue, net
$1,168,370
$491,618
$99,389
$(119,772)
$1,639,605
(1)
Includes fuel recovery revenue.
(2)
Includes $0.8 million of electric customer credits.
(3)
Amortization of intangible assets related to Cleco Power’s wholesale power supply agreements.
(4)
Includes $2.6 million of electric customer credits.
(5)
Includes $0.7 million of electric customer credits.
(6)
Includes $16.1 million of other miscellaneous fee revenue and $3.2 million of Teche Unit 3 SSR revenue.
(7)
Includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.
(8)
Includes realized gains associated with FTRs of $12.4 million and LCFC revenue of $0.2 million.
(9)
Includes $57.1 million in lease revenue related to the Cottonwood Sale Leaseback and $8.4 million of deferred lease revenue amortization.
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FOR THE YEAR ENDED DEC. 31, 2018
(THOUSANDS)
CLECO
POWER
OTHER
ELIMINATIONS
TOTAL
Revenue from contracts with customers
 
 
 
 
Retail revenue
 
 
 
 
Residential(1)
$435,610
$
$
$435,610
Commercial(1)
288,791
288,791
Industrial(1)
167,001
167,001
Other retail(1)
15,582
15,582
Surcharge
23,138
23,138
Electric customer credits
(33,195)
(33,195
Total retail revenue
896,927
896,927
Wholesale, net(1)
219,598
(9,680)(2)
209,918
Transmission
54,531
54,531
Other(3)
27,800
2
27,802
Affiliate(4)
874
74,591
(75,465)
Total revenue from contracts with customers
1,199,730
64,913
(75,465)
1,189,178
Revenue unrelated to contracts with customers
 
 
 
 
Other(5)
41,866
41,866
Total revenue unrelated to contracts with customers
41,866
41,866
Operating revenue, net
$1,241,596
$64,913
$(75,465)
$1,231,044
(1)
Includes fuel recovery revenue.
(2)
Amortization of intangible assets related to wholesale power supply agreements.
(3)
Other revenue from contracts with customers includes $18.2 million of other miscellaneous fee revenue and $9.6 million of Teche Unit 3 SSR revenue.
(4)
Affiliate revenue from contracts with customers includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.
(5)
Includes realized gains associated with FTRs of $39.3 million and LCFC revenue of $2.6 million.
Cleco and Cleco Power have unsatisfied performance obligations with durations ranging between 1 and 15 years that primarily relate to stand-ready obligations as part of fixed capacity minimums. Cleco and Cleco Power have elected to not disclose the value of unsatisfied variable performance obligations as part of their application of the right to invoice practical expedient. At December 31, 2019, Cleco and Cleco Power had $30.8 million of unsatisfied performance obligations that will be recognized as revenue over the term of the contracts as the stand-ready obligation to provide energy is provided.
Note 6 — Regulatory Assets and Liabilities

Cleco Power capitalizes or defers certain costs for recovery from customers and recognizes a liability for amounts expected to be returned to customers based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered or refunded through the ratemaking process.

Under the current regulatory environment, Cleco Power believes these regulatory assets will be fully

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

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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  
 

 

 

  

 

 

  

Cleco Power
 
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
REMAINING
RECOVERY
PERIOD (YRS.)
Regulatory assets (liabilities)
 
 
 
Deferred taxes, net
(146,948)
(155,537)
*
Mining costs
1,274
Interest costs
3,958
4,208
*
AROs
3,668
3,099
*
Postretirement costs
151,543
140,245
*
Tree trimming costs
11,341
9,069
*
Training costs
6,241
6,396
40
Surcredits, net(1)
145
289
*
AMI deferred revenue requirement
3,136
3,681
6
Emergency declarations
1,349
2,980
*
Production operations and maintenance expenses
7,985
12,245
*
AFUDC equity gross-up(1)
72,766
71,952
*
Acadia Unit 1 acquisition costs
2,124
2,230
20
Financing costs
7,554
7,923
*
Coughlin transaction costs
906
938
29.5
Corporate franchise tax, net
(1,145)
1,416
*
Non-service cost of postretirement benefits
6,739
4,629
*
Energy efficiency
2,820
2,585
*
Accumulated deferred fuel
22,910
20,112
*
Other, net
(4,543)
(4,979)
*
Total regulatory assets, net
$152,549
$134,755
  
(1)Represents regulatory assets 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, 2016.2019, and 2018, respectively. All other assets are earning a return on investment.
*
For information related to the remaining recovery periods, refer to the following disclosures for each specific regulatory asset.

The following table summarizes Cleco’s net regulatory assets and liabilities:

Cleco

  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 
 

 

 

  

 

 

 

Cleco
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Total Cleco Power regulatory assets, net
$152,549
$134,755
2016 Merger adjustments(1)
 
 
Fair value of long-term debt
127,977
138,701
Postretirement costs
17,399
19,387
Financing costs
7,935
8,279
Debt issuance costs
5,665
6,252
Total Cleco regulatory assets, net
$311,525
$307,374
(1)
Cleco Holdings’ regulatory assets include acquisition accounting adjustments as a result of the 2016 Merger.

Income Taxes

The regulatory assetassets and liabilities recorded for deferred income taxes representsrepresent the effect of tax benefits or detriments that must be flowed through to customers as they are received or paid. The amounts deferred are attributable to differences between book and tax recovery periods. In 2017, the President signed the TCJA.
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Changes in the IRC, as amended, from the TCJA, had a material impact on the Registrants’ financial statements in 2017. Tax effects of changes in tax laws must be recognized in the period in which the law is enacted. Also, deferred tax assets and liabilities must be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. In 2017, Cleco and Cleco Power made an estimate for the remeasurement of ADIT based upon the new tax rate, which resulted in a provisional regulatory liability of $348.6 million. During the fourth quarter of 2018, Cleco Power recorded the final remeasurements, which resulted in an additional regulatory liability of $26.4 million for a total of $375.0 million at December 31, 2018. No additional regulatory liability was accrued at December 31, 2019. For more information on the status of the TCJA regulatory liability, see Note 13 — “Regulation and Rates — TCJA.”
Mining Costs

Cleco Power operates a generating unit jointly owned with SWEPCO that uses lignite as its primary fuel source.
Cleco Power, along with SWEPCO, maintains a lignite mining agreement with DHLC, the operator of the Dolet Hills Mine. As ordered by the LPSC, Cleco Power’s retail customers began receivingreceived fuel cost savings through the year 2011, while actual mining costs incurred above a certain percentage of the benchmark price were deferred. These deferred andcosts could be recovered from retail customers through the FAC only when the actual mining costs arewere 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 2009 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 previously authorized recovery of the legacy deferred fuel balance previously authorized.

balance. At June 30, 2019, Cleco Power had fully recovered the existing deferred mining costs, plus interest.

Interest Costs

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

assets.

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—“Summary2 — “Summary of Significant Accounting Policies—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 10eight years as of December 31, 2016,2019, for Cleco’s plan) when it exceeds certain thresholds. The amount and timing of the recovery will be based on the changing funded status of the pension plan in future periods. For more information on Cleco’s pension plan and adoption of these authoritative guidelines, see Note 9—“Pension10 — “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 amountand recover through its base rates tree trimming costs. The LPSC authorized a deferral up to $10.9 million. Of the remainingmillion, excluding debt carrying costs. Cleco Power is currently collecting deferred tree trimming 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 currentthrough its base rates through June 2020.and expects to be fully amortized by 2026.

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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 taxADIT liabilities at a rate

of return which was set by the LPSC. The settlement, through a true-up mechanism, allows the surcredits to be adjusted to reflect the actual tax deductions allowed by the IRS.

Cleco Power 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 bewere 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,period, through June 2018. Cleco Power is required to implement a surcredit when funds are withdrawn frombegan collecting 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 provisionbalance as part of the July 1, 2019, 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

rate adjustment.

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 theproject as a regulatory asset, including carrying charges, is capped by the LPSC at $20.0 million.asset. In June 2014, the LPSC approved Cleco Power’s FRP extension andrecovery of the AMI regulatory asset and project capital costs were included in rate base.over the average life of the AMI meters, or 11 years. In July 2014, Cleco Power isbegan recovering the AMI deferred revenue requirement over 11 years beginningrequirement.
Emergency Declarations
In August 2016, the LPSC issued emergency declaration executive orders following flooding events in south Louisiana which prohibited public utilities from disconnecting or charging late fees to customers for non-payment in affected parishes. In January 2017, the LPSC issued an order that terminated the executive orders effective March 1, 2017, and allowed public utilities to formally petition the LPSC to recover lost revenues as a result of the executive orders. In July 2014.

2017, Cleco Power began recovering lost revenues associated with the flooding events and expects the regulatory assets to be fully amortized by June 2021.

Production Operations and Maintenance Expenses

In September 2009, the LPSC authorized

Annually, Cleco Power is allowed to defer, as a regulatory asset, production operations and maintenance expenses, net of fuel and payroll, above the retail jurisdictional portion of $25.6$45.0 million, adjusted annually for a growth factor (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

extension, theThe LPSC allowedallows Cleco Power to recover the amount deferred in any calendar year over the following three yearthree-year regulatory period, beginning on July 1, when the annual rates are set. Cleco Power had no deferral in 2019. In December 2013, 2014, 2015, and 2016,2018, Cleco Power deferred $8.5$8.0 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.
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Financing Costs

In 2011, Cleco Power entered into and settled two treasury rate locks. Of the $26.8 million in settlements, $7.4 million was deferred as a regulatory asset relating to ineffectiveness of the hedge relationships. Also in 2011, Cleco Power entered into a forward starting swap contract. These derivatives were entered into in order to mitigate the interest rate exposure on coupon payments related to forecasted debt issuances. In May 2013, the forward starting interest rate swap was settled at a loss of $3.3 million. Cleco Power deferred $2.9 million of the losses as a regulatory asset, which is being amortized over the terms of the related debt issuances.

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 transaction costs related to the transfer of Coughlin transfer transaction costs.from Evangeline to Cleco Power. The Coughlin transaction costs are being recovered over a 35-year period beginning July 2014.

Corporate Franchise Tax,

Net

As part of the FRP extension approved by the LPSC in June 2014, Cleco Power was authorized to recover through a rider the retail portion of state corporate franchise taxes paid. 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

Non-service Cost of Postretirement Benefits
On January 1, 2018, FASB’s amended guidance related to defined benefit pension and other postretirement plans became effective. The amendment allows only the FRP period Julyservice cost component of net benefit cost to be eligible for capitalization within property, plant, and equipment. Beginning January 1, 2013 through June 30, 2014,2018, Cleco Power’s non-service cost previously eligible for capitalization into property, plant, and equipment are being deferred to a regulatory asset and will be amortized over the estimated lives of the respective assets.
Energy Efficiency
In December 2018, Cleco Power was authorized byfiled a letter of intent with the LPSC to recover the estimatedunder recovery of the accumulated decrease in revenues, also known as the LCFC, associated with the energy efficiency program for years 2014 through 2018 to be recovered over a four-year period. Cleco Power began collecting the accumulated LCFC revenues in Cleco Power’s energy efficiency rates effective March 1, 2019. On October 21, 2019, Cleco Power received notice of approval from the LPSC allowing recovery of the accumulated LCFC revenues.
Other Regulatory Assets (Liabilities), Net
At December 31, 2019, Other, net consisted of a $4.7 million regulatory liability for over collections related to the St. Mary Clean Energy project and a $0.8 million regulatory liability for an LPSC Cleco Cajun Transaction commitment. These regulatory liabilities were offset by a $1.0 million regulatory asset for the Coughlin Pipeline revenue requirement.
On July 1, 2018, Cleco Power began collecting the revenue requirement of $58.3 million related to Acadia Unit 1. the St. Mary Clean Energy Center project based on an expected commercial operation date in the third quarter of 2018. The project was commercially operational in August 2019. Cleco Power recorded a regulatory liability for the over collections due to the delay of the commercial operations. On July 1, 2019, Cleco Power’s rates were adjusted by the amount of the over-collection and Cleco Power began amortizing the regulatory asset over 12 months.
In January 2019, the LPSC approved the Cleco Cajun Transaction. Approval of the Cleco Cajun Transaction was conditioned upon certain commitments, including a $4.0 million annual reduction to Cleco Power’s retail customer rates. For the period from February 4, 2019, to June 30, 2019, Cleco Power recorded a regulatory liability for the annual reduction until the July 1, 2019 FRP rate adjustment reflected the annual savings. Also on July 1, 2019, Cleco Power began amortizing the regulatory liability over 12 months.
In June 2014,2017, the LPSC approved the establishment of a regulatory asset upon the completion of the Coughlin Pipeline project for the revenue requirement associated with the project until Cleco Power determined that it had under-recovered $0.8 millionseeks recovery in revenue from customers basedthe new FRP, which is anticipated to be effective July 1, 2020. The project was placed in service on the actual revenue requirement for Acadia Unit 1. TheSeptember 6, 2019. Cleco Power anticipates collecting this 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 request2020, subject 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 LPSCregulatory approval also allowed Cleco Power to record a regulatory asset of $7.1 million representing the unrecovered revenue requirements

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.new FRP.

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PPA True-up

In preparing the FRP monitoring report for the year ended June 30, 2014,

Accumulated Deferred Fuel
Cleco Power determined it had recovered $0.6 million aboveis allowed to recover 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. The difference between fuel and purchased power revenues collected from retail and wholesale customers and the current fuel and purchased power costs is generally recorded as Accumulated deferred fuel on Cleco Power’s Consolidated Balance Sheet. For 2016,2019, approximately 75%76% 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’ 2016 Merger Adjustments

As a result of the 2016 Merger, Cleco implemented acquisition accounting, which eliminated AOCI at the Cleco consolidated level on the date of the 2016 Merger. Cleco will continue to recover expenses related to certain postretirement costs; therefore, Cleco recognized a regulatory asset based on its determination that these costs can continue to be collected from customers. These costs will be amortized to Other operations expense over the average remaining service period of participating employees. Cleco will also continue to recover financing costs associated with the settlement of two treasury rate locks and a forward starting swap contract that were previously recognized in AOCI. Additionally, as a result of the 2016 Merger, a regulatory asset was recorded for debt issuance costs that were eliminated at Cleco and a regulatory asset was recorded for the difference between the carrying value and the fair value of long-term debt. These regulatory assets will beare being amortized over the terms of the related debt issuances. In November and December 2016, Cleco Powerissuances, unless the debt is 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 theprior to maturity, at which time any unamortized related unamortized debt issuance cost of $19.8 million on Cleco’s Consolidated Balance Sheets wereregulatory asset will be derecognized. The offset was to the respective regulatory assets.

Note 5—7 — Jointly Owned Generation Units

Cleco Power operatesand Cleco Cajun operate electric generation units that are jointly owned with other utilities. The joint-owners are responsible for their own share of the capital and the operating and maintenance costs of the respective units. Cleco Power’sPower and Cleco Cajun are responsible for their own share of the direct expenses of thetheir respective jointly owned generation unitsunits. Cleco Power’s share of expenses is included in the operating expenses on Cleco and Cleco Power’s Consolidated Statements of Income. Cleco Cajun’s share of expenses is included in the consolidated statementsoperating expenses on Cleco’s Consolidated Statement of income.

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.”

At December 31, 2016,2019, 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
 
 
 
 
 
 
AT DEC. 31, 2019
(THOUSANDS, EXCEPT PERCENTAGES AND MW)
RODEMACHER
UNIT 2
DOLET
HILLS
BAYOU
COVE
BIG
CAJUN II
- UNIT 3
TOTAL
Utility plant in service
$72,840
$179,909
$42,438
$33,291
$328,478
Accumulated depreciation
$7,690
$22,159
$2,090
$2,163
$34,102
Construction work in progress
$539
$5,435
$
$329
$6,303
Ownership interest percentage
30%
50%
75%
58%
 
Capacity (MW)
523(1)
650(1)
300(2)
588(2)
 
Ownership interest (MW)
157
325
225
341
 
(1)
Nameplate capacity (MW)
(2)
Rated capacity (MW)

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  
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Cleco Power
 
 
 
 
AT DEC. 31, 2019
(THOUSANDS, EXCEPT PERCENTAGES AND MW)
RODEMACHER
UNIT 2
DOLET
HILLS
TOTAL
Utility plant in service
$147,020
$397,406
$544,426
Accumulated depreciation
$81,870
$239,655
$321,525
Construction work in progress
$539
$5,435
$5,974
Ownership interest percentage
30%
50%
 
Nameplate capacity (MW)
523
650
 
Ownership interest (MW)
157
325
 
Note 6—8 — Fair Value Accounting

The amounts reflected in Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2016,2019, and December 31, 2015,2018, for cash equivalents, restricted cash equivalents, accounts receivable, other accounts receivable, short-term debt, and accounts payable approximate fair value because of their short-term nature.

Cleco applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including business combinations as well as impairment related to goodwill and other long-lived assets.

The following tables summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments not measured at fair value inon Cleco and Cleco Power’s Consolidated Balance Sheets:

Cleco
 
 
 
 
 
AT DEC. 31,
 
2019
2018
(THOUSANDS)
CARRYING
VALUE*
FAIR VALUE
CARRYING
VALUE*
FAIR VALUE
Long-term debt
$3,188,664
$3,371,915
$2,889,631
$2,859,924

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$13.7 million in 2016at December 31, 2019, and $9.9 $10.3��million in 2015.at December 31, 2018.

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 

Cleco Power
 
 
 
 
 
AT DEC. 31,
 
2019
2018
(THOUSANDS)
CARRYING
VALUE*
FAIR VALUE
CARRYING
VALUE*
FAIR VALUE
Long-term debt
$1,380,688
$1,601,865
$1,400,930
$1,517,152
*
The carrying value of long-term debt does not include deferred issuance costs of $9.4$7.4 million in 2016at December 31, 2019, and $9.6$8.3 million in 2015.at December 31, 2018.

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

Fair Value Measurements and Disclosures

Cleco classifies assets and liabilities that are either measured or disclosed at their fair value according to three different levels depending on the inputs used in determining fair value.

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The following tables disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured or disclosed on a recurring basis:

Cleco
 
 
 
 
 
 
 
 
 
FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)
AT DEC. 31,
2019
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
AT DEC. 31,
2018
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
Asset Description
 
 
 
 
 
 
 
 
Institutional money market funds
$129,643
$—
$129,643
$
$133,722
$—
$133,722
$
FTRs
6,822
6,822
23,355
23,355
Other commodity derivatives
201
201
Total assets
$136,666
$—
$129,844
$6,822
$157,077
$—
$133,722
$23,355
Liability Description
 
 
 
 
 
 
 
 
FTRs
$1,044
$—
$
$1,044
$468
$—
$
$468
Other commodity derivatives
5,373
5,373
$—
$
$
Total liabilities
$6,417
$—
$5,373
$1,044
$468
$—
$
$468
Cleco Power
 
 
 
 
 
 
 
 
 
FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)
AT DEC. 31,
2019
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
AT DEC. 31,
2018
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
Asset Description
 
 
 
 
 
 
 
 
Institutional money market funds
$74,903
$—
$74,903
$
$55,900
$—
$55,900
$
FTRs
6,311
6,311
23,355
23,355
Total assets
$81,214
$—
$74,903
$6,311
$79,255
$—
$55,900
$23,355
Liability Description
 
 
 
 
 
 
 
 
FTRs
$586
$—
$
$586
$468
$—
$
$468
Total liabilities
$586
$—
$
$586
$468
$—
$
$468

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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

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:

hierarchy for 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 
 

 

 

  

 

 

  

 

 

 

and Cleco Power:
Cleco
 
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
Beginning balance
$22,887
$7,044
Unrealized (losses) gains*
(1,659)
11,865
Purchases
27,881
28,185
Settlements
(43,331)
(24,207)
Ending balance
$5,778
$22,887
*
Cleco Power’s unrealized (losses) gains are reported through Accumulated deferred fuel on Cleco’s Consolidated Balance Sheet. Cleco Cajun’s unrealized (losses) gains are reported through Purchased power on Cleco’s Consolidated Income Statement.
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TABLE OF CONTENTS

Cleco Power
 
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
Beginning balance
$22,887
$7,044
Unrealized (losses) gains*
(945)
11,865
Purchases
21,609
28,185
Settlements
(37,826)
(24,207)
Ending balance
$5,725
$22,887
*
Unrealized gains (losses) are reported through Accumulated deferred fuel on Cleco 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 quantifiestables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for Cleco and Cleco Power as of December 31, 2016:

2019:
Cleco
 
 
 
 
 
 
 
FAIR VALUE
VALUATION
TECHNIQUE
SIGNIFICANT
UNOBSERVABLE
INPUTS
FORWARD PRICE
RANGE
(THOUSANDS, EXCEPT DOLLAR PER MWh)
Assets
Liabilities
 
 
Low
High
FTRs at December 31, 2019
$6,822
$1,044
RTO auction
pricing
FTR price -
per MWh
$(2.57)
$2.86
FTRs at December 31, 2018
$23,355
$468
RTO auction
pricing
FTR price -
per MWh
$(4.40)
$15.10
Cleco Power
 
 
 
 
 
 
 
FAIR VALUE
VALUATION
TECHNIQUE
SIGNIFICANT
UNOBSERVABLE
INPUTS
FORWARD PRICE
RANGE
(THOUSANDS, EXCEPT DOLLAR PER MWh)
Assets
Liabilities
 
 
Low
High
FTRs at December 31, 2019
$6,311
$586
RTO auction
pricing
FTR price -
per MWh
$(2.04)
$2.86
FTRs at December 31, 2018
$23,355
$468
RTO auction
pricing
FTR price -
per MWh
$(4.40)
$15.10

Cleco

   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 numbervolume 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 pricemarkets. Institutional money market funds assets are discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return. 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.not observable. Cleco has consistently applied the Level 2 and Level 3 fair value techniques from fiscal period to fiscal period. Significant increases or decreases in any of those inputs in isolation would result in a significantly different fair value measurement.

The assets and liabilities reported at fair value are grouped into classes based on the underlying nature and risks associated with the individual asset or liability.

At December 31, 2016,2019, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents and restricted cash equivalents. The institutional money market funds were reported on Cleco’s Consolidated Balance Sheets in cash and cash equivalents, current restricted cash and cash equivalents, and non-current restricted cash and cash equivalents of $20.0$103.4 million, $23.1$11.1 million, and $23.3$15.1 million, respectively, at December 31, 2016,2019, and $64.2$103.8 million, $9.3$11.2 million, and $16.1$18.7 million, respectively, at December 31, 2015.2018. At Cleco Power, the institutional money market funds were reported on Cleco Power’s Consolidated Balance Sheets in cash and cash equivalents, current restricted cash and cash equivalents, and non-current restricted cash and cash equivalents of $18.7$49.5 million, $23.1$11.1 million, and $23.3$14.3 million, respectively, at December 31, 2016,2019, and $62.0$26.1 million, $9.3$11.2 million, and $16.1$18.6 million, respectively, at December 31, 2015.2018. If the money market funds failed to perform under the terms of the

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investments, Cleco and Cleco Power would be exposed to a loss of the invested amounts. Collateral on these types of investments is not required by either Cleco or Cleco Power. The Level 2 institutional money market funds asset consists of a single class. In order to capture interest income and minimize risk, cash is invested in money market funds that invest primarily in short-term securities issued by the U. S. Treasury to maintain liquidity and achieve the goal of a net asset value of a dollar. The risks associated with this class are counterparty risk of the fund manager and risk of price volatility associated with the underlying securities of the fund.

Other commodity derivatives include fixed price physical forwards and swap transactions. These contracts contain counterparty credit risk because they are transacted directly with a counterparty and are not cleared on an exchange. These other commodity derivatives are recorded at fair value and categorized as Level 2 because pricing is indexed to other contracts.
Cleco Power’sPower and Cleco Cajun’s FTRs were priced using MISO’s monthly auction prices. Forward seasonal periods are not included in every monthly auction; therefore, the average of the most recent seasonal auction prices is used for monthly valuation. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from MISO auctions, which occur monthly in the Multi-Period Monthly Auction.

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, 2016,2019, and 2015,2018, Cleco did not experience any transfers between levels within the fair value hierarchy.

Commodity Contracts

The following table presentstables present the fair values of derivative instruments and their respective line items as recorded on Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2016,2019, 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 
  

 

 

  

 

 

 
2018:
Cleco
 
 
 
 
 
DERIVATIVES NOT DESIGNATED
AS HEDGING INSTRUMENTS
(THOUSANDS)
BALANCE SHEET LINE ITEM
AT DEC. 31,
2019
AT DEC. 31,
2018
Commodity related contracts
 
 
FTRs
 
 
 
Current
Energy risk management assets
$6,822
$23,355
Current
Energy risk management liabilities
1,044
468
Other commodity derivatives
 
 
Current
Energy risk management assets
201
Current
Energy risk management liabilities
3,069
Non-current
Other deferred credits
2,304
Commodity-related contracts, net
$606
$22,887
Cleco Power
 
 
 
 
 
DERIVATIVES NOT DESIGNATED
AS HEDGING INSTRUMENTS
(THOUSANDS)
BALANCE SHEET LINE ITEM
AT DEC. 31,
2019
AT DEC. 31,
2018
Commodity related contracts
 
 
FTRs
 
 
 
Current
Energy risk management assets
$6,311
$23,355
Current
Energy risk management liabilities
586
468
Commodity-related contracts, net
$5,725
$22,887
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TABLE OF CONTENTS

The following table presentstables present the effect of derivatives not designated as hedging instruments on Cleco and Cleco Power’s Consolidated Statements of Income for the years December 31, 2016, 2015,2019, 2018, 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 
    

 

 

   

 

 

  

 

 

  

 

 

 

2017:
Cleco
 
 
 
 
 
 
AMOUNT OF GAIN/(LOSS)
RECOGNIZED IN INCOME ON
DERIVATIVES FOR THE YEAR
ENDED DEC. 31,
(THOUSANDS)
DERIVATIVES LINE ITEM
2019
2018
2017
Commodity contracts
 
 
 
FTRs(1)
Electric operations
$13,043
$39,659
$23,826
FTRs(1)
Purchased power
(15,685)
(4,566)
(5,509
Other commodity derivatives
Fuel used for electric generation
(5,172)
Total
$(7,814)
$35,093
$18,317
(1)
For the 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, 2015,2019, 2018, and 2014,2017, unrealized lossesgains (losses) associated with FTRs for Cleco Power of $1.5$(1.7) million, $11.9 million and $2.7$(1.4) 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 
    

 

 

  

 

 

  

 

 

 

Cleco Power
 
 
 
 
 
 
AMOUNT OF GAIN/(LOSS)
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
DERIVATIVES LINE ITEM
2019
2018
2017
Commodity contracts
 
 
 
 
FTRs(1)
Electric operations
$13,047
$39,659
$23,826
FTRs(1)
Purchased power
(6,066)
(4,566)
(5,509)
Total
$6,981
$35,093
$18,317
(1)
For the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, unrealized gains (losses) associated with FTRs of $2.1$(0.9) million, $(1.5)$11.9 million, and $(2.7)$(1.4) 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, 2016,2019, and 20152018 was 9.09.2 million MWh and 8.48.7 million MWh, respectively.

The total volume of FTRs that Cleco had outstanding at December 31, 2019, and 2018 was 14.6 million MWh and 8.7 million MWh, respectively. At December 31, 2019, Cleco had 58.5 million MMBtus outstanding in other commodity derivatives.

Note 7—9 — Debt

Cleco Power’s total indebtedness as of December 31, 2016,2019, and 20152018 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 Power
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Bonds
 
 
Senior notes, 2.94%, due 2022
$25,000
$25,000
Senior notes, 3.08%, due 2023
100,000
100,000
Senior notes, 3.17%, due 2024
50,000
50,000
Senior notes, 3.68%, due 2025
75,000
75,000
Senior notes, 3.47%, due 2026
130,000
130,000
Senior notes, 4.33%, due 2027
50,000
50,000
Senior notes, 3.57%, due 2028
200,000
200,000
Senior notes, 6.50%, due 2035
295,000
295,000
Senior notes, 6.00%, due 2040
250,000
250,000
Senior notes, 5.12%, due 2041
100,000
100,000
Series A GO Zone bonds, 2.00%, due 2038, mandatory tender in 2020
50,000
50,000
Series B GO Zone bonds, 4.25%, due 2038
50,000
50,000
Cleco Katrina/Rita’s storm recovery bonds, 5.61%, due 2023
11,055
31,625
Total bonds
1,386,055
1,406,625
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Cleco Power
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Finance leases
 
 
Barge lease obligations
15,861
16,418
Gross amount of long-term debt and finance leases
1,401,916
1,423,043
Less: long-term debt due within one year
60,970
20,571
Less: finance leases classified as long-term debt due within one year
617
557
Unamortized debt discount
(5,368)
(5,695)
Unamortized debt issuance costs
(7,589)
(8,446)
Total long-term debt and finance leases, net
$1,327,372
$1,387,774
Cleco’s total indebtedness as of December 31, 2016,2019, and 20152018 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 
 

 

 

  

 

 

 

Cleco
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Total Cleco Power long term debt and finance leases, net
$1,327,372
$1,387,774
Cleco Holdings’ long-term debt, net
 
 
Senior notes, 3.250%, due 2023
165,000
165,000
Senior notes, 3.743%, due 2026
535,000
535,000
Senior notes, 3.375%, due 2029
300,000
Senior notes, 4.973%, due 2046
350,000
350,000
Bank term loan, variable rate, due 2021
300,000
300,000
Bank term loan, variable rate, due 2021
30,000
Long-term debt due within one year
(64,398)
Unamortized debt issuance costs(1)
(6,271)
(1,989)
Fair value adjustment
127,976
138,700
Total Cleco long-term debt and finance leases, net
$3,064,679
$2,874,485
(1)
For December 31, 2019, and 2018, this amount includes unamortized debt issuance costs for Cleco Holdings of $11.9 million and $8.2 million, respectively, partially offset by deferred debt issuance costs eliminated as a result of the 2016 Merger of $5.6 million and $6.3 million, respectively. For more information, see Note 6 — “Regulatory Assets and Liabilities — Cleco Holdings’ 2016 Merger Adjustments.”
The principal amounts payable under long-term debt agreements for each year through 20212024 and thereafter are as follows:
(THOUSANDS)
CLECO
CLECO POWER
For the year ending Dec. 31
 
 
2020(1)
$11,055
$11,055
2021
$330,000
$
2022
$25,000
$25,000
2023
$265,000
$100,000
2024
$50,000
$50,000
Thereafter
$2,385,000
$1,200,000
(1)
Does not include Series A GO Zone bonds that have a maturity date of December 2038 but a mandatory tender in May 2020.
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TABLE OF CONTENTS

(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

The principal amounts payable in 2017 for a capitalunder the finance lease agreement for barges. For more information about the barge lease, see Note 15—“Litigation, Other Commitmentseach year through 2024 and Contingencies, and Disclosures about Guarantees—Other Commitments—Fuel Transportation Agreement.”

thereafter are as follows:
(THOUSANDS)
CLECO
CLECO POWER
For the year ending Dec. 31
 
 
2020
$617
$617
2021
$682
$682
2022
$755
$755
2023
$836
$836
2024
$925
$925
Thereafter
$12,046
$12,046

Cleco Power Debt

Cleco Power had no short-term debt outstanding at December 31, 2016,2019, and 2015.

2018.

At December 31, 2016,2019, Cleco Power’s long-term debt and finance leases outstanding was $1.25$1.39 billion, of which $19.7$61.6 million was due within one year. The long-term debt due within one year at December 31, 2016,2019, primarily represents $17.9$50.0 million of GO Zone bonds with a mandatory tender in May 2020 and $11.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments.

bonds.

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,March 2, 2020, Cleco Power completed the private salerepayment 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 Facilityits Cleco Katrina/Rita storm recovery 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 millionissued in connection with such redemption, and for general company purposes.

March 2008.

Cleco Debt

Cleco had no short-term debt outstanding at December 31, 2016,2019, and 2015.

2018.

At December 31, 2016,2019, Cleco’s long-term debt and finance leases outstanding was $2.76$3.19 billion, of which $19.7$126.0 million was due within one year. The long-term debt due within one year at December 31, 2016,2019, primarily represents $17.9$63.3 million of principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC, $50.0 million of GO Zone bonds with a mandatory tender in May 2020, and $11.0 million of principal payments for the Cleco Katrina/Rita storm recovery bonds and $1.8 million of capital lease payments.

bonds.

In connection with the completion of the Merger,Cleco Cajun Transaction on April 13, 2016,February 4, 2019, Cleco Holdings entered intoborrowed $300.0 million under a $1.35 billion Acquisition Loan Facility. The Acquisition Loan Facility hadnew bridge loan agreement and $100.0 million under a new term loan agreement. Both loan agreements are variable rate debt and have a three-year term and a rate of LIBOR plus 1.75% or ABR plus 0.75%. In May and June 2016,term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings refinancedto maintain (i) a debt to capital ratio (as defined in the Acquisition Loan Facility withapplicable agreement) below 65% and (ii) a series of other long-term financings described below.

rating applicable to Cleco’s senior debt rating (as defined in the applicable agreement). On May 17, 2016,September 11, 2019, Cleco Holdings completed the private saleplacement of $535.0$300.0 million aggregate principal amount of 3.743%its 3.375% 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.September 15, 2029. 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 costsremaining amounts due under the $300.0 million bridge loan agreement and to repay a portion of $17.7the $100.0 million term loan agreement. The senior notes are governed by an indenture entered into between Cleco Holdings and a trustee. The indenture contains certain covenants that restrict Cleco Holdings’ ability to merge, consolidate, transfer, or lease all or substantially all of its assets or create or incur certain liens.

Upon approval of the Cleco Cajun Transaction, commitments were expensedmade to merger costs in connection with the LPSC by Cleco, including repayment of the Acquisition Loan Facility.$400.0 million of Cleco Holdings’ debt by December 31, 2024. As of December 31, 2019, Cleco Holdings was in compliance with these commitments. The cumulative minimum principal amounts committed to be repaid for each year through 2024 are as follows:
(THOUSANDS)
 
For the year ending Dec. 31
 
2019
$66,700
2020
$133,300
2021
$200,000
2022
$267,700
2023
$333,300
2024
$400,000
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Credit Facilities

At December 31, 2016,2019, Cleco had two separate revolving credit facilities, one for Cleco Holdings in the amount of $175.0 million and one for Cleco Power in the amount of $300.0 million, with a maximum aggregate capacity of $400.0$475.0 million.

In connection with the Cleco Cajun Transaction, on February 4, 2019, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total credit facility of $175.0 million. The credit facility includes restrictive financial covenants and expires in 2021. Under covenants contained in Cleco Holdings’ credit facility, Cleco is required to maintain total indebtedness less than or equal to 65% of total capitalization. At December 31, 2015,2019, $1.01 billion of Cleco’s member’s equity was unrestricted. At December 31, 2019, Cleco Holdings was in compliance with the covenants of its credit facility. The borrowing costs under Cleco Holdings’ credit facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%. If Cleco Holding’s credit ratings were to be downgraded one level, Cleco Holdings could be required to pay higher fees and additional interest of 0.075% and 0.50%, respectively, under the pricing levels of its credit facility.
At December 31, 2019, Cleco Power had a $300.0 million credit facility. 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 restrictedincludes restrictive financial covenants and expires in 2021.

Under covenants contained in Cleco Power’s credit facility, Cleco Power is required to maintain total indebtedness less than or equal to 65% of total capitalization. At December 31, 2016,2019, $989.0 million of Cleco Power’s member’s equity was unrestricted. At December 31, 2019, Cleco Power had no borrowings outstanding underwas in compliance with the covenants in 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 inIf Cleco Power’s credit facility,ratings were to be downgraded one level, Cleco Power iscould be required to maintain total indebtedness equalpay higher fees and additional interest of 0.05% and 0.125%, respectively, under the pricing levels of its credit facility.

If Cleco Holdings or Cleco Power were to default under the covenants in their respective credit facilities or less than 65% of total capitalization. At December 31, 2016, $853.4 million of Cleco Power’s member’s equity was unrestricted. Ifother 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 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

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

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

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 910 — Pension Plan and Employee Benefits

Pension Plan and Other Benefits Plan

Employees hired before August 1, 2007, are covered by a non-contributory, defined benefit pension plan.

Benefits under the plan reflect an employee’s years of service, age at retirement, and highest total average compensation for any consecutive five calendar years during the last ten years of employment with Cleco. Cleco’s policy is to base its

contributions to the employee pension plan upon actuarial computations utilizing the projected unit credit method, subject to the IRS’s full funding limitation. On September 12, 2019, Cleco made a $12.3 million discretionary contribution to the pension plan. Cleco did not make any required or discretionary contributions to the pension plan in 2016 and 2015, nor does it expect2018 or 2017. Cleco expects to make any$83.0 million discretionary contributions in 2017.2020, which would reduce the future required contributions. The required contributions are driven by liability funding target percentages set by law which could cause the required contributions to be uneven among the years. Based on funding assumptions at December 31, 2019, management estimates that $61.8 million in pension contributions will be required through 2024. Future discretionary contributions may be made depending on changes in assumptions, the ability to utilize the contribution as a tax deduction, and requirements concerning recognizing a minimum pension liability. Adverse changes in assumptions or adverse actual events could cause additional minimum contributions. The ultimate amount and timing of the contributions may be affected by changes in the

discount rate, changes in the funding regulations, and actual returns on fund assets. Cleco Power is considered the plan sponsor and Support Group is considered the plan administrator.

The pension plan was amended on February 4, 2019, to include certain former NRG Energy employees who are now Cleco Cajun employees. The Cleco Cajun employees are eligible to participate as a cash balance participant and are credited with all service that was credited to them under the NRG Pension Plan as of February 4, 2019. Benefits under the plan amendment reflect the employee’s years of service, age at retirement, and accrued benefit at retirement.
Cleco’s retirees and their dependents may be eligible to receive medical, dental, vision, andOther Benefits. Dependents of Cleco’s retirees may also be eligible to receive Other Benefits with the exception of life insurance benefits (other benefits).benefits. Cleco recognizes the expected cost of these other benefitsOther Benefits during the periods in which the benefits are earned.

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TABLE OF CONTENTS

The employee pension plan and other benefitsOther Benefits plan obligation, plan assets, and funded status at December 31, 2016,2019, and 20152018 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
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 
PENSION BENEFITS
OTHER BENEFITS
 
FOR THE YEAR ENDED
DEC. 31,
FOR THE YEAR ENDED
DEC. 31,
(THOUSANDS)
2019
2018
2019
2018
Change in benefit obligation
 
 
 
 
Benefit obligation at beginning of period
$530,936
$567,215
$40,455
$43,203
Service cost
8,414
9,507
1,191
1,320
Interest cost
22,485
20,860
1,646
1,465
Plan participants’ contributions
1,229
1,224
Actuarial loss (gain)
73,655
(42,935)
13,897
(1,106)
Expenses paid
(2,933)
(2,786)
Benefits paid
(22,234)
(20,925)
(5,696)
(5,651)
Benefit obligation at end of period
610,323
530,936
52,722
40,455
Change in plan assets
 
 
 
 
Fair value of plan assets at beginning of period
391,933
444,089
Actual return on plan assets
81,081
(28,884)
Employer contributions
12,250
Expenses paid
(2,933)
(2,786)
Adjustment
439
Benefits paid
(22,234)
(20,925)
Fair value of plan assets at end of period
460,097
391,933
Unfunded status
$(150,226)
$(139,003)
$(52,722)
$(40,455)

The employee pension plan accumulated benefit obligation at December 31, 2016,2019, and 20152018 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 
  

 

 

   

 

 

 
 
PENSION BENEFITS
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Accumulated benefit obligation
$568,354
$491,522

The following table presents the net actuarial gains/losses transition obligations/assets, and prior service costscosts/credits included in other comprehensive income for other benefitsOther 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 benefitsOther Benefits plan atfor December 31, 2016,2019, and 2015:

2018:
 
PENSION BENEFITS
OTHER BENEFITS
 
AT DEC. 31,
AT DEC. 31,
(THOUSANDS)
2019
2018
2019
2018
Net actuarial loss (gain) occurring during period
$19,075
$9,722
$13,897
$(1,106)
Net actuarial loss amortized during period
$7,849
$12,313
$21
$135
Prior service credit amortized during period
$(71)
$(71)
$
$
F-54

  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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

TABLE OF CONTENTS

The following table presents net actuarial gains/losses and prior period service costs/credits in accumulated other comprehensive income for other benefitsOther 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 20172020 for the employee pension plan and other benefitsOther Benefits plans forat December 31, 2017, 2016,2020, 2019, and 2015:

2018:
 
PENSION BENEFITS
OTHER BENEFITS
 
AT DEC. 31,
AT DEC. 31,
(THOUSANDS)
2020
2019
2018
2020
2019
2018
Net actuarial loss
$14,824
$151,603
$140,377
$1,355
$15,732
$1,814
Prior service credit
$(60)
$(60)
$(131)
$
$
$

  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 non-service components of net periodic pension and Other Benefits cost are included in Other income (expense), net within Cleco and Cleco Power’s Consolidated Statements of Income. The components of net periodic pension and other benefitsOther Benefits costs for 2016, 2015,2019, 2018, and 20142017 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 
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 
PENSION BENEFITS
OTHER BENEFITS
 
FOR THE YEAR ENDED DEC. 31,
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
2019
2018
2017
Components of periodic benefit costs
 
 
 
 
 
 
Service cost
$8,414
$9,507
$9,039
$1,191
$1,320
1,446
Interest cost
22,485
20,860
21,648
1,646
1,465
1,569
Expected return on plan assets
(26,502)
(23,773)
(24,064)
Amortizations
 
 
 
 
 
 
Prior service credit
(71)
(71)
(71)
Net loss (gain)
7,849
12,312
10,008
21
135
(50)
Net periodic benefit cost
$12,175
$18,835
$16,560
2,858
$2,920
$2,965

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, throughyears ended December 31, 20162019, 2018, and 2017 was $1.3 million. The amounts for the predecessor periods for 2015, and 2014 were $2.1$2.2 million, $2.0 million, and $1.7$1.8 million, respectively.

Cleco Holdings is the plan sponsor for the other benefit plans. There are no assets set aside in a trust and the liabilities are reported on the individual subsidiaries’ financial statements. The expense

related to other benefitsOther Benefits reflected in Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2016, 2015,2019, 2018, and 20142017 was $3.5$3.1 million, $3.6$3.3 million, and $3.6$3.3 million, respectively. The current and non-current portions of the other benefitsOther Benefits liability for Cleco and Cleco Power at December 31, 2016,2019, and 20152018 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.

Cleco
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current
$4,401
$4,130
Non-current
$48,321
$36,325
Cleco Power
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current
$3,815
$3,584
Non-current
$42,080
$31,694
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TABLE OF CONTENTS

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 

  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 

 
PENSION BENEFITS
OTHER BENEFITS
 
AT DEC. 31,
AT DEC. 31,
 
2019
2018
2019
2018
Weighted-average assumptions used to determine the benefit obligation
 
 
 
 
Discount rate
3.43%
4.35%
3.25%
4.16%
Rate of compensation increase
2.81%
2.93%
N/A
N/A
 
PENSION BENEFITS
OTHER BENEFITS
 
FOR THE YEAR ENDED DEC. 31,
FOR THE YEAR ENDED DEC. 31,
 
2019
2018
2017
2019
2018
2017
Weighted-average assumptions used to determine the net benefit cost
 
 
 
 
 
 
Discount rate
4.35%
3.73%
4.27%
4.16%
3.47%
3.81%
Expected return on plan assets
6.55%
5.86%
6.08%
N/A
N/A
N/A
Rate of compensation increase
2.81%
2.93%
2.98%
N/A
N/A
N/A

The expected return on plan assets was determined by examining the risk profile of each target category as compared to the expected return on that risk, within the parameters determined by the retirement committee. The result was also compared to the expected rate of return of other comparable plans. In assessing the risk as compared to return profile, historical returns as compared to risk were considered. The historical risk compared to returns was adjusted for the expected future long-term relationship between risk and return. The adjustment for the future risk compared to returns was, in part, subjective and not based on any measurable or observable events. For the calculation of the 20172020 periodic expense, Cleco decreased the expected long-term return on plan assets to 6.08%5.91%. Cleco expects pension expense to decreaseincrease in 20172020 by approximately $2.2$6.0 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.

rate and a decrease in expected return on plan assets.

Employee pension plan assets may beare invested in publicly traded domestic common stocks;accordance with the Pension Plan’s Investment Policy Statement. At December 31, 2019, allowable investments included U.S. Government, federal agency,Equity Portfolios, International Equity - Developed Markets Portfolios, Emerging Markets Equity Portfolios, Multi-Asset Credits, Treasury Separate Trading of Registered Interest and corporate obligations; an international equity fund, commercial real estate funds;Principal of Securities (STRIPS), Fixed Income Portfolios - Long Credit, and pooled temporary investments. Investments in securities (obligations of U.S. Government, U.S. Government Agencies, and state and local governments, corporate debt, common/

Real Estate Portfolios.

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

Level 2—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—3 – unobservable inputs based upon the entities’ own assumptions.
F-56

TABLE OF CONTENTS

There have been no changes in the methodologies for determining fair value at December 31, 2016,2019, and December 31, 2015.2018. 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       
  

 

 

       

(THOUSANDS)
AT DEC.
31, 2019
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
Asset Description
 
 
 
 
Cash equivalents
$4,810
$
$4,810
$
Government securities
19,517
19,517
Mutual funds
 
 
 
 
Domestic
102,184
102,184
International
53,041
53,041
Real estate funds
18,017
18,017
Corporate debt
157,109
157,109
Total
$354,678
$155,225
$181,436
$18,017
Investments measured at net asset value*
103,326
 
 
 
Interest accrual
2,093
 
 
 
Total net assets
$460,097
 
 
 
*
Investments measured at net asset value consist of Common/collective trust.

   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       
  

 

 

       

(THOUSANDS)
AT DEC.
31, 2018
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
Asset Description
 
 
 
 
Cash equivalents
$2,471
$
$2,471
$
Common stock
13,111
13,111
Government securities
19,831
19,831
Mutual funds
 
 
 
 
Domestic
79,210
79,210
International
43,418
43,418
Real estate funds
20,298
20,298
Corporate debt
138,391
138,391
Total
$316,730
$135,739
$160,693
$20,298
Investments measured at net asset value*
73,100
 
 
 
Interest accrual
2,103
 
 
 
Total net assets
$391,933
 
 
 
*
Investments measured at net asset value consist of Hedge fund-of-funds and Common/collective trust.

Level 3 valuations are derived from other valuation methodologies including pricing models, discounted cash flow models, and similar techniques. Level 3 valuations incorporate subjective judgments and consider assumptions including capitalization rates, discount rates, cash flows, and other factors that are not observable in the market. Significant increases or decreases in any of those inputs in isolation would result in a significantly different fair value measurement.

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TABLE OF CONTENTS

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, 2016,2019, 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 
  

 

 

 

2018:

(THOUSANDS)
Balance, Dec. 31, 2017
$19,195
Realized losses
29
Unrealized gains
391
Purchases
710
Sales
(27)
Balance, Dec. 31, 2018
$20,298
Realized gains
370
Unrealized losses
(1,727)
Purchases
759
Sales
(1,683)
Balance, Dec. 31, 2019
$18,017
The market-related value of plan assets differs from the fair value of plan assets by the amount of deferred asset gains or losses. Actual asset returns that differ from the expected return on plan assets are deferred and recognized in the market-related value of assets on a straight-line basis over a five-year period. For 2016,2019, the return on plan assets was 10.90%22.17% compared to an expected long-term return of 6.21%6.55%. The 20152018 return on pension plan assets was (2.90)(7.31)% compared to an expected long-term return of 6.15%5.86%.

As of December 31, 2016,2019, 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 (FAS) actuarial assumed rate of return on plan assets, and

Exceed the annualized total return of athe following customized index (based on the target allocation in the glide path) consisting of a mixture of S&P 500 Index, Russell 2500 Index, MSCI EAFEMorgan Stanley Capital International All Country World ex U.S. Index, Morgan Stanley Capital International Emerging Markets Index, Customer Index related to Multi-Asset Credit asset class, Bloomberg Barclays Capital Long Credit Index, Bloomberg Barclays Capital Long Government/Credit Index,15+ Year Treasury STRIPS, and National Council of Real Estate Investment Fiduciaries Index, and U.S. Treasury Bills plus 5%.Index.

Risk characteristics of the portfolio (annualized standard deviation of returns) should be similar to or less than the custom index.
In order to meet the objectives and to control risk, the retirement committee has established the following guidelines that the investment managers must follow:

Domestic

U.S. Equity Portfolios

Equity holdings of a single company (including common stock and convertible securities) must not exceed 10% of the manager’s portfolio.portfolio measured at market value.

A minimum of 25 stocks should be owned.owned in the portfolio.

Equity holdings in a singleany one economic sector should not exceed the lesser of three times the sector’s weighting in the S&P 500 Index or 35% of the portfolio.

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

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

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

The purchase of securities on margin and short sales is prohibited.
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TABLE OF CONTENTS

International Equity Portfolios

- Developed Markets

Portfolios
Equity holdings of a single company (including common stock and convertible securities) should not exceed 5% of the manager’s portfolio.portfolio measured at market value.

A minimum of 30 stocks should be owned.

Equity holdings in a singleany industry sector should not exceed 35%.

A minimum of 50% of the countries within the MSCI EAFEMorgan Stanley Capital International All Country World ex U.S. Index should be represented within the portfolio. The allocation to an individual country should not exceed the lesser of 30% or 5 times the country’s weighting within the MSCI EAFEMorgan Stanley Capital International All Country World ex U.S. Index.

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

Emerging Markets

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

A minimum of 30 individual stocks should be owned.

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

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

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

Illiquid securities which are not readily marketable may represent no more than 10% of the manager’s portfolio.
Currency hedging decisions are at the discretion of the investment manager.

Multi-Asset Credits
Assets can include, but would not be limited to, high yield debt, emerging market debt, global investment grade credit and bank loans, as well as fixed income strategies.
Currency hedging decisions are the discretion of the investment manager.
Treasury STRIPS
The STRIPS are synthetic zero-coupon bonds that are created by separating each coupon and principal payment of a treasury bond into a separate security. STRIPS take the form of a zero-coupon bond which is sold at a discount to face value and mature at par. They are backed by U.S. Treasury securities.
Implementation of the portfolio is either through Treasury Futures or purchase of Treasury STRIPS through an investment manager.
The benchmark would be Bloomberg Barclays 15+ Year Treasury STRIPS.
Fixed Income 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 +/Portfolios - 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.
Treasury STRIPS managers will have the discretion to utilize U.S. treasury futures and STRIPS as needed to adjust the portfolio duration.
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Real Estate Portfolios

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

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

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

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

Debt portfoliosprohibited. The Long Duration fixed income managers and Treasury STRIPS manger(s) are exempt from the prohibition on derivative use.

Executionderivatives use, due to the nature of target allocation rebalancing may be implemented through short- to intermediate-term uselong duration fixed income management. Currency hedging is permitted for international investing.
The investment manager of derivatives overlay strategies. The notional value of derivative positionsaffiliated securities shall not exceed 20%purchase any securities of the total pension fund’s value at any given time.its organization or affiliated entities.

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
 

 

 

  

 

 

  

 

 

 

2019:
 
PERCENT OF TOTAL PLAN ASSETS
 
AT DEC. 31, 2019
 
MINIMUM
TARGET
MAXIMUM
Return-seeking
 
 
 
Domestic equity
 
19%
 
International equity
 
20%
 
Multi-asset credit
 
6%
 
Real estate
 
5%
 
Total return-seeking
45%
50%
55%
Liability hedging*
45%
50%
55%
*
Liability hedging is nothas no target by subcategories.subcategories

The assumed health care cost trend rates used to measure the expected cost of other benefitsOther Benefits is 5.0% for 20172020 and remains at 5.0% thereafter. The rate used for 20162019 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
  

 

 

   

 

 

 

Other Benefits:

 
ONE-PERCENTAGE POINT
(THOUSANDS)
INCREASE
DECREASE
Effect on total of service and interest cost components
$14
$(16)
Effect on postretirement benefit obligation
$205
$(229)
The projected benefit payments for the employee pension plan and other benefitsOther Benefits obligation plan for each year through 20212024 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 

(THOUSANDS)
PENSION BENEFITS
OTHER BENEFITS, GROSS
For the year ending Dec. 31,
 
 
2020
$24,065
$4,472
2021
$25,293
$4,498
2022
$26,541
$4,554
2023
$27,709
$4,536
2024
$28,741
$4,531
Next five years
$158,810
$21,706
SERP

Certain Cleco officers are covered by SERP. In 2014, SERP was closed to new participants; however, with regard to current SERP participants, including former employees or their beneficiaries, all terms of SERP will
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continue, other than as described below. SERP is a non-qualified, non-contributory, defined benefit pension plan. Generally, benefits under the plan reflect an employee’s years of service, age at retirement, and the sum of (a) the highest base salary paid out over the last five calendar years and (b) the average of the threefive 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 limitsamount the employee would have received under the terms of the original 401(k) Plan. Two executive officers’ SERP benefits will bewere 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 havehad 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,A third executive officer’s SERP was closed to new participants; however, with regard to current SERP participants, including former employees or their beneficiaries, all termsbenefit amount will be set at a specified amount based upon the year of

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. separation. Management will reviewreviews 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 fortrust. The life insurance policies issued on SERP participants.participants designate the rabbi trust as the beneficiary. Market conditions could have a significant impact on the cash surrender value of the life insurance policies. Proceeds from the life insurance policies are expected to be used to pay the SERP participants’ death benefits, as well as future SERP payments. However, because SERP is a non-qualified plan, the assets of the trust could be used to satisfy general creditors of Cleco Power in the event of insolvency. All SERP benefits are paid out of the general cash available of the respective companies from whichthat employed the officer retired.officer. Cleco Power is considered the plan sponsor and Support Group is considered the plan administrator.

SERP’s funded status at December 31, 2016,2019, and 20152018 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 BENEFITS
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
Change in benefit obligation
 
 
Benefit obligation at beginning of period
$78,414
$84,339
Service cost
330
542
Interest cost
3,326
3,077
Actuarial loss (gain)
11,608
(5,163)
Benefits paid
(4,550)
(4,381)
Benefit obligation at end of period
$89,128
$78,414

SERP’s accumulated benefit obligation at December 31, 2016,2019, and 20152018 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 

 
SERP BENEFITS
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Accumulated benefit obligation
$89,128
$78,414
The following table presents net actuarial gains/losses and prior service costscosts/credits included in other comprehensive income or regulatory assets related to current year gains and losses as a result of being amortized as a component of net periodic benefit costs for SERP atfor December 31, 2016,2019, and 2015:2018:
 
SERP BENEFITS
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
Net actuarial loss (gain) occurring during year
$11,608
$(5,163)
Net actuarial loss amortized during year
$1,544
$2,913
Prior service credit amortized during year
$(160)
$(160)
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  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/actuarial 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 20172020 for SERP forat December 31, 2017, 2016,2020, 2019, 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 
2018:
 
SERP BENEFITS
 
AT DEC. 31,
(THOUSANDS)
2020
2019
2018
Net actuarial loss
$3,171
$28,731
$17,261
Prior service credit
$(160)
$(1,678)
$(1,837)

The non-service components of net periodic benefit cost related to SERP are included in Other income (expense), net within Cleco and Cleco Power’s Consolidated Statements of Income. The components of the net SERP costs for 2016, 2015,2019, 2018, and 20142017 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 
  

 

 

   

 

 

   

 

 

   

 

 

 

 
SERP BENEFITS
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Components of periodic benefit costs
 
 
 
Service cost
$330
$542
$494
Interest cost
3,326
3,077
3,239
Amortizations
 
 
 
Prior service credit
(160)
(160)
(190)
Net loss
1,544
2,913
2,105
Net periodic benefit cost
5,040
6,372
5,648
Special/contractual termination benefits
315
Total benefit cost
$5,040
$6,372
$5,963

There was a remeasurement of SERP at April 13, 2016,March 30, 2017, to reflect change in control benefits as a result of the Merger.special termination benefit resulting from an executive officer’s separation agreement. On the date of the remeasurement, the discount rate decreased from 4.60%4.22% to 4.15%4.08%. This remeasurement resulted in a $3.6 million curtailment charge and $3.2 millionspecial termination benefit for the executive officer 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%.

$0.3 million.

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

  SERP 
  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 BENEFITS
 
AT DEC. 31,
 
2019
2018
Weighted-average assumptions used to determine the benefit obligation
 
 
Discount rate
3.37%
4.34%
Rate of compensation increase
5.00%
5.00%
 
SERP BENEFITS
 
JAN. 1, 2019 -
DEC. 31, 2019
JAN. 1, 2018 -
DEC. 31, 2018
MAR. 31, 2017 -
DEC. 31, 2017
JAN. 1, 2017 -
MAR. 30, 2017
Weighted-average assumptions used to determine the net benefit cost
 
 
 
 
Discount rate
4.34%
3.70%
4.08%
4.22%
Rate of compensation increase
5.00%
5.00%
5.00%
5.00%

  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, 2015,2019, 2018, and 20142017 was $0.8 million, $1.4 million, $2.2and $1.3 million, and $1.7 million, respectively.

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Liabilities relating to SERP are reported on the individual subsidiaries’ financial statements.Thestatements. The current and non-current portions of the SERP liability

for Cleco and Cleco Power at December 31, 2016,2019, and 20152018 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 

Cleco
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current
$4,599
$4,478
Non-current
$84,529
$73,936
Cleco Power
 
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current
$760
$930
Non-current
$13,964
$12,025
The projected benefit payments for the SERP for each year through 20212024 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 

(THOUSANDS)
2020
2021
2022
2023
2024
NEXT FIVE
YEARS
SERP
$4,662
$4,689
$4,698
$4,710
$4,753
$24,861
401(k)

Plan

Cleco’s 401(k) Plan is intended to provide active, eligible employees with voluntary, long-term savings and investment opportunities. The 401(k) Plan is a defined

contribution plan and is subject to the applicable provisions of the Employee Retirement Income Security Act of 1974. In accordance with the 401(k) Plan, employer contributions can beare made in the form of cash. Cash contributions are invested in proportion to the participant’s voluntary contribution investment choices. Participation in the Plan is voluntary and active Cleco employees are eligible to participate. Cleco’s 401(k) was amended upon the close of the Cleco Cajun Transaction to include Cleco Cajun employees. Cleco’s 401(k) Plan expense for the years ended December 31, 2016, 2015,2019, 2018, and 2014 is2017 was 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 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
401(k) Plan expense
$7,861
$5,884
$5,386
Cleco Power is the plan sponsor for the 401(k) Plan. The expense of the 401(k) Plan related to Cleco’s other subsidiaries for the years ended December 31, 2016, 2015,2019, 2018, and 2014 is2017 was 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 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
401(k) Plan expense
$3,408
$1,066
$888
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Note 10—11 — Income Taxes

Cleco

For the successor period April 13, 2016, through December 31, 2016, and the predecessor period for the yearyears ended December 31, 2015,2019, and 2018, 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, 2014,2017, 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
 

 

 

  

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT PERCENTAGES)
2019
2018
2017
Income before tax
$195,830
$123,819
$145,159
Statutory rate
21.0%
21.0%
35.0%
Tax expense at federal statutory rate
$41,124
$26,002
$50,806
Increase (decrease)
 
 
 
Plant differences, including AFUDC flowthrough
(4,687)
(401)
743
State income taxes, net of federal benefit
9,565
6,288
5,047
Return to accrual adjustment
(3,963)
(193)
(608)
TCJA
(19)
(46,291)
NMTC
(1,578)
313
Other, net
1,126
(717)
(2,931)
Total tax expense
$43,165
$29,382
$7,079
Effective rate
22.0%
23.7%
4.9%
Information about current and deferred income tax expense is as follows:
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Current federal income tax expense
$1,600
$15,304
$46,520
Deferred federal income tax expense (benefit)
37,963
5,863
(47,329)
Amortization of accumulated deferred investment tax credits
(191)
(236)
(662)
Total federal income tax expense (benefit)
$39,372
$20,931
$(1,471)
Current state income tax expense
1,675
7,771
3,187
Deferred state income tax expense
2,118
680
5,363
Total state income tax expense
$3,793
$8,451
$8,550
Total federal and state income tax expense
$43,165
$29,382
$7,079
Items charged or credited directly to member’s equity
 
 
 
Federal deferred
(5,130)
1,408
(2,380)
State deferred
(1,678)
460
(384)
Total tax (benefit) expense from items charged directly to member’s equity
$(6,808)
$1,868
$(2,764)
Total federal and state income tax expense
$36,357
$31,250
$4,315
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  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 
 

 

 

  

 

 

  

 

 

  

 

 

 

The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2016,2019, and 20152018 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
 

 

 

  

 

 

 

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Depreciation and property basis differences
$(862,263)
$(664,996)
Net operating loss carryforward
120,955
NMTC
92,364
86,673
Fuel costs
(3,984)
(8,339)
Other comprehensive income
10,612
640
Regulated operations regulatory liability, net
34,836
39,808
Postretirement benefits
22,691
19,580
Merger fair value adjustments
(52,957)
(56,725)
Other
(19,312)
(24,671)
Accumulated deferred federal and state income taxes, net
$(657,058)
$(608,030)
Valuation Allowance

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized. As of December 31, 2016,2019, and 2015,2018, Cleco had a deferred tax asset resulting from NMTC carryforwards of $97.5$92.4 million and $96.5$86.9 million, respectively. If the NMTC carryforwards are not utilized, they will begin to expire in 2029. Management considers it more likely than not that all deferred tax assets related to NMTC carryforwards will be realized; therefore, no valuation allowance has been recorded.

Net Operating Losses

As

For the 2019 tax year, Cleco created approximately $536.5 million and $68.7 million of December 31, 2016,federal and state net operating losses, respectively, primarily due to the Cleco had aCajun Transaction.
The federal net operating loss carryforward of $89.9 million and a state net operating loss carryforward of $201.1 million. The federalmay be carried forward indefinitely, and state net operating loss carryforwards will begin to expire in 2031. 2039.
Cleco considers it more likely than not that these income

tax losses will be utilized to reduce future income tax 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, 2016,2019, and 20142018, income tax expense was lowerhigher than the amount computed by applying the statutory rate. For the year ended December 31, 2015,2017, income tax expense was higherlower 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
 

 

 

  

 

 

  

 

 

 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS, EXCEPT PERCENTAGES)
2019
2018
2017
Income before tax
$193,714
$218,181
$218,069
Statutory rate
21.0%
21.0%
35.0%
Tax expense at federal statutory rate
$40,680
$45,818
$76,324
Increase (decrease)
 
 
 
Plant differences, including AFUDC flowthrough
(4,687)
(401)
743
State income taxes, net of federal benefit
11,683
11,080
7,583
Return to accrual adjustment
(2,008)
483
(284)
TCJA
(19)
(14,292)
Other, net
(216)
(1,037)
(2,743)
Total taxes
$45,452
$55,924
$67,331
Effective rate
23.5%
25.6%
30.9%
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Information about current and deferred income tax expense is as follows:

   FOR THE YEAR ENDED
DEC. 31,
 

(THOUSANDS)

  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 
  

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Current federal income tax expense
$14,781
$44,411
$87,433
Deferred federal income tax expense (benefit)
22,443
(9,033)
(29,190)
Amortization of accumulated deferred investment tax credits
(191)
(236)
(662)
Total federal income tax expense
$37,033
$35,142
$57,581
Current state income tax expense
9,063
23,293
14,751
Deferred state income tax benefit
(644)
(2,511)
(5,001)
Total state income tax expense
$8,419
$20,782
$9,750
Total federal and state income taxes
$45,452
$55,924
$67,331
Items charged or credited directly to members’ equity
 
 
 
Federal deferred
(2,500)
797
(141)
State deferred
(818)
261
(23)
Total tax (benefit) expense from items charged directly to member’s equity
$(3,318)
$1,058
$(164)
Total federal and state income tax expense
$42,134
$56,982
$67,167
The balance of accumulated deferred federal and state income tax assets and liabilities at

December 31, 2016,2019, and 20152018 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
 

 

 

  

 

 

 

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Depreciation and property basis differences
$(705,423)
$(666,224)
Net operating loss carryforward
2,714
Fuel costs
(5,608)
(8,339)
Other comprehensive income
7,510
4,192
Regulated operations regulatory liability, net
34,836
39,808
Postretirement benefits
10,044
11,081
Other
(1,907)
(11,283)
Accumulated deferred federal and state income taxes, net
$(657,834)
$(630,765)
Valuation Allowance

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized. Management considers it more likely than not that all deferred tax assets will be realized; therefore, no valuation allowance has been recorded.

Uncertain Tax Positions

Cleco classifies all interest related to uncertain tax positions as a component of interest payable and interest expense. At December 31, 2016,2019, and 2015,2018, 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, 2015,2019, 2018, and 2014,2017, Cleco and Cleco Power had no interest expense related to uncertain tax positions.

At December 31, 2016,2019, and 2015,2018, Cleco had no liability for unrecognized tax benefits. The total

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 incomepositions. Cleco estimates that it is reasonably possible that the balance of unrecognized tax years that remain subject to examination by the IRS are 2012, 2013, 2014,benefits as of December 31, 2019, for Cleco 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 itemsPower would be unchanged in the financial statements.

At December 31, 2016, and 2015, Cleco had no liability for uncertain tax positions.next 12 months. 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 onaffect Cleco’s effective income tax rate.

Income Tax Audits
Cleco participates in the IRS’s Compliance Assurance Process in which financial results are examined and agreed upon prior to filing federal consolidated tax returns. The 2018 federal income tax year remains subject to examination by the IRS. While the statute of limitations remains open for tax years 2016 and 2017 until 2020 and 2021, respectively, management believes the likelihood of further examination by the IRS is remote.
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The state income tax years 2016, 2017, and 2018 remain subject to examination by the Louisiana Department of Revenue.
Cleco classifies income tax penalties as a component of other expenses. For the years ended December 31, 2016,2019, and 2015,2018, no penalties were recognized.
TCJA
On December 22, 2017, the President signed into law the TCJA. The TCJA includes significant changes to the IRC, as amended, including amendments which significantly change the taxation of business entities and includes specific provisions related to rate regulated activities, including Cleco Power. The most significant change that impacts Cleco is the reduction of the corporate federal income tax rate from 35% to 21%.
The SEC Staff recognized the complexity of reflecting the impacts of the TCJA and issued guidance which clarified accounting for income taxes and allowed for up to one year to complete the required analysis and accounting (the measurement period). During the fourth quarter of 2018, Cleco finalized the remeasurement of and accounting for the effects of the TCJA, which resulted in a total net reduction in the ADIT liability for Cleco and Cleco Power of $421.2 million and $389.3 million, respectively. For more information on the year endedregulatory treatment of the TCJA regulatory liability, see Note 6 — “Regulatory Assets and Liabilities — Income Taxes” and Note 13 — “Regulation and Rates — TCJA.”
Additionally, as a result of the TCJA, effective for tax years beginning after December 31, 2014, $0.12017, corporations are no longer subject to the alternative minimum tax (AMT). For companies with unused AMT credits, the credits may be carried forward and used as refundable credits for tax years beginning after 2017, but before 2022. Cleco expects its unused AMT credits will be fully utilized by December 31, 2021. During 2018, Cleco’s $7.6 million of penalties was recognized.

unused tax credits were reclassed from Accumulated deferred federal and state income taxes, net to Taxes payable, net and Other deferred charges on Cleco’s Consolidated Balance Sheets. At December 31, 2019, and 2018, Cleco had $1.4 million and $3.8 million in AMT credits recorded in Taxes payable, net on Cleco’s Consolidated Balance Sheets for the current amount of credits expected to be utilized. At December 31, 2019, and 2018, Cleco had $1.4 million and $3.8 million in non-current AMT credits recorded in Other deferred charges on Cleco’s Consolidated Balance Sheets.

Note 11—12 — Disclosures about Segments

Segment

Cleco

Cleco’s reportable segment issegments are 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 toCleco’s reportable segments are 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

Cajun.

interconnection facility subsidiaries, and an investment subsidiary.

Cleco Power, theEach reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco’s CEO with discrete financial information and, at least quarterly, present discrete financial information to Cleco and Cleco Power’s Boards of Managers. The reportable segment prepares budgets that are presented to and approved by Cleco and Cleco Power’s Boards of Managers.

The column shown as Other in the following tables includes the holding company, a shared services subsidiary, an investment subsidiary, and a subsidiary formed to facilitate the Cleco Cajun Transaction. Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a new reportable segment. For more information on the transaction, see Note 3 — “Business Combinations.”

The financial results of Cleco’s segment isin the following tables are presented on an accrual basis. The historical segment information was not recast because the Cleco Cajun segment only consists of the newly acquired business. There were no other changes to Cleco’s existing reportable segments. Management evaluates the performance of its segmentsegments and allocates resources to itthem based on segment profit and the requirements to implement new strategic initiatives and projects to meet current business objectives. Material

intercompany transactions occur on a regular basis. These intercompany transactions relate primarily to

joint and common administrative support services as well as transmission 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 

   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 to Cleco Cajun.

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SEGMENT INFORMATION
 
 
FOR THE YEAR ENDED DEC. 31, 2019
(THOUSANDS)
CLECO
POWER
CLECO
CAJUN
OTHER
ELIMINATIONS
CONSOLIDATED
Revenue
 
 
 
 
 
Electric operations
$1,130,928
$375,489
$(9,680)
$(1)
$1,496,736
Other operations
72,833
117,468
2
(7,471)
182,832
Affiliate revenue
3,125
108
109,067
(112,300)
Electric customer credits
(38,516)
(1,447)
(39,963)
Operating revenue, net
$1,168,370
$491,618
$99,389
$(119,772)
$1,639,605
Depreciation and amortization
$172,471
$35,544
$8,305
$
$216,320
Merger transaction and commitment costs
$
$
$7,668
$
$7,668
Interest income
$4,744
$987
$974
$(615)
$6,090
Interest charges
$71,279
$35
$70,611
$(616)
$141,309
Net income (loss)
$148,262
$69,411
$(65,009)
$1
$152,665
Additions to property, plant, and equipment
$313,962
$9,174
$655
$
$323,791
Equity investment in investee
$17,072
$
$
$
$17,072
Goodwill
$1,490,797
$
$
$
$1,490,797
Total segment assets
$5,967,327
$1,011,591
$546,096
$(48,716)
$7,476,298
 
FOR THE YEAR ENDED DEC. 31, 2018
(THOUSANDS)
CLECO
POWER
OTHER
ELIMINATIONS
CONSOLIDATED
Revenue
 
 
 
 
Electric operations
$1,191,587
$(9,680)
$
$1,181,907
Other operations
82,330
2
82,332
Affiliate revenue
874
74,591
(75,465)
Electric customer credits
(33,195)
(33,195)
Operating revenue, net
$1,241,596
$64,913
$(75,465)
$1,231,044
Depreciation and amortization
$162,069
$8,344
$1
$170,414
Merger transaction and commitment costs
$
$19,514
$
$19,514
Interest income
$5,052
$1,338
$(317)
$6,073
Interest charges
$71,303
$55,659
$(320)
$126,642
Federal and state income tax expense (benefit)
$55,924
$(26,541)
$(1)
$29,382
Net income (loss)
$162,257
$(67,819)
$(1)
$94,437
Additions to property, plant, and equipment
$289,153
$1,908
$
$291,061
Equity investment in investee
$18,172
$
$
$18,172
Goodwill
$1,490,797
$
$
$1,490,797
Total segment assets
$5,839,853
$633,756
$(36,795)
$6,436,814
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FOR THE YEAR ENDED DEC. 31, 2017
(THOUSANDS)
CLECO
POWER
OTHER
ELIMINATIONS
CONSOLIDATED
Revenue
 
 
 
 
Electric operations
$1,108,389
$(10,757)
$
$1,097,632
Other operations
77,522
2,058
79,580
Affiliate revenue
851
57,168
(58,019)
Electric customer credits
(1,566)
(1,566)
Operating revenue, net
$1,185,196
$48,469
$(58,019)
$1,175,646
Depreciation and amortization
$158,415
$8,439
$
$166,854
Merger transaction and commitment costs
$
$5,445
$(293)
$5,152
Interest income
$1,283
$316
$(175)
$1,424
Interest charges
$69,362
$53,725
$(174)
$122,913
Federal and state income tax expense (benefit)
$67,331
$(60,252)
$
$7,079
Net income (loss)
$150,738
$(12,659)
$1
$138,080
Additions to property, plant, and equipment
$235,252
$1,680
$
$236,932
Equity investment in investee
$18,172
$
$
$18,172
Goodwill
$1,490,797
$
$
$1,490,797
Total segment assets
$5,679,538
$619,943
$(21,099)
$6,278,382
Cleco Power
Cleco Power is a vertically integrated, regulated electric utility operating within Louisiana and

Mississippi and is viewed as one unit by management. Discrete financial reports are prepared only at the company level.

Note 12—13 — Regulation and Rates

At December 31, 2019, Provision for rate refund on Cleco and Cleco Power’s Consolidated Balance Sheets consisted primarily of $28.7 million for the estimated refund for the tax-related benefits from the TCJA, $3.5 million for the estimated refund related to the FERC audit, $2.3 million for the estimated FRP refunds, $1.9 million for the cost of service savings refunds, and $1.0 million for potential reductions to the transmission ROE. For more information about the FERC audit, see Note 15 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — FERC Audit.”
Transmission ROE

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco Power, may collect under the MISO tariff. 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, 2016,2019, Cleco Power had $3.3$1.0 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.

change in ROE. For more information on the ROE complaint, see Note 15—“Litigation,15 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees— Litigation—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 theCleco Power’s current FRP, Cleco Power is allowed to earn a target ROE of 10.0%, while providing the opportunity to earn up to 10.9%. Additionally, 60% of retail earnings between 10.9% and 11.75%, and all retail earnings over 11.75%, are required to be refunded to customers. The amount of credits due to customers, if any, is determined by Cleco Power and the LPSC annually. Credits are typically included on customers’ bills the following summer, but the amount and timing of the refunds isare ultimately subject to LPSC approval. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP, with anticipated new rates being effective July 1, 2020. Cleco Power has responded to several sets of data requests relating to the new FRP.
Cleco Power must file annual monitoring reports no later than October 31 for the 12-month period ending June 30. In January 2020, Cleco Power was scheduled to filereached an applicationagreement with the LPSC Staff regarding the treatment and realignment of SSR revenue between base and fuel revenue that resulted in $2.3 million of refunds for a new FRP by June 30, 2017. However, as part of the merger approval process, Cleco Power agreed not

2018
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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 and confirmed no refunds for the 12-month period ended June 30, 2015, which indicated that $0.2 million2017 monitoring report. The settlement also applies to treatment of SSR revenues for the 2019 monitoring report. The 2017 monitoring report was due to be returned to eligible customers. On July 27, 2016,approved by the LPSC Staff issued theiron February 19, 2020. Cleco Power expects to refund the $2.3 million for the 2018 monitoring report indicating agreement with in March 2020. Cleco Power has responded to data requests relating to the 2019 FRP monitoring report.
Cleco Power’s refund calculation for the 12-month period ended June 30, 2015. The $0.2monitoring reports also include a $1.2 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 dueannual cost of service savings as a result of the 2016 Merger Commitments. The cost of service savings are not subject to the target ROE or any sharing mechanism. The cost of service savings are refunded annually in September and will continue until Cleco Power’s next FRP and $0.3is in effect, which is expected in July 2020. At December 31, 2019, Cleco Power had $1.9 million was dueaccrued for the estimated cost of service savings refunds.
TCJA
The provisions of the TCJA reduced the top federal statutory corporate income tax rate from 35% to 21%. As a result of the tax rate reduction, on January 1, 2018, Cleco Power began accruing an estimated reserve for the reduction in the federal statutory corporate income tax rate. In February 2018, the LPSC directed utilities, including Cleco Power, to provide considerations of the appropriate manner to flow through to ratepayers the benefits of the reduction in corporate income taxes as a result of the costTCJA. On July 10, 2019, the LPSC approved Cleco Power’s rate refund of service savings$79.2 million, plus interest, for the reduction in the statutory federal tax rate for the period from January 2018 to June 2020. The refund is being credited to customers over 12 months beginning August 1, 2019. At December 31, 2019, Cleco Power had $28.7 million accrued for the estimated federal tax-related benefits from the Merger Commitments. On DecemberTCJA and $2.4 million accrued in related interest.
Also on July 10, 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT, resulting from the enactment of the TCJA, in Cleco Power’s application for its next FRP, which was filed on June 28, 2019.
2016 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 2016 Merger. The LPSC’s written order approving the 2016 Merger was issued on April 7, 2016. Approval of the 2016 Merger was conditioned upon certain commitments, including $136.0 million of customer rate credits. 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, 2016,2019, Cleco Power had issued $121.5$135.9 million of customer rate credits. Also included in the 2016 Merger Commitments were $2.5 million of contributions for economic development for Louisiana state and local organizations to be disbursed over five years, an additional $7.0 million one-time contribution in 2016 for economic development in Cleco Power’s service territory to be administered by the LED,Louisiana Economic Development, and $6.0 million of charitable contributions to be disbursed over five years.

In addition, At December 31, 2019, Cleco Power had $3.9 million remaining accrued for the 2016 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 indiscussed above.

SSR
In September 2017. As of December 31, 2016, Cleco Power filed an Attachment Y with MISO requesting retirement of Teche Unit 3 effective April 1, 2017. MISO conducted a study which determined the proposed retirement of Teche Unit 3 would result in violations of specific applicable reliability standards for which no mitigation is available. As a result, MISO designated Teche Unit 3 as an SSR unit until such time that an appropriate alternative solution can be implemented to mitigate reliability issues. One mitigating factor identified was Cleco Power’s Terrebonne to Bayou Vista Transmission project. The Terrebonne to Bayou Vista project was completed in April 2019. Cleco Power received a termination notice, effective April 30, 2019, and filed paperwork to withdraw the filed Attachment Y. While operating as an SSR unit, Cleco Power received monthly payments that included recovery of expenses, including capital expenditures, related to the operations of Teche Unit 3. Additionally, MISO allocated SSR costs to the load serving entities that required the operation of the SSR unit, including Cleco Power. These payments and cost allocations were finalized as part of a MISO SSR settlement approved in December 2018. Cleco Power operated Teche Unit 3 as an SSR unit from April 2017 through April 2019.
Cleco Power expects Teche Unit 3 to be available to run until the estimated 2021 in-service date of Bayou Vista to Segura Transmission project, at which time, Cleco Power does not expect to offer the unit into MISO, barring any grid or customer reliability issues or other similar reasons. At December 31, 2019, Cleco Power had $0.9$6.1 million accrued for the cost savings refund. A report onnet capital refund for capital expenditures paid for by third parties while operating under the statusSSR agreement. As part of the Merger Commitments must be filed annually by October 31 forsettlement, one of the 12-month period ended June 30. On October 31, 2016,load serving entities agreed to reimburse 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 sharetheir portion of the actual taxes paidcapital refund. Management is unable 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 receiveddetermine the first set of data requests from the LPSC Staff for eachtiming 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.

capital refund.
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Note 13—14 — Variable Interest Entities

Cleco and Cleco Power apply the equity method of accounting to report the investment in Oxbow in the consolidated financial statements. Under the equity method, the assets and liabilities of this entity are

reported as Equity investment in investee on Cleco and Cleco Power’s Consolidated Balance Sheets. The revenue and expenses (excluding income taxes) of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Consolidated Statements of Income.

Oxbow is owned 50% by Cleco Power and 50% by SWEPCO. Cleco Power is not the primary beneficiary because it shares the power to control Oxbow’s significant activities with SWEPCO. Cleco Power’s current assessment of its maximum exposure to loss related to Oxbow at December 31, 2016,2019, consisted of its equity investment of $18.7$17.1 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 2016,2019, Cleco Power received $0.6$1.1 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 
  

 

 

  

 

 

 

 
AT DEC. 31,
INCEPTION TO DATE (THOUSANDS)
2019
2018
Purchase price
$12,873
$12,873
Cash contributions
6,399
6,399
Dividend received
(2,200)
(1,100)
Total equity investment in investee
$17,072
$18,172
The following table compares the carrying amount of Oxbow’s assets and liabilities with Cleco Power’s maximum exposure to loss related to its investment in Oxbow:

(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 
  

 

 

   

 

 

 

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Oxbow’s net assets/liabilities
$34,145
$36,345
Cleco Power’s 50% equity
$17,072
$18,172
Cleco Power’s maximum exposure to loss
$17,072
$18,172

The following tables contain summarized financial information for Oxbow:

(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

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Current assets
$2,239
$4,128
Property, plant, and equipment, net
23,738
25,186
Other assets
9,364
9,405
Total assets
$35,341
$38,719
Current liabilities
$1,196
$2,374
Partners’ capital
34,145
36,345
Total liabilities and partners’ capital
$35,341
$38,719
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating revenue
$8,886
$6,992
$4,189
Operating expenses
8,886
6,992
4,189
Income before taxes
$
$
$
DHLC mines lignite reserves.reserves at Oxbow through the Amended Lignite Mining Agreement. The lignite reserves are intended to be used to provide fuel to the Dolet Hills Power Station. For more information on DHLC, mines the lignite reserves at Oxbow through the Amended Lignite Mining Agreement.

see Note 15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Risks and Uncertainties.”

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

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Note 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—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.

Litigation
2016 Merger

Merger

In connection with the 2016 Merger, four actions were filed in the Ninth9th 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 2016 Merger at a price that allegedly undervalued Cleco, and failing to disclose material information about the 2016 Merger. The petitions also alleged that Cleco Partners, Cleco Corporation, Merger Sub, and in some cases, certain of the investors in Cleco Partners either aided and abetted or entered into a civil conspiracy to advance those supposed breaches of duty. The petitions seek various remedies, including monetary damages, which includes attorneys’ fees and expenses.

The four actions filed in the Ninth9th 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
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).

In November 2014, the plaintiff in theBraunstein action moved for a dismissal of the action without prejudice, and that motion was granted onin November 19, 2014. OnIn December 3, 2014, the Court consolidated the remaining three actions and appointed interim co-lead counsel. OnAlso, in 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 namesnamed Cleco Corporation, its directors, Cleco Partners, and Merger Sub as defendants. The Consolidated Amended Petition alleges,alleged, among other things, that Cleco Corporation’s directors breached their fiduciary duties to Cleco’s shareholders and grossly

mismanaged Cleco by approving the Merger Agreement because it allegedly did not value Cleco adequately, failing to structure a process through which shareholder value would be maximized, engaging in self-dealing by ignoring conflicts of interest, and failing to disclose material information about the 2016 Merger. The Consolidated Amended Petition further allegesalleged 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).

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,BCI, 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. OnIn December 11, 2014, the plaintiff in theButler action filed an Amended Class Action Petition for Damages. Each petition alleges,alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties to Cleco’s shareholders by approving the Merger Agreement because it allegedly doesdid 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 2016 Merger. Each petition further alleged that Cleco, Cleco Partners, Merger Sub, and certain of the investors in Cleco Partners aided and abetted the directors’ breaches of fiduciary duty. OnIn December 23, 2014, the directors and Cleco filed declinatory exceptions in each action on the basis that each action was improperly brought in

Orleans Parish and should either be transferred to the Ninth9th Judicial District Court for Rapides Parish or dismissed. OnAlso, in 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. OnIn January 23, 2015, the Court in the

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Creative Life Services case sustained the defendants’ declinatory exceptions and dismissed the case so that it could be transferred to the Ninth9th Judicial District Court for Rapides Parish. OnIn 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 Ninth9th Judicial District Court for Rapides Parish.

On

In February 25, 2015, the Ninth9th 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. OnIn 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 Ninth9th Judicial District Court for Rapides Parish. Cleco filed exceptions seeking dismissal of the amended petition onin July 24, 2015. Cleco believes that the allegations of the petitions in each action are without merit
In March 2016 and that it has substantial meritorious defenses to the claims set forth in each of the petitions.

On March 21,May 2016, the plaintiffs filed their Third Consolidated Amended Verified Derivative Petition for Damages and Preliminary and Permanent Injunction. On May 13, 2016, the plaintiffs filedInjunction and their Fourth Verified Consolidated Amended Class Action Petition. ThisPetition, respectively. The fourth petition eliminated the request for preliminary and permanent injunction and also named an additional executive officer as a defendant. Cleco filed exceptions seeking dismissal of the amended Petition. A hearing was held onin September 15, 2016. On September 26, 2016 and the District Court granted the exceptions filed by Cleco and dismissed all claims asserted by the former shareholders. The plaintiffs appealed the District Court’s ruling to the Louisiana Third Circuit Court of Appeal. The Third Circuit Court of Appeal heard oral arguments in the case in September 2017. In December 2017, the Third Circuit Court of Appeal issued an order reversing and remanding the case to the District Court for further proceedings. In January 2018, Cleco filed a writ with the Louisiana Supreme Court seeking review of the Third Circuit Court of Appeal’s decision. The writ was denied in March 2018 and the parties are engaged in discovery in the District Court. In November 2018, Cleco filed exceptions of no cause of action and res judicata, seeking to dismiss all claims. The District Court denied the exceptions on November 9, 2016.January 14, 2019. A briefing schedulehearing on the plaintiff’s request for certification of a class was scheduled for August 26, 2019; however, prior to the hearing, the parties reached an agreement to certify a limited class. Cleco believes that the allegations of the petitions in each action are without merit and that it has not yet been set.

substantial meritorious defenses to the claims set forth in each of the petitions.

Gulf Coast Spinning

In September 2015, a potential customer sued Cleco for failure to fully perform an alleged verbal agreement to lend or otherwise fund its startup costs to the extent of $6.5 million. Gulf Coast Spinning Company, LLC (Gulf Coast), the primary plaintiff, alleges that Cleco promised to assist it in raising approximately $60.0 million, which Gulf Coast needed to construct a cotton spinning facility near Bunkie, Louisiana. According to the petition filed by Gulf Coast in the 12th 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. OnIn 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. OnAppeal. In June 30, 2016, the Third Circuit Court of Appeal for the State of Louisiana denied the request to have the case dismissed. OnIn 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. OnIn 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. OnIn May 16, 2016, the District Court lifted the stay at the request of Gulf Coast. The parties are currently participating in discovery. Cleco believes the allegations of the petition are contradicted by the written documents executed by Gulf Coast, and are otherwise without merit, and that it has substantial meritorious defenses to the claims alleged by Gulf Coast.
Sabine River Flood
In March 2017, Cleco was served with a summons in Perry Bonin, Ace Chandler, and Michael Manuel, et al v. Sabine River Authority of Texas and Sabine River Authority of Louisiana, No. B-160173-C. The action was filed in the 163rd Judicial District Court for Orange County, Texas, and relates to flooding that occurred in
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Texas and Louisiana in March 2016. The plaintiffs have alleged that the flooding was the result of the release of water from the Toledo Bend spillway gates into the Sabine River. While the plaintiffs have made numerous allegations, they have specifically alleged that Cleco Power, included as one of several companies and governmental bodies, failed to repair one of the two hydroelectric generators at the Toledo Bend Dam, which in turn contributed to the flooding. Cleco Power does not operate the hydroelectric generator.
The suit was removed to federal court in Texas. The new federal case is Perry Bonin, et al. v. Sabine River Authority of Texas et al., No. 17-cv-134, U.S. District Court for the Eastern District of Texas (Bonin Case). The plaintiffs moved to remand the case to state court, but the district court found that the case raises a substantial federal question and denied the motion to remand. Cleco Power, along with its co-defendants, filed a motion to dismiss on various grounds, primarily arguing that the plaintiffs’ claims are preempted because they infringe on FERC’s exclusive control of dam operations. The district court granted the motion to dismiss in part, declining to rule on some of the arguments raised by the defendants, and granted the plaintiffs leave to amend their complaint. The plaintiffs filed a Fifth Amended Complaint in March 2018. Cleco Power filed a new motion to dismiss the plaintiffs’ claims.
In March 2018, approximately 26 other individual plaintiffs filed a petition against Cleco Power and other defendants in Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. D180096-C. The action was filed in the 260th Judicial District Court for Orange County, Texas. The defendants removed the case to federal court in April 2018. The new federal case is Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. 18-cv-153, U.S. District Court for the Eastern District of Texas. The allegations are essentially identical to those in the Bonin Case. Also, in April 2018, Cleco Power filed a motion to dismiss on the same grounds that previously were successful in the Bonin Case. In July 2018, the district court entered an order consolidating the Addison Case with the Bonin Case. Management believes that both cases, as they relate to Cleco Power, have no merit. In August 2018, the Judge entered an order requiring the plaintiffs to file a more definitive statement to clarify the plaintiffs’ claims. In response thereto, the plaintiffs filed a Sixth Amended Petition in September 2018. Cleco Power filed a response in October 2018. All claims were dismissed against Cleco Power by ruling of the judge on March 18, 2019. The plaintiffs filed an appeal of the dismissal with the United States Court of Appeals for the Fifth Circuit. This case has been fully briefed, and an oral argument is set for the week of March 30, 2020.
Dispute with Saulsbury Industries
In October 2018, Cleco Power sued Saulsbury Industries, Inc., the former general contractor for the St. Mary Clean Energy Center project, seeking damages for Saulsbury Industries, Inc.’s failure to complete the St. Mary Clean Energy Center project on time and for costs incurred by Cleco Power in hiring a replacement general contractor. The action was filed in the 9th Judicial District Court for Rapides Parish, No. 263339. Saulsbury Industries, Inc. removed the case to the U.S. District Court for the Western District of Louisiana, on March 1, 2019.
In January 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC, in the U.S. District Court for the Western District of Louisiana. Saulsbury Industries, Inc. alleges that Cleco Power and Cabot Corporation caused the delays in the St. Mary Clean Energy Center project, resulting in significant impact to Saulsbury Industries, Inc.’s direct and indirect costs. On June 5, 2019, Cleco Power and Cabot Corporation each filed separate motions to dismiss. On October 24, 2019, the District Court denied Cleco’s motion as premature and ruled that Saulsbury Industries, Inc. had six weeks to conduct discovery on specified jurisdictional issues. The current procedural posture of the Western District of Louisiana case reflects a recognition by Cleco Power and Saulsbury Industries, Inc. that subject matter jurisdiction is lacking and that this action, in so far as it relates to Cleco Power and Saulsbury Industries, Inc., will not proceed in federal court.
On October 10, 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC in the 16th Judicial District Court for St. Mary Parish, No. 133910-A. Saulsbury Industries, Inc. alleged that Cleco Power and Cabot Corporation caused the delays in the St. Mary Clean Energy Center project, resulting in significant impact to Saulsbury Industries, Inc.’s direct and indirect costs. Saulsbury Industries, Inc. also seeks to enforce an alleged lien on the St. Mary Energy Center project. On December 9, 2019, Cleco moved to stay the case, arguing that the Rapides Parish suit should proceed. On February 14, 2020, the court granted Cleco’s motion.
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LPSC Audits

Fuel Audit

Generally, theCleco Power’s cost of fuel used for electric generation and the cost of power purchased for utility customerspower are recovered through the LPSC-

establishedLPSC-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,In March 2018, Cleco Power received notice of an FAC audit from the LPSC initiated an audit of Cleco Power’s fuel and purchased power expenses for the period of January 2014 through2016, to December 2015.2017. The total amount of fuel expense included in the audit was $582.6$536.2 million. On January 19, 2017,In August 2018, the LPSC Staff issued its audit report which recommended no disallowance of fuel costs. Management expectsOn April 26, 2019, the report to bewas approved by the LPSC in the second quarter of 2017.LPSC. Cleco Power currently has FAC filings for 2016January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings.

Historically, the disallowances have not been material. If a disallowance of fuel cost is ordered resulting in a refund, any such refund could have a material adverse effect on the results of operations, financial condition or cash flows of the Registrants.

Environmental Audit

In July 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides forCleco Power an EAC to recover from its customers certain costs of environmental compliance. The costs eligible for recovery are prudently incurred air emissions credits associated with complying with federal, state, and local air emission regulations that apply to the generation of electricity reduced by the sale of such allowances. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. On February 3, 2016,In May 2018, Cleco Power received notice of an EAC audit from the LPSC initiated an audit of Cleco Power’s environmental costs for the period November 2010 throughof January 2016 to December 2015.2017. The total amount of environmental costsexpense included in this audit was $81.2$30.7 million. On December 1, 2016,July 16, 2019, the LPSC Staff issued its audit report, which recommended ano disallowance of environmental costs of less than $0.1 million. Thecosts. On September 11, 2019, the report was approved by the LPSC on February 17, 2017.LPSC. Cleco Power currently has EAC filings for 2016January 2018 and thereafter that remain subject to audit. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings.

Historically, the disallowances have not been material. If a disallowance of environmental cost is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.

Cleco Power began incurring additionalincurs environmental compliance expenses in the second

quarter of 2015 for reagents associated with the compliance withstandards of MATS. In June 2015, the U.S. Supreme Court remanded the MATS rule to the D.C. Circuit Court of Appeals. In December 2015, the D.C. Circuit Court of Appeals remanded the rule to the EPA; however, the D.C. Circuit Court of Appeals did not vacate this rule. OnIn 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. At the request of the EPA, in April 2017, the court issued an order holding the cases in abeyance pending the EPA’s review of its supplemental finding. These expenses are also eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC.

FERC Audit
Generally, Cleco Power records wholesale transmission revenue through approved formula rates. Attachment O of the MISO tariff and certain grandfathered agreements. The calculation of the rate formulas, as well as FERC accounting and reporting requirements, are subject to periodic audits by FERC. In March 2018, the Division of Audits and Accounting, within the Office of Enforcement of FERC, initiated an audit of Cleco Power for the period of January 1, 2014, through June 30, 2019. On September 27, 2019, Cleco Power received the final audit report, which indicated 12 findings of noncompliance with a combination of FERC accounting and reporting requirements and computation of revenue requirements along with 59 recommendations associated with the audit period. Cleco Power submitted a plan for implementing the audit recommendations on October 28, 2019. Cleco Power also submitted the refund analysis on November 7, 2019, which resulted in an estimated refund of $3.5 million related to the FERC audit findings, pending final assessment by the FERC Division of Audits and
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Accounting. This amount was recorded in Provision for rate refund on Cleco and Cleco Power’s Consolidated Balance Sheets at December 31, 2019. Cleco Power anticipates this amount to be refunded to its wholesale transmission customers as a reduction in Attachment O and grandfathered agreement rates over 12 months beginning June 1, 2020.
Transmission ROE

Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. The complaints sought to reduce the current 12.38% ROE used in MISO’s transmission rates to a proposed 6.68%.
The first complaint, filed in November 2013, is forcomplaints covered the period NovemberDecember 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 ALJadministrative law judge issued an initial decision in the second rate case docket recommending a 9.70% base ROE. A bindingIn September 2016, FERC issued a Final Order in response to the first complaint establishing a 10.32% ROE. However, on November 21, 2019, FERC voted to adopt a new methodology for evaluating base ROE for public utilities under the Federal Power Act. In addition, FERC set the MISO transmission owners’ region-wide base ROE at 9.88% for the refund period covered in the first complaint and going forward. The draft FERC order on the second ROE complaint is expectedfurther found that complainants in the second quartercomplaint proceeding failed to show that the 9.88% base ROE was unjust and unreasonable and thus dismissed the second complaint. Cleco Power is unable to determine when a final FERC Order will be issued. As of 2017.

December 31, 2019, Cleco Power had $1.0 million accrued for the change in the ROE.

In November 2014, the MISO transmission owners committee, inof 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. TheBeginning January 1, 2020, the collection of the adder is delayed untilbeing included in MISO’s transmission rates for a total ROE of 10.38%.
South Central Generating
In 2017, Louisiana Generating received insurance settlement proceeds for costs incurred to resolve a lawsuit which was brought by the resolutionEPA and the LDEQ against Louisiana Generating related to Big Cajun II, Unit 3. Entergy Gulf States, as co-owner of Big Cajun II, Unit 3, is expected to be allocated a portion of the ROE complaint proceeding.

insurance settlement proceeds. Any amount allocated to Entergy Gulf States will be determined by ongoing litigation and negotiations. South Central Generating estimated this amount to be $10.0 million. As part of December 31, 2016,the Cleco Power had $3.3Cajun Transaction, Cleco Cajun assumed the $10.0 million accruedcontingent liability and NRG Energy indemnified Cleco for losses associated with this litigation matter. As a reductionresult, Cleco also recorded a $10.0 million indemnification asset, which was included in the purchase price allocation.

Prior to the ROE,Cleco Cajun Transaction, South Central Generating was involved in various litigation matters, 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 environmental and contract proceedings, before various courts regarding matters arising out of the Registrants.

ordinary course of business. Management is unable to estimate any potential losses that Cleco Cajun may ultimately be responsible for with respect to any one of these matters. As part of the Cleco Cajun Transaction, NRG Energy indemnified Cleco for losses as of the closing date associated with matters that existed as of the closing date, including pending litigation.

Other

Cleco is involved in various litigation matters, including regulatory, environmental, and administrative proceedings before various courts, regulatory commissions, arbitrators, and governmental agencies regarding matters arising in the ordinary course of business. The liability Cleco may ultimately incur with respect to any one of these matters 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, 2016,2019, believes the probable and reasonably estimable liabilities based on the eventual disposition of these matters is $4.8$5.0 million and has accrued this amount.

Off-Balance Sheet Commitments and Guarantees

Cleco Holdings and Cleco Power have entered into various off-balance sheet commitments in the form of guarantees and standingstandby letters of credit, in order to facilitate their activities and the activities of Cleco Holdings’ subsidiaries and equity investees (affiliates). Cleco Holdings and Cleco Power have also agreed to contractual terms that require the Registrants to pay third parties if certain triggering events occur. These contractual terms generally are defined as guarantees.
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Cleco Holdings entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of credit assurance to the counterparty in the event Cleco’s affiliates do not fulfill certain contractual obligations. If Cleco Holdings had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.

The off-balance sheet commitments are not recognized on Cleco and Cleco Power’s Consolidated

Balance Sheets because management has determined that Cleco and Cleco Power’s affiliates are able to perform thesethe obligations under their contracts and that it is not probable that payments by Cleco or Cleco Power will be required.

Cleco Holdings provided guarantees and indemnities to Entergy Louisiana and Entergy Gulf States as a result of the sale of the Perryville generation facility in 2005. At December 31, 2016, theThe remaining indemnifications relate to environmental matters that may have been present prior to closing. These remaining indemnifications have no limitations to time.time limitations. The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million. Currently, managementManagement 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, theThe remaining indemnifications relate to the fundamental organizational structure of Acadia. These remaining indemnifications have no time limitations as to time or maximum potential future payments. Currently, managementManagement 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, managementManagement does not expect to be required to make any payments under these indemnifications.

As part of the Amended Lignite Mining Agreement, Cleco Power and SWEPCO, joint owners of Dolet Hills Power Station, have agreed to pay the loan and lease principal obligations of the lignite miner, DHLC, when due if DHLC does not have sufficient funds or credit to pay.

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$86.4 million; however, the Amended Lignite Mining Agreement does not contain a cap. The projection is based on the forecasted loan and lease obligations to be incurred by DHLC, primarily for purchases of equipment. Cleco Power has the right to dispute the incurrence of loan and lease obligations through the review of the mining plan before the incurrence of such loan and lease obligations. The Amended Lignite Mining Agreement is not expected to terminate pursuant to its terms until 2036 and does not affect the amount the Registrants can borrow under their credit facilities. Currently, management does not expect to be required to pay DHLC under this guarantee.

At December 31, 2019, Cleco Holdings had a $34.5 million letter of credit to MISO pursuant to energy market requirements related to Cleco Cajun’s participation in MISO. The letter of credit automatically renews each year and has no impact on the Cleco Holdings’ credit facility.
Generally, neither Cleco Holdings nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations. There are no assets held as collateral for third parties that either Cleco Holdings or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees or indemnification obligations.
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Long-Term Purchase Obligations

Cleco Holdings had no unconditional long-term purchase obligations at December 31, 2016.2019. Cleco Power hasand Cleco Cajun have several unconditional long-term purchase obligations primarily related to the purchase of petroleum coke, limestone, and energy delivery facilities.facilities, information technology outsourcing, natural gas storage, network monitoring, and software maintenance. The aggregate amount of payments required under such obligations at December 31, 2016,2019, is as follows:

YEAR ENDING DEC. 31,

  (THOUSANDS) 

2017

  $56,482 

2018

   14,905 

2019

   3,688 
  

 

 

 

Total long-term purchase obligations

  $75,075 
  

 

 

 
(THOUSANDS)
CLECO POWER
CLECO
For the year ending Dec. 31,
 
 
2020
$28,741
$89,490
2021
29,832
35,986
2022
18,025
19,311
2023
7,751
8,782
2024
7,740
9,829
Thereafter
13,242
14,474
Total long-term purchase obligations
$105,331
$177,872

PaymentsCleco’s payments under these agreements for the years ended December 31, 2016, 2015,2019, 2018, and 20142017 were $72.9$94.8 million, $89.7$70.5 million, and $90.4$47.0 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

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 
  

 

 

 

Duringthese agreements for the years ended December 31, 2016,2019, 2018, and 2015, Cleco Power incurred immaterial amounts of contingent rent under the barge agreement related to the increase in the PPI.

2017 were $35.3 million, $60.7 million, and $44.2 million, respectively.

Other

Cleco has accrued for liabilities related to third parties, employee medical benefits, and AROs. For more information on AROs, see Note 2—“Summary2 — “Summary of Significant Accounting Policies—Policies — AROs” and Note 4—“Regulatory6 — “Regulatory Assets and Liabilities—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

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 participantand Cleco Cajun are participants in the MISO market. Energy prices in the MISO market are based on LMP, which includes a component directly related to congestion on the transmission system. Pricing zones with greater transmission congestion may have a higher LMP.LMPs. Physical transmission constraints present in the MISO market could increase energy costs within Cleco Power’s pricing zones. Cleco Power usesand Cleco Cajun use FTRs to mitigate transmission congestion risk.price risks. Changes to anticipated transmission paths may result in an unexpected increase in energy costs.
On March 1, 2019, Cleco Power began to operate Dolet Hills Power Station from June through September of each year; however, Dolet Hills Power Station will continue to be available to operate in other months, as needed. Cleco Power will continue to evaluate the cost of operating the Dolet Hills Power Station compared with other alternatives and decide the best course of action for the Dolet Hills Power Station within the LPSC regulatory requirements and recovery mechanism. In January 2020, Cleco Power’s joint owner in Dolet Hills Power Station unilaterally entered into a settlement with the Arkansas Public Service Commission to seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. While this settlement does not bind Cleco Power to agree to retire the Dolet Hills Power Station by 2026, management is unable to predict the effects an early closure agreement would have on the recovery value of the plant. In addition, Cleco Power and its joint owner are in discussions around their joint venture in the Oxbow mine and their obligations under the associated mining agreement with Dolet Hills Lignite Company. Any early closure of the mine could result in increased costs to Cleco Power.

billed through fuel, which management currently believes are recoverable.
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Note 16—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, 2015,2019, 2018, and 2014.

2017.

At December 31, 2016,2019, Cleco Holdings had accounts receivablepayable of less than $0.1$33.8 million due from Cleco Group in relation to merger costs paid on behalfprimarily for affiliate settlement of Cleco Group.taxes payable. At December 31, 2016,2018, Cleco Holdings had no accounts payable due to Cleco Group. At

For the year ended December 31, 2015,2019, Cleco hadHoldings made no affiliate balances that were payabledistribution payments to or receivable from non-consolidated affiliates.

DuringCleco Group. For the successor period April 13, 2016, throughyear ended December 31, 2016,2018, Cleco Holdings received $100.7 million of equity contributions from Cleco Group and made $88.8$71.4 million of distribution payments to Cleco Group.

Cleco Power

Cleco Power has entered into service agreements with affiliates to receive and to provide goods and professional services. Charges from affiliates included in Cleco Power’s Consolidated Statements of Income primarily involve services provided by Support Group in accordance with service agreements. 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

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 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Support Group
 
 
 
Other operations and maintenance
$73,090
$56,669
$50,572
Taxes other than income taxes
$(73)
$6
$(13)
Other expense
$64
$290
$255
Cleco Holdings
 
 
 
Other expense
$
$1,007
$361
The majority of the services provided by Cleco Power relates to the lease of office space to Support Group.Group and transmission services to Cleco Cajun. Cleco Power charges affiliates the higher of management’s estimated fair market value or fully loaded costs for goods and services provided in accordance with service agreements.
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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 
 

 

 

   

 

 

   

 

 

 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Other operations revenue
 
 
 
Cleco Cajun
$7,471
$
$
Affiliate revenue
 
 
 
Support Group
3,088
874
851
Cleco Cajun
37
Other income
 
 
 
Cleco Holdings
149
1,092
494
Total
$10,745
$1,966
$1,345

Cleco Power had the following affiliate receivable and payable balances associated with the service agreements:

  AT DEC. 31, 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.

 
AT DEC. 31,
 
2019
2018
(THOUSANDS)
ACCOUNTS
RECEIVABLE
ACCOUNTS
PAYABLE
ACCOUNTS
RECEIVABLE
ACCOUNTS
PAYABLE
Cleco Holdings
$10,351
$194
$699
$88
Support Group
3,172
13,890
2,619
7,755
Cleco Cajun
958
39
Total
$14,481
$14,123
$3,318
$7,843
During 2016, 2015,2019, 2018, and 2014,2017, Cleco Power made $110.0$20.0 million, $121.4 million, and $135.0 million, and $115.0 millionrespectively, of distribution payments to Cleco Holdings, respectively. During 2016, Cleco Power received equity contributions from Cleco Holdings of $50.0 million cash.Holdings. Cleco Power received no equity contributions from Cleco Holdings in 20152019, 2018, and received a $138.1 million non-cash equity contribution relating to the transfer of Coughlin in 2014.

2017.

Cleco Power is the pension plan sponsor and the related trust holds the assets. The net unfunded status of the pension plan is reflected at Cleco Power. The liability of Cleco Power’s affiliates is transferred with a like amount of assets to Cleco Power monthly. The following table shows the expense of the pension plan related to Cleco Power’s affiliates for the years ended 20162019 and 2015:

   FOR THE YEAR
ENDED DEC. 31,
 

(THOUSANDS)

  2016   2015 

Support Group

  $1,771   $2,055 
2018:
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
Support Group
$1,316
$1,963
Cleco Cajun
$239
$

Note 17—17 — Intangible Assets, Intangible Liabilities, and Goodwill

During 2008, Cleco Katrina/Rita acquired a $177.5 million intangible asset which includes $176.0 million for the right to bill and collect storm recovery charges from customers of Cleco Power and $1.5 million of financing costs. This intangible asset is expected to 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.be fully amortized in 2020. The intangible asset’s expected amortization expense is based on the estimated collections from Cleco Power’s customers. At the end of its life, the asset will have no residual value. Cleco Katrina/Rita records amortization expense based on actual collections. At the date of the 2016 Merger, the gross balance of the Cleco Katrina/Rita intangible asset for Cleco was adjusted to be net of accumulated amortization, as no accumulated amortization existed 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.

at such date.

As a result of the 2016 Merger, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the valuation of the Cleco trade name and long-term wholesale power supply agreements. At the end of their life, these intangible assets will have no residual value. The trade name intangible asset is being amortized over its estimated economic useful life of 20 years. 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 23 years and 1915 years and the amortization is included in Electric operations on Cleco’s Consolidated Statements of Income.
As a result of the Cleco Cajun Transaction, fair value adjustments were recorded on Cleco’s Consolidated Balance Sheet for the difference between the contract and market price of acquired long-term wholesale power
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agreements. The fair value of intangible assets of $98.9 million and intangible liabilities of $14.2 million was reflected in the purchase price allocation. At the end of their life, these intangible assets and liabilities will have no residual value. These intangibles are amortized over the remaining life of each applicable contract ranging between two years and eight years. ForThe amortization is included in Electric operations on Cleco’s Consolidated Statement of Income.
As part of the successor period April 13, 2016, through December 31, 2016, Cleco recognizedCajun Transaction, Cleco assumed an LTSA for maintenance services related to the Cottonwood Plant. An intangible liability of $24.1 million was reflected in the purchase price allocation and is being amortized using the straight-line method over the estimated remaining life of the LTSA of seven years. The amortization is included as a reduction of revenue of $7.5 millionto the LTSA prepayments on Cleco’s Consolidated Balance Sheet. For more information on the fair value adjustments of intangible assets and liabilities related to the Cleco Cajun Transaction, see Note 3 — “Business Combinations.”
The following tables present Cleco and Cleco Power’s amortization of intangible assets and liabilities:
Cleco
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Intangible assets
 
 
 
Cleco Katrina/Rita right to bill and collect storm recover charges
$20,576
$20,608
$16,772
Trade name
$255
$255
$255
Power supply agreements
$24,273
$9,680
$10,757
Intangible liabilities
 
 
 
LTSA
$3,194
$
$
Power supply agreements
$3,234
$
$
No impairments for intangibles in the power supply agreements.

table above for 2019, 2018, and 2017.
Cleco Power
 
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Cleco Katrina/Rita right to bill and collect storm recovery charges
$20,576
$20,608
$16,772

The following tables summarize the balances for intangible assets and liabilities subject to amortization for Cleco and Cleco Power as of December 31, 2016, and 2015:Power:

Cleco
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Intangible assets
 
 
Cleco Katrina/Rita right to bill and collect storm recovery charges
$70,594
$70,594
Trade name
5,100
5,100
Power supply agreements
184,004
85,104
Total intangible assets carrying amount
259,698
160,798
Intangible liabilities
 
 
LTSA
24,100
Power supply agreements
14,200
Total intangible liabilities carrying amount
38,300
Net intangible assets carrying amount
221,398
160,798
Accumulated amortization
(115,167)
(76,491)
Net intangible assets subject to amortization
$106,231
$84,307
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Cleco

  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 
 

 

 

  

 

 

 

Cleco Power
 
 
AT DEC. 31,
(THOUSANDS)
2019
2018
Cleco Katrina/Rita right to bill and collect storm recovery charges
$177,537
$177,537
Accumulated amortization
(177,020)
(156,444)
Net intangible assets subject to amortization
$517
$21,093
The following tables summarizetable summarizes the amortization expense related to intangible assets and liabilities expected to be recognized in Cleco and Cleco Power’sCleco’s Consolidated 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 
Cleco
 
(THOUSANDS)
INTANGIBLE ASSETS
INTANGIBLE LIABILITIES
For the year ending Dec. 31,
 
 
2020
$26,372
$(7,012)
2021
$25,855
$(5,862)
2022
$25,855
$(5,041)
2023
$25,855
$(5,041)
2024
$29,459
$(5,041)
Thereafter
$4,707
$(3,875)

Cleco Power

EXPECTED AMORTIZATION EXPENSE

  (THOUSANDS) 

For the year ending Dec. 31,

  

2017

  $18,009 

2018

  $19,312 

2019

  $21,152 

On April 13, 2016, expects to recognize $0.5 million of amortization expense related to intangible assets on its Consolidated Statement of Income in 2020.

Goodwill
In connection with the completion of the 2016 Merger, Cleco recognized goodwill of $1.49 billion. Management has assigned the recognized goodwill to

the Cleco Power reporting segment. Goodwill is required to be tested for impairment at the reporting segment level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting segment below its carrying value. Application of the goodwill impairment test requires significant judgments, including the identification of reporting segments, assignments of assets and liabilities to reporting segments, assignment of goodwill to reporting segments, and the determination of the fair value of the reporting segments.

Cleco’s reportableCleco conducted its 2019 annual impairment test using an August 1, 2019, measurement date. The fair value of the Cleco Power reporting segment was estimated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables within the utility and energy industries. Significant assumptions used in these fair value estimates include estimation of future cash flows related to capital expenditures, long-term rate of growth, and weighted-average cost of capital or discount rate. Changes in these assumptions could materially affect the determination of fair value and goodwill impairment at Cleco Power. For more information about Cleco’s policyBased on goodwill, see Note 2—“Summarythe tests performed, management has determined that there was no impairment 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 RFPgoodwill 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

2019.

Coughlin from Evangeline to Cleco Power. In March 2014, Coughlin was transferred to Cleco Power with a net bookManagement estimated the fair value of $176.0Cleco Power’s equity to be $3.97 billion at the August 1, 2019, measurement date. The carrying value of Cleco Power’s equity was approximately $3.40 billion with the excess of the fair value over the carrying value representing 16.8% or $570.4 million. Cleco Power finalized the rate treatment of Coughlin as part of its FRP extension proceeding before the LPSC in June 2014.

There were no accumulated impairment charges.
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Note 19—18 — Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss are summarized in the following tables for Cleco and Cleco Power. All amounts are reported net of income taxes. Amounts in parentheses indicate debits.

Cleco

(THOUSANDS)

 POSTRETIREMENT
BENEFIT NET
(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 
 

 

 

  

 

 

  

 

 

 

(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)
Cleco
As a result
(THOUSANDS)
POSTRETIREMENT BENEFIT
NET GAIN (LOSS)
Balances, Dec. 31, 2016
$1,500
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year
(3,898)
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net gain
(523)
Balances, Dec. 31, 2017
$(2,921)
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the Merger, AOCI was reduced to zero on April 13, 2016, as required by acquisition accounting.year
3,681
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net loss
1,615
Reclassification of effect of tax rate change
(589)
Balances, Dec. 31, 2018
$1,786
Other comprehensive income before reclassifications
Postretirement benefit adjustments incurred during the year
(18,877)
Amounts reclassified from accumulated other comprehensive income
Amortization of postretirement benefit net loss
(422)
Balances, Dec. 31, 2019
$(17,513)
Cleco Power
 
(THOUSANDS)
POSTRETIREMENT
BENEFIT NET
(LOSS) GAIN
NET (LOSS)
GAIN ON
CASH FLOW
HEDGES
TOTAL AOCI
Balances, Dec. 31, 2016
$(7,905)
$(5,517)
$(13,422)
Other comprehensive loss before reclassifications
 
 
 
Postretirement benefit adjustments incurred during the year
(948)
(948)
Amounts reclassified from accumulated other comprehensive loss
 
 
 
Amortization of postretirement benefit net loss
476
476
Reclassification of net loss to interest charges
211
211
Balances, Dec. 31, 2017
$(8,377)
$(5,306)
$(13,683)
Other comprehensive loss before reclassifications
 
 
 
Postretirement benefit adjustments incurred during the year
954
954
Amounts reclassified from accumulated other comprehensive loss
 
 
 
Amortization of postretirement benefit net loss
1,789
1,789
Reclassification of net loss to interest charges
254
254
Reclassification of effect of tax rate change
(1,426)
(1,070)
(2,496)
Balances, Dec. 31, 2018
$(7,060)
$(6,122)
$(13,182)
Other comprehensive loss before reclassifications
 
 
 
Postretirement benefit adjustments incurred during the year
(10,344)
(10,344)
Amounts reclassified from accumulated other comprehensive loss
 
 
 
Amortization of postretirement benefit net loss
687
687
Reclassification of net gain to interest charges
254
254
Balances, Dec. 31, 2019
$(16,717)
$(5,868)
$(22,585)
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(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
 

 

 

  

 

 

  

 

 

 

Note 20 —Miscellaneous19 — Miscellaneous Financial Information (Unaudited)

Cleco

Quarterly information for Cleco for 20162019 and 20152018 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 

 
 
 
 
2019
(THOUSANDS)
1ST QUARTER
2ND QUARTER
3RD QUARTER
4TH QUARTER
Operating revenue, net
$344,186
$397,873
$487,971
$409,575
Operating income
$50,586
$87,196
$101,539
$75,573
Net income
$20,557
$44,746
$55,565
$31,797
 
 
 
 
2018
(THOUSANDS)
1ST QUARTER
2ND QUARTER
3RD QUARTER
4TH QUARTER
Operating revenue, net
$276,760
$299,261
$358,256
$296,767
Operating income
$44,734
$63,709
$86,110
$50,004
Net income
$10,861
$25,839
$47,360
$10,377
Distributions to member
$19,500
$20,400
$20,600
$10,850
Cleco Power

Quarterly information for Cleco Power for 20162019 and 20152018 is shown in the following tables:
 
 
 
 
2019
(THOUSANDS)
1ST QUARTER
2ND QUARTER
3RD QUARTER
4TH QUARTER
Operating revenue, net
$268,745
$272,972
$344,977
$281,676
Operating income
$44,905
$75,446
$78,132
$49,985
Net income
$26,712
$49,356
$51,527
$20,667
Distributions to member
$
$
$
$20,000
 
 
 
 
2018
(THOUSANDS)
1ST QUARTER
2ND QUARTER
3RD QUARTER
4TH QUARTER
Operating revenue, net
$279,387
$301,901
$360,899
$299,409
Operating income
$50,521
$72,602
$96,063
$59,786
Net income
$26,004
$43,020
$63,336
$29,897
Distributions to member
$28,000
$43,000
$50,400
$
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   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 

CLECO HOLDINGS (Parent Company Only)SCHEDULE I

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)
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 
  

 

 

   

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating expenses
 
 
 
Administrative and general
$3,263
$1,269
$602
Merger transaction costs
7,803
19,514
5,152
Other operating expense
130
318
260
Total operating expenses
11,196
21,101
6,014
Operating loss
(11,196)
(21,101)
(6,014)
Equity income from subsidiaries, net of tax
205,187)
149,543
170,706
Interest, net
(70,252)
(54,635)
(53,684)
Other income (expense), net
8,568
(1,687)
3,978
Income before income taxes
132,307
72,120
114,986
Federal and state income tax benefit
(20,358)
(22,317)
(23,094)
Net income
$152,665
$94,437
$138,080
The accompanying notes are an integral part of the Condensed Financial Statements.condensed financial statements.
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CLECO HOLDINGS (Parent Company Only)SCHEDULE I

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)
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 
  

 

 

  

 

 

  

 

 

   

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Net Income
$152,665
$94,437
$138,080
Other comprehensive (loss) income, net of tax Postretirement benefits (loss) gain (net of tax benefit of $6,808, tax expense of $1,868, and tax benefit of $2,764, respectively)
(19,299)
(5,296)
(4,421)
Total other comprehensive (loss) income, net of tax
(19,299)
(5,296)
(4,421)
Comprehensive income, net of tax
$133,366
$99,733
$133,659
The accompanying notes are an integral part of the Condensed Financial Statements.condensed financial statements.
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CLECO HOLDINGS (Parent Company Only)SCHEDULE I

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)
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.

 
AT DEC. 31,
(THOUSANDS)
2019
2018
Assets
 
 
Current assets
 
 
Cash and cash equivalents
$15,008
$76,938
Accounts receivable - affiliate
14,231
8,374
Other accounts receivable
2,650
2,755
Taxes receivable, net
6,726
7,046
Cash surrender value of trust-owned life insurance policies
68,523
59,894
Total current assets
107,138
155,007
Equity investment in subsidiaries
4,150,953
3,247,809
Accumulated deferred federal and state income taxes, net
127,655
101,015
Other deferred charges
1,831
4,532
Total assets
4,387,577
3,508,363
 
 
 
Liabilities and member’s equity
 
 
Liabilities
 
 
Current liabilities
 
 
Long-term debt due within one year
$63,300
$
Accounts payable
1,448
1,322
Accounts payable - affiliate
47,184
18,047
Interest accrued
11,005
7,576
Deferred compensation
12,115
10,753
Other current liabilities
274
273
Total current liabilities
135,326
37,971
Postretirement benefit obligations
4,481
3,894
Long-term debt, net
1,604,764
1,341,758
Total liabilities
1,744,571
1,383,623
Commitments and contingencies (Note 6)
 
 
Member’s equity
2,643,006
2,124,740
Total liabilities and member’s equity
$4,387,577
$3,508,363
The accompanying notes are an integral part of the Condensed Financial Statements.condensed financial statements.
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CLECO HOLDINGS (Parent Company Only)SCHEDULE I

SCHEDULE I
CLECO HOLDINGS (Parent Company Only)
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 
  

 

 

  

 

 

  

 

 

  

 

 

 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Operating activities
 
 
 
Net cash provided by operating activities
$189,644
$97,614
$124,817
Investing activities
 
 
 
Return of equity investment in tax credit fund
1,625
2,775
7,502
Contribution to subsidiary
(962,170)
(1,250)
Other investing
442
(630)
Net cash (used in) provided by investing activities
(960,545)
1,967
6,872
Financing activities
 
 
 
Draws on credit facility
75,000
73,000
Payments on credit facility
(75,000)
(73,000)
Issuance of long-term debt
700,000
Repayment of long-term debt
(370,000)
Payment of financing costs
(5,929)
(25)
(269)
Contribution from member
384,900
Distributions to member
(71,350)
(84,065)
Net cash provided by (used in) financing activities
708,971
(71,375)
(84,334)
Net (decrease) increase in cash and cash equivalents
(61,930)
28,206
47,355
Cash and cash equivalents at beginning of period
76,938
48,732
1,377
Cash and cash equivalents at end of period
$15,008
$76,938
$48,732
 
 
 
 
Supplementary cash flow information
 
 
 
Interest paid, net of amount capitalized
$56,768
$53,798
$52,026
Income taxes (refunded) paid, net
$(19)
$2
$(6)
Supplementary non-cash investing and financing activity
 
 
 
Non-cash contribution to subsidiary, net of tax
$
$3,865
$
The accompanying notes are an integral part of the Condensed Financial Statements.

condensed financial statements.

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TABLE OF CONTENTS

CLECO HOLDINGS (Parent Company Only) Notes to the Condensed Financial Statements

Note 1—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, 2016,2019, Cleco Holdings’ restricted net assets of consolidated subsidiaries were $1.09$1.26 billion and exceeded 25% of its total consolidated net assets.
Cleco Holdings’ only major, first-tier subsidiary issubsidiaries are Cleco Power.Power and Cleco Cajun. Cleco Power contains the LPSC-jurisdictional generation, transmission, and distribution electric utility operations serving Cleco’s traditionalits retail and wholesale customers.

Prior Upon completion of the Cleco Cajun Transaction, Cleco Cajun became a major, first tier subsidiary. Cleco Cajun is an unregulated electric utility company that owns generation and transmission assets and supplies wholesale power and capacity to March 2014, when Evangeline ownedits customers. For more information about the Cleco Cajun Transaction, see “Financial Statements and operated Coughlin, Midstream was also considered a first-tier subsidiary of Cleco Corporation. SubsequentSupplementary Data — Notes to the transfer of Coughlin from Evangeline to Cleco Power in March 2014, Midstream was no longer considered a first-tier subsidiary.

Financial Statements — Note 2 — Business Combinations.”

The accompanying financial statements have been prepared to present the results of operations, financial condition, and cash flows of Cleco Holdings on a stand-alone basis as a holding company. Investments in subsidiaries and other investees are presented using the equity method. These financial statements should be read in conjunction with Cleco’s consolidated financial statements.

Note 2—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

2 — Debt

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, 2016,2019, and 2015,2018, Cleco Holdings had no short-term debt outstanding.

At December 31, 2016,2019, Cleco Holding’s long-term debt outstanding was $1.34$1.67 billion, of which none$63.3 million was due within one year.

The amount due within one year represents principal payments on Cleco Holdings’ debt as required by the Cleco Cajun Transaction commitments to the LPSC.

In connection with the completion of the Merger,Cleco Cajun Transaction on April 13, 2016,February 4, 2019, Cleco Holdings entered intoborrowed $300.0 million under a $1.35 billion Acquisition Loan Facility. The Acquisition Loan Facility hadnew bridge loan agreement and $100.0 million under a new term loan agreement. Both loan agreements are variable rate debt and have a three-year term and a rate of LIBOR plus 1.75% or ABR plus 0.75%. In May and June 2016,term. Both loan agreements contain certain financial covenants, including requiring Cleco Holdings refinancedto maintain (i) a debt to capital ratio (as defined in the Acquisition Loan Facility withapplicable agreement) below 65% and (ii) a series of other long-term financings described below.

rating applicable to Cleco Holdings’ senior debt rating (as defined in the applicable agreement). On May 17, 2016,September 11, 2019, Cleco Holdings completed the private saleplacement of $535.0$300.0 million aggregate principal amount of 3.743%its 3.375% 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.September 15, 2029. 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 costsremaining amounts due under the $300.0 million bridge loan agreement and to repay a portion of $17.7the $100.0 million term loan agreement. The senior notes are governed by an indenture entered into between Cleco Holdings and a trustee. The indenture contains certain covenants that restrict Cleco Holdings’ ability to merge, consolidate, transfer, or lease all or substantially all of its assets or create or incur certain liens.

Upon approval of the Cleco Cajun Transaction, commitments were expensedmade to

the LPSC by Cleco Holdings, including repayment of $400.0 million of Cleco Holdings’ debt by December 31, 2024. As of December 31, 2019, Cleco Holdings was in compliance with these commitments. The cumulative minimum principal amounts committed to be repaid for each year through 2024 are as follows:
(THOUSANDS)
 
For the year ending Dec. 31,
 
2019
$66,700
2020
$133,300
2021
$200,000
2022
$267,700
2023
$333,300
2024
$400,000

merger costs inIn connection with the repaymentCleco Cajun Transaction, Cleco Holdings increased its credit facility capacity by $75.0 million, for a total credit facility of $175.0 million. All other terms remained the Acquisition Loan Facility.same.

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TABLE OF CONTENTS

The principal amounts payable under long-term debt agreements for each year through 20212024 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 
AMOUNTS PAYABLE UNDER LONG-TERM DEBT ARRANGEMENTS
(THOUSANDS)
For the year ending Dec. 31,
 
2020
$
2021
$330,000
2022
$
2023
$165,000
2024
$
Thereafter
$1,185,000

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—3 — Cash Distributions and Equity Contributions

Some provisions in Cleco Power’s debt instruments restrict the amount of equity available for distribution to Cleco Holdings by Cleco Power by requiring Cleco Power’s total indebtedness to be less than or equal to 65% of total capitalization. In addition, the 2016 Merger Commitments provide for limitations on the amount of distributions that may be paid from Cleco Power to Cleco Holdings, depending on Cleco Power’s common equity ratio and its corporate credit ratings.

The following table summarizes the cash distributions Cleco Holdings received from affiliates during 2016, 2015,2019, 2018, 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 
 

 

 

  

 

 

  

 

 

  

 

 

 
2017:
 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Cleco Power
$20,000
$121,400
$135,000
Cleco Cajun
205,000
Perryville
225
6,850
Attala
217
7,160
Total
$225,000
$121,842
$149,010

During the predecessor period January 1, 2014, throughboth years ended December 31, 2014,2019, and 2017, Cleco Holdings made a $138.1 millionno 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 noequity contributions to affiliates. During the successor period April 13, 2016, throughyear ended December 31, 2016,2018, Cleco Holdings made a contribution$1.8 million and $2.1 million in non-cash equity contributions to Perryville and Attala, respectively.

During the year ended December 31, 2019, Cleco Holdings made $962.2 million of $50.0 millioncontributions to Cleco Power.Cajun to finance the Cleco Cajun Transaction. During the successor period April 13, 2016, throughyear ended December 31, 2016,2018, Cleco Holdings made $1.3 million of contributions to Cleco Cajun. During the year ended December 31, 2017, Cleco Holdings made no cash contributions to affiliates.
During the year ended December 31, 2019, Cleco Holdings received $100.7$384.9 million of equity contributions from Cleco GroupGroup. During both years ended December 31, 2018, and 2017, Cleco Holdings received no equity contributions from Cleco Group.
During the year ended December 31, 2019, Cleco Holdings made $88.8no distribution payments to Cleco Group. During the years ended December 31, 2018, and 2017, Cleco Holdings made $71.4 million and $84.1 million, respectively, of distribution payments to Cleco Group.

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Note 5—4 — 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 

 
FOR THE YEAR ENDED DEC. 31,
(THOUSANDS)
2019
2018
2017
Federal and state income tax benefit
$(20,358)
$(22,317)
$(23,094)
Equity income from subsidiaries - federal and state income tax expense
$63,523
$51,699
$30,173

For information regarding the TCJA, see “Financial Statements and Supplementary Data — Notes to the Financial Statements — Note 6—11 — Income Taxes — TCJA.”

Note 5 — Commitments and Contingencies

For information regarding commitments and contingencies related to Cleco Holdings, see Part II, Item 8, “Financial Statements and Supplementary Data—Data — Notes to the Financial Statements—Statements — Note 15—

15 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees.”

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CLECOSCHEDULE 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 

CLECO
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
 
 
 
 
(THOUSANDS)
BALANCE AT
BEGINNING
OF PERIOD
ADDITIONS
DEDUCTIONS
BALANCE AT
END OF
PERIOD(1)
Allowance for Uncollectible Accounts
 
 
 
 
Year Ended Dec. 31, 2019
$814
$2,323
$132
$3,005
Year Ended Dec. 31, 2018
$1,457
$977
$1,620
$814
Year Ended Dec. 31, 2017
$7,199
$4,179
$9,921
$1,457
(1)
Deducted in the consolidated balance sheet

(THOUSANDS)

  BALANCE AT
BEGINNING OF
PERIOD
   ADDITIONS   DEDUCTIONS   BALANCE AT
END OF
PERIOD(1)
 

Unrestricted Storm Reserve

        

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 
  

 

 

   

 

 

   

 

 

   

 

 

 

(THOUSANDS)
BALANCE AT
BEGINNING
OF PERIOD
ADDITIONS
DEDUCTIONS
BALANCE AT
END OF
PERIOD(1)
Unrestricted Storm Reserve
 
 
 
 
Year Ended Dec. 31, 2019
$3,672
$4,000
$6,572
$1,100
Year Ended Dec. 31, 2018
$4,186
$
$514
$3,672
Year Ended Dec. 31, 2017
$2,607
$4,000
$2,421
$4,186
Restricted Storm Reserve
 
 
 
 
Year Ended Dec. 31, 2019
$15,485
$800
$4,000
$12,285
Year Ended Dec. 31, 2018
$14,469
$1,016
$
$15,485
Year Ended Dec. 31, 2017
$17,385
$1,084
$4,000
$14,469
(1)
Included in the consolidated balance sheet

CLECO POWERSCHEDULE 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 
  

 

 

   

 

 

   

 

 

   

 

 

 

CLECO POWER
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
 
 
 
 
(THOUSANDS)
BALANCE AT
BEGINNING
OF PERIOD
ADDITIONS
DEDUCTIONS
BALANCE AT
END OF
PERIOD(1)
Allowance for Uncollectible Accounts
 
 
 
 
Year Ended Dec. 31, 2019
$814
$2,323
$132
$3,005
Year Ended Dec. 31, 2018
$1,457
$977
$1,620
$814
Year Ended Dec. 31, 2017
$7,199
$4,179
$9,921
$1,457
(1)
Deducted in the consolidated balance sheet

(THOUSANDS)

  BALANCE AT
BEGINNING
OF PERIOD
   ADDITIONS   DEDUCTIONS   BALANCE AT
END OF
PERIOD(1)
 

Unrestricted Storm Reserve

        

Year Ended Dec. 31, 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 
  

 

 

   

 

 

   

 

 

   

 

 

 

(THOUSANDS)
BALANCE AT
BEGINNING
OF PERIOD
ADDITIONS
DEDUCTIONS
BALANCE AT
END OF
PERIOD(1)
Unrestricted Storm Reserve
 
 
 
 
Year Ended Dec. 31, 2019
$3,672
$4,000
$6,572
$1,100
Year Ended Dec. 31, 2018
$4,186
$
$514
$3,672
Year Ended Dec. 31, 2017
$2,607
$4,000
$2,421
$4,186
Restricted Storm Reserve
 
 
 
 
Year Ended Dec. 31, 2019
$15,485
$800
$4,000
$12,285
Year Ended Dec. 31, 2018
$14,469
$1,016
$
$15,485
Year Ended Dec. 31, 2017
$17,385
$1,084
$4,000
$14,469
(1)
Included in the consolidated balance sheet
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Cleco
These unaudited condensed consolidated financial statements should be read in conjunction with Cleco’s Consolidated Financial Statements and Notes included in “Financial Statements and Supplementary Data — Consolidated Financial Statements (Audited) of Cleco.” For more information on the basis of presentation, see “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies — Basis of Presentation.”
CLECO
Condensed Consolidated Statements of Income (Unaudited)
 
FOR THE THREE
MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Operating revenue
 
 
Electric operations
$311,157
$312,949
Other operations
44,908
39,397
Gross operating revenue
356,065
352,346
Electric customer credits
(8,493)
(8,160)
Operating revenue, net
347,572
344,186
Operating expenses
 
 
Fuel used for electric generation
76,637
104,054
Purchased power
66,320
60,099
Other operations and maintenance
74,766
60,731
Depreciation and amortization
55,873
49,856
Taxes other than income taxes
16,536
13,870
Merger transaction and commitment costs
2,775
4,990
Total operating expenses
292,907
293,600
Operating income
54,665
50,586
Interest income
1,157
1,491
Allowance for equity funds used during construction
(74)
5,688
Other (expense) income, net
(12,709)
2,777
Interest charges
 
 
Interest charges, net
35,328
36,115
Allowance for borrowed funds used during construction
(179)
(2,116)
Total interest charges
35,149
33,999
Income before income taxes
7,890
26,543
Federal and state income tax expense
1,562
5,986
Net income
$6,328
$20,557
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
FOR THE THREE
MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Net income
$6,328
$20,557
Other comprehensive income (loss), net of tax
 
 
Postretirement benefits gain (loss) (net of tax expense of $146 in 2020 and tax benefit of $47 in 2019)
414
(135)
Total other comprehensive income (loss), net of tax
414
(135)
Comprehensive income, net of tax
$6,742
$20,422
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO
Condensed Consolidated Balance Sheets (Unaudited)
(THOUSANDS)
AT MAR.
31, 2020
AT DEC.
31, 2019
Assets
 
 
Current assets
 
 
Cash and cash equivalents
$350,231
$116,292
Restricted cash and cash equivalents
4,054
11,100
Customer accounts receivable (less allowance for credit losses of $2,123 in 2020 and $3,005 in 2019)
71,796
83,591
Other accounts receivable
29,485
35,731
Unbilled revenue
30,434
33,207
Fuel inventory, at average cost
109,232
83,061
Materials and supplies, at average cost
120,646
118,858
Energy risk management assets
1,992
7,023
Accumulated deferred fuel
16,353
22,910
Cash surrender value of company-/trust-owned life insurance policies
75,411
86,096
Prepayments
6,518
7,711
Regulatory assets
18,643
19,807
Other current assets
12,356
12,688
Total current assets
847,151
638,075
Property, plant, and equipment
 
 
Property, plant, and equipment
5,038,241
4,982,255
Accumulated depreciation
(503,554)
(454,874)
Net property, plant, and equipment
4,534,687
4,527,381
Construction work in progress
121,575
117,630
Total property, plant, and equipment, net
4,656,262
4,645,011
Equity investment in investee
17,072
17,072
Goodwill
1,490,797
1,490,797
Prepayments
27,794
25,949
Operating lease right of use assets
28,447
28,791
Restricted cash and cash equivalents
9,899
15,203
Note receivable
15,031
15,198
Regulatory assets
415,226
422,431
Intangible assets
131,122
138,103
Other deferred charges
37,394
39,668
Total assets
$7,676,195
$7,476,298
The accompanying notes are an integral part of the condensed consolidated financial statements.
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(THOUSANDS)
AT MAR.
31, 2020
AT DEC.
31, 2019
Liabilities and member’s equity
 
 
Liabilities
 
 
Current liabilities
 
 
Short-term debt
$238,000
$
Long-term debt and finance leases due within one year
63,932
125,986
Accounts payable
104,091
158,863
Accounts payable - affiliate
33,780
33,780
Customer deposits
59,192
58,289
Provision for rate refund
29,735
38,903
Taxes payable, net
23,902
8,931
Interest accrued
41,731
19,001
Energy risk management liabilities
9,697
4,113
Regulatory liabilities - other
3,910
6,675
Deferred compensation
9,371
12,115
Other current liabilities
45,699
44,683
Total current liabilities
663,040
511,339
Long-term liabilities and deferred credits
 
 
Accumulated deferred federal and state income taxes, net
655,027
657,058
Postretirement benefit obligations
283,830
283,075
Regulatory liabilities - deferred taxes, net
146,225
146,948
Restricted storm reserve
8,324
12,285
Deferred lease revenue
47,561
49,862
Intangible liabilities
30,119
31,872
Asset retirement obligations
23,489
23,173
Operating lease liabilities
25,119
25,779
Other deferred credits
30,474
27,222
Total long-term liabilities and deferred credits
1,250,168
1,257,274
Long-term debt and finance leases, net
3,113,239
3,064,679
Total liabilities
5,026,447
4,833,292
Commitments and contingencies (Note 14)
 
 
Member’s equity
2,649,748
2,643,006
Total liabilities and member’s equity
$7,676,195
$7,476,298
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO
Condensed Consolidated Statements of Cash Flows (Unaudited)
 
FOR THE THREE
MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Operating activities
 
 
Net income
$6,328
$20,557
Adjustments to reconcile net income to net cash provided by operating activities
 
 
Depreciation and amortization
63,307
56,776
Provision for credit losses
2,957
316
Unearned compensation expense
1,788
948
Allowance for equity funds used during construction
74
(5,688)
Loss on risk management assets and liabilities, net
6,509
954
Deferred lease revenue
(2,301)
(1,440)
Deferred income taxes
(2,900)
5,425
Deferred fuel costs
7,626
13,869
Cash surrender value of company-/trust-owned life insurance
10,686
(1,806)
Changes in assets and liabilities
 
 
Accounts receivable
13,310
(6,929)
Unbilled revenue
2,773
5,109
Fuel inventory and materials and supplies
(27,928)
(1,939)
Prepayments
(1,638)
14
Accounts payable
(55,131)
(19,999)
Accounts payable - affiliate
3,102
Customer deposits
2,731
2,598
Provision for merger commitments
1,018
(732)
Postretirement benefit obligations
1,315
192
Regulatory assets and liabilities, net
(721)
5,173
Other deferred accounts
(4,571)
(540)
Taxes accrued
14,563
5,403
Interest accrued
22,730
28,662
Deferred compensation
(2,743)
152
Other operating
424
(2,048)
Net cash provided by operating activities
60,206
108,129
Investing activities
 
 
Additions to property, plant, and equipment
(65,624)
(83,679)
Allowance for equity funds used during construction
(74)
5,688
Payment to acquire business, net of cash acquired
(814,969)
Other investing
285
299
Net cash used in investing activities
(65,413)
(892,661)
Financing activities
 
 
Draws on credit facilities
238,000
108,000
Payments on credit facilities
(108,000)
Issuances of long-term debt
400,000
Repayment of long-term debt
(11,055)
(10,382)
Payment of financing costs
(3,785)
Contributions from member
384,900
Other financing
(149)
(134)
Net cash provided by financing activities
226,796
770,599
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents
221,589
(13,933)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period
142,595(1)
140,086
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period
$364,184(2)
$126,153
Supplementary cash flow information
 
 
Interest paid, net of amount capitalized
$9,077
$5,752
Supplementary non-cash investing and financing activities
 
 
Accrued additions to property, plant, and equipment
$11,854
$56,670
(1)
Includes cash and cash equivalents of $116,292, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $15,203.
(2)
Includes cash and cash equivalents of $350,231, current restricted cash and cash equivalents of $4,054, and non-current restricted cash and cash equivalents of $9,899.
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited)
(THOUSANDS)
MEMBERSHIP
INTEREST
RETAINED
EARNINGS
AOCI
TOTAL
MEMBER’S
EQUITY
Balances, Dec. 31, 2018
$2,069,376
$53,578
$1,786
$2,124,740
Contribution from member
384,900
384,900
Net income
20,557
20,557
Other comprehensive loss, net of tax
(135)
(135)
Balances, Mar. 31, 2019
$2,069,376
$459,035
$1,651
$2,530,062
 
 
 
 
 
Balances, Dec. 31, 2019
$2,069,376
$591,143
$(17,513)
$2,643,006
Net income
6,328
6,328
Other comprehensive income, net of tax
414
414
Balances, Mar. 31, 2020
$2,069,376
$597,471
$(17,099)
$2,649,748
The accompanying notes are an integral part of the condensed consolidated financial statements.
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Cleco Power
These unaudited condensed consolidated financial statements should be read in conjunction with Cleco Power’s Consolidated Financial Statements and Notes included in “Financial Statements and Supplementary Data — Consolidated Financial Statements (Audited) of Cleco.” For more information on the basis of presentation, see “Financial Statements and Supplementary Data — Notes to the Unaudited Interim Financial Statements — Note 1 — Summary of Significant Accounting Policies — Basis of Presentation.”
CLECO POWER
Condensed Consolidated Statements of Income (Unaudited)
 
FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Operating revenue
 
 
Electric operations
$224,430
$257,175
Other operations
15,764
19,430
Affiliate revenue
1,106
300
Gross operating revenue
241,300
276,905
Electric customer credits
(8,340)
(8,160)
Operating revenue, net
232,960
268,745
Operating expenses
 
 
Fuel used for electric generation
61,064
94,131
Purchased power
23,462
29,654
Other operations and maintenance
56,944
47,700
Depreciation and amortization
43,677
42,377
Taxes other than income taxes
12,276
9,978
Total operating expenses
197,423
223,840
Operating income
35,537
44,905
Interest income
954
994
Allowance for equity funds used during construction
(74)
5,688
Other (expense) income, net
(2,667)
268
Interest charges
 
 
Interest charges, net
18,760
19,261
Allowance for borrowed funds used during construction
(179)
(2,116)
Total interest charges
18,581
17,145
Income before income taxes
15,169
34,710
Federal and state income tax expense
3,338
7,998
Net income
$11,831
$26,712
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO POWER
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Net income
$11,831
$26,712
Other comprehensive income, net of tax
 
 
Postretirement benefits gain (net of tax expense of $152 in 2020 and $55 in 2019)
426
156
Amortization of interest rate derivatives to earnings (net of tax expense of $22 in 2020 and $22 in 2019)
64
64
Total other comprehensive income, net of tax
490
220
Comprehensive income, net of tax
$12,321
$26,932
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO POWER
Condensed Consolidated Balance Sheets (Unaudited)
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Assets
 
 
Utility plant and equipment
 
 
Property, plant, and equipment
$5,542,292
$5,489,457
Accumulated depreciation
(1,941,674)
(1,905,031
Net property, plant, and equipment
3,600,618
3,584,426
Construction work in progress
114,710
111,687
Total utility plant and equipment, net
3,715,328
3,696,113
Current assets
 
 
Cash and cash equivalents
189,423
55,489
Restricted cash and cash equivalents
4,054
11,100
Customer accounts receivable (less allowance for credit losses of $2,123 in 2020 and $3,005 in 2019)
30,735
39,165
Accounts receivable - affiliate
12,037
14,481
Other accounts receivable
24,852
24,604
Unbilled revenue
30,434
33,207
Fuel inventory, at average cost
80,459
59,602
Materials and supplies, at average cost
93,544
91,941
Energy risk management assets
1,673
6,311
Accumulated deferred fuel
16,353
22,910
Cash surrender value of company-owned life insurance policies
17,614
17,574
Prepayments
4,469
4,786
Regulatory assets
10,907
10,973
Other current assets
646
655
Total current assets
517,200
392,798
Equity investment in investee
17,072
17,072
Prepayments
1,686
2,693
Operating lease right of use assets
27,883
28,633
Restricted cash and cash equivalents
9,056
14,363
Note receivable
15,031
15,198
Regulatory assets
267,602
272,289
Other deferred charges
36,791
37,371
Total assets
$4,607,649
$4,476,530
The accompanying notes are an integral part of the condensed consolidated financial statements.
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(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Liabilities and member’s equity
 
 
Member’s equity
$1,725,713
$1,713,392
Long-term debt and finance leases, net
1,377,432
1,327,372
Total capitalization
3,103,145
3,040,764
Current liabilities
 
 
Short-term debt
150,000
Long-term debt and finance leases due within one year
632
61,587
Accounts payable
77,892
110,096
Accounts payable - affiliate
10,486
14,123
Customer deposits
59,192
58,289
Provision for rate refund
28,921
38,241
Taxes payable, net
46,988
38,888
Interest accrued
23,232
7,972
Energy risk management liabilities
524
586
Regulatory liabilities - other
3,910
6,675
Other current liabilities
22,497
22,802
Total current liabilities
424,274
359,259
Commitments and contingencies (Note 14)
 
 
Long-term liabilities and deferred credits
 
 
Accumulated deferred federal and state income taxes, net
664,071
657,834
Postretirement benefit obligations
207,293
206,270
Regulatory liabilities - deferred taxes, net
146,225
146,948
Restricted storm reserve
8,324
12,285
Asset retirement obligations
7,441
7,325
Operating lease liabilities
25,001
25,658
Other deferred credits
21,875
20,187
Total long-term liabilities and deferred credits
1,080,230
1,076,507
Total liabilities and member’s equity
$4,607,649
$4,476,530
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO POWER
Condensed Consolidated Statements of Cash Flows (Unaudited)
 
FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Operating activities
 
 
Net income
$11,831
$26,712
Adjustments to reconcile net income to net cash provided by operating activities
 
 
Depreciation and amortization
45,079
43,739
Provision for credit losses
2,569
316
Allowance for equity funds used during construction
74
(5,688)
Deferred income taxes
5,341
(2,386)
Deferred fuel costs
7,626
13,869
Cash surrender value of company-owned life insurance
(40)
3,044
Changes in assets and liabilities
 
 
Accounts receivable
3,452
(8,045)
Accounts receivable - affiliate
2,863
1,687
Unbilled revenue
2,773
5,109
Fuel inventory and materials and supplies
(22,429)
(6,147)
Prepayments
1,209
965
Accounts payable
(33,749)
(10,704)
Accounts payable - affiliate
(3,817)
8,422
Customer deposits
2,731
2,598
Provision for merger commitments
(1,295)
(732)
Postretirement benefit obligations
1,181
394
Regulatory assets and liabilities, net
(1,218)
4,676
Other deferred accounts
(3,452)
(840)
Taxes accrued
7,691
(22,895)
Interest accrued
15,260
16,868
Other operating
370
(993)
Net cash provided by operating activities
44,050
69,969
Investing activities
 
 
Additions to property, plant, and equipment
(61,477)
(81,040)
Allowance for equity funds used during construction
(74)
5,688
Other investing
285
299
Net cash used in investing activities
(61,266)
(75,053)
Financing activities
 
 
Draws on credit facility
150,000
33,000
Payments on credit facility
(33,000)
Repayment of long-term debt
(11,055)
(10,382)
Other financing
(148)
(142)
Net cash provided by (used in) financing activities
138,797
(10,524)
Net increase (decrease) in cash, cash equivalents, restricted cash, and restricted cash equivalents
121,581
(15,608)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at beginning of period
80,952(1)
61,877
Cash, cash equivalents, restricted cash, and restricted cash equivalents at end of period
$202,533(2)
$46,269
The accompanying notes are an integral part of the condensed consolidated financial statements.
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FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Supplementary cash flow information
 
 
Interest paid, net of amount capitalized
$605
$1,348
Supplementary non-cash investing and financing activities
 
 
Accrued additions to property, plant, and equipment
$11,015
$49,477
(1)
Includes cash and cash equivalents of $55,489, current restricted cash and cash equivalents of $11,100, and non-current restricted cash and cash equivalents of $14,363.
(2)
Includes cash and cash equivalents of $189,423, current restricted cash and cash equivalents of $4,054, and non-current restricted cash and cash equivalents of $9,056.
The accompanying notes are an integral part of the condensed consolidated financial statements.
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CLECO POWER
Condensed Consolidated Statements of Changes in Member’s Equity (Unaudited)
(THOUSANDS)
MEMBER’S
EQUITY
AOCI
TOTAL
MEMBER’S
EQUITY
Balances, Dec. 31, 2018
$1,607,715
$(13,182)
$1,594,533
Net income
26,712
26,712
Other comprehensive income, net of tax
220
220
Balances, Mar. 31, 2019
$1,634,427
$(12,962)
$1,621,465
 
 
 
 
Balances, Dec. 31, 2019
$1,735,977
$(22,585)
$1,713,392
Net income
11,831
11,831
Other comprehensive income, net of tax
490
490
Balances, Mar. 31, 2020
$1,747,808
$(22,095)
$1,725,713
The accompanying notes are an integral part of the condensed consolidated financial statements.
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Index to Applicable Notes to the Unaudited Interim Financial Statements of Registrants
Note 1
Summary of Significant Accounting Policies
Cleco and Cleco Power
Note 2
Business Combinations
Cleco
Note 3
Recent Authoritative Guidance
Cleco and Cleco Power
Note 4
Leases
Cleco and Cleco Power
Note 5
Revenue Recognition
Cleco and Cleco Power
Note 6
Regulatory Assets and Liabilities
Cleco and Cleco Power
Note 7
Fair Value Accounting
Cleco and Cleco Power
Note 8
Debt
Cleco and Cleco Power
Note 9
Pension Plan and Employee Benefits
Cleco and Cleco Power
Note 10
Income Taxes
Cleco and Cleco Power
Note 11
Disclosures about Segments
Cleco
Note 12
Regulation and Rates
Cleco and Cleco Power
Note 13
Variable Interest Entities
Cleco and Cleco Power
Note 14
Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees
Cleco and Cleco Power
Note 15
Affiliate Transactions
Cleco and Cleco Power
Note 16
Intangible Assets and Liabilities
Cleco and Cleco Power
Note 17
Accumulated Other Comprehensive Loss
Cleco and Cleco Power
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Note 1 — Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying condensed consolidated financial statements of Cleco include the accounts of Cleco and its majority-owned subsidiaries after elimination of intercompany accounts and transactions. Cleco’s condensed consolidated financial statements include the financial results of Cleco Cajun from the closing of the Cleco Cajun Transaction on February 4, 2019, through March 31, 2020. For more information about the Cleco Cajun Transaction, see Note 2 — “Business Combinations.”
Basis of Presentation
The condensed consolidated financial statements of Cleco and Cleco Power have been prepared in accordance with GAAP for interim financial information and with the instructions to the Form 10-Q and Regulation S-X. Accordingly, these condensed consolidated financial statements do not include all of the information and notes required by GAAP for annual financial statements. The year-end condensed consolidated balance sheet data was derived from audited financial statements. Because the interim condensed consolidated financial statements and the accompanying notes do not include all of the information and notes required by GAAP for annual financial statements, the condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes in the Registrants’ Combined Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
These condensed consolidated financial statements, in the opinion of management, reflect all normal recurring adjustments that are necessary to fairly state the financial position and results of operations of Cleco and Cleco Power. Amounts reported in Cleco and Cleco Power’s interim financial statements are not necessarily indicative of amounts expected for the annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices, discrete income tax items, and other factors.
On March 11, 2020, the World Health Organization declared the current outbreak of COVID-19 to be a global pandemic, and on March 13, 2020, the U.S. declared a national emergency. In response to these declarations and the rapid spread of COVID-19, federal, state and local governments have imposed varying degrees of restrictions on business and social activities to contain COVID-19, including quarantine and “stay-at-home” orders and directives in Cleco’s service territory. Cleco has modified some of its business operations, as these restrictions have significantly impacted many sectors of the economy, including record levels of unemployment, with businesses, nonprofit organizations, and governmental entities modifying, curtailing, or ceasing normal operations. Cleco has also modified certain business practices to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities.
Cleco cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the markets will have on its business, cash flows, liquidity, financial condition, and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development of effective treatments, the duration of the outbreak, actions taken by governmental authorities, customers, suppliers and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume.
In preparing financial statements that conform to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses, and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. For information on recent authoritative guidance and its effect on financial results, see Note 3 — “Recent Authoritative Guidance.”
Restricted Cash and Cash Equivalents
Various agreements to which Cleco is subject contain covenants that restrict its use of cash. As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for its intended purposes and/or general corporate purposes.
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Cleco and Cleco Power’s restricted cash and cash equivalents consisted of the following:
Cleco
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Current
 
 
Cleco Katrina/Rita’s storm recovery bonds
$2,623
$9,632
Cleco Power’s charitable contributions
1,200
1,200
Cleco Power’s rate credit escrow
231
268
Total current
4,054
11,100
Non-current
 
 
Diversified Lands’ mitigation escrow
23
21
Cleco Cajun’s defense fund
720
719
Cleco Cajun’s margin deposits
100
100
Cleco Power’s future storm restoration costs
8,315
12,269
Cleco Power’s charitable contributions
741
2,094
Total non-current
9,899
15,203
Total restricted cash and cash equivalents
$13,953
$26,303
Cleco Power
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Current
 
 
Cleco Katrina/Rita’s storm recovery bonds
$2,623
$9,632
Charitable contributions
1,200
1,200
Rate credit escrow
231
268
Total current
4,054
11,100
Non-current
 
 
Future storm restoration costs
8,315
12,269
Charitable contributions
741
2,094
Total non-current
9,056
14,363
Total restricted cash and cash equivalents
$13,110
$25,463
Cleco Katrina/Rita had the right to bill and collect storm restoration costs from Cleco Power’s customers. As cash was collected, it was restricted for payment of administration fees, interest, and principal on storm recovery bonds. The change from December 31, 2019, to March 31, 2020, was due to Cleco Katrina/Rita using $11.1 million for the final storm recovery bond principal payment and $0.3 million for the related final interest payment, partially offset by collections of $4.4 million net of administration fees. The remaining $2.6 million of restricted cash is expected to be used for final administrative and winding up activities of Cleco Katrina/Rita.
Reserves for Credit Losses
Customer accounts receivable are recorded at the invoiced amount and do not bear interest. Customer accounts receivables are generally considered to become past due 20 days after the billing date. Cleco recognizes write-offs within the allowance for credit losses once all recovery methods have been exhausted. It is the policy of management to review accounts receivable and unbilled revenue monthly using a reserve matrix based on historical bad debt write-offs as well as current and forecasted economic conditions to establish a credit loss estimate. Management’s historical credit loss analysis included periods of economic recessions, natural disasters, and temporary changes to collection policies. Due to the critical necessity of electricity, none of these past events have significantly impacted Cleco’s credit loss rates. While the LPSC has issued a moratorium on disconnects of customers for nonpayment on March 13, 2020, and Cleco’s service territory experienced a recent decline in the economy related to the COVID-19 outbreak, the economic outlook at March 31, 2020, was still within range of Cleco’s historical credit loss analysis.
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The table below presents the changes in the allowance for credit losses by receivable for Cleco and Cleco Power:
Cleco
 
 
 
(THOUSANDS)
ACCOUNTS
RECEIVABLE
OTHERS*
TOTAL
Balances, Dec. 31, 2019
$3,005
$1,250
$4,255
CECL adoption
71
71
Current period provision
2,498
388
2,886
Charge-offs
(4,092)
(4,092)
Recovery
641
641
Balances, Mar. 31, 2020
$2,123
$1,638
$3,761
*
Loan held at Diversified Lands that is fully reserved for at March 31, 2020.
Cleco Power
(THOUSANDS)
ACCOUNTS
RECEIVABLE
Balances, Dec. 31, 2019
$3,005
CECL adoption
71
Current period provision
2,498
Charge-offs
(4,092)
Recovery
641
Balances, Mar. 31, 2020
$2,123
Fair Value Measurements and Disclosures
Various accounting pronouncements require certain assets and liabilities to be measured at their fair values. Some assets and liabilities are required to be measured at their fair value each reporting period, while others are required to be measured only one time, generally the date of acquisition or debt issuance. Cleco and Cleco Power disclose the fair value of certain assets and liabilities by one of three levels when required for recognition purposes. For more information about fair value levels, see Note 7 — “Fair Value Accounting.”
Derivatives and Other Risk Management Activity
Cleco’s Energy Market Risk Management Policy authorizes hedging of commodity price risk with physical or financially settled derivative instruments. Some of these contracts may qualify for the normal purchase, normal sale (NPNS) exception under derivative accounting guidance. Contracts that do not qualify for NPNS accounting treatment or are not elected for NPNS accounting treatment are marked-to-market and recorded on the balance sheet at their fair value.
Additionally, Cleco Power and Cleco Cajun are awarded and/or purchase FTRs in auctions facilitated by MISO. FTRs represent economic hedges of future congestion charges that will be incurred in serving customer load. FTRs are derivatives not designated as hedging instruments for accounting purposes.
Cleco Power’s FTRs are marked-to-market with the resulting unrealized gains or losses deferred as a component of deferred fuel assets or liabilities in accordance with regulatory policy. At settlement, realized gains or losses are included in the FAC and reflected on customers’ bills as a component of the fuel charge.
Cleco Cajun’s FTRs are marked-to-market with the resulting unrealized gains and losses recorded on the income statement as a component of purchased power expense. At settlement, realized gains or losses are also recorded on the income statement as a component of purchased power expense.
Cleco Cajun entered into other commodity derivative contracts during the three months ended March 31, 2020. Management did not elect to apply hedge accounting to these contracts as allowed under applicable accounting standards. When these contracts are marked-to-market, the resulting unrealized gain or loss is recorded on the income statement as a component of fuel expense for gas related derivative contracts or purchased power for
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power related derivative contracts. At settlement, realized gains or losses are also recorded on the income statement as a component of fuel expense for gas related derivative contracts or purchased power for power related derivative contracts.
For more information on FTRs and other commodity derivatives, see Note 7 — “Fair Value Accounting — Commodity Contracts.”
Cleco may also enter into contracts to mitigate the volatility in interest rate risk. These contracts include, but are not limited to, interest rate swaps and treasury rate locks. For each reporting period presented, the Registrants did not enter into any contracts to mitigate the volatility in interest rate risk.
Note 2 — Business Combinations
On February 4, 2019, Cleco Cajun acquired from NRG Energy all of the outstanding membership interests in South Central Generating. This acquisition enabled Cleco to significantly increase the scale of its operations in Louisiana.
Accounting for the Cleco Cajun Transaction
As consideration for all of the outstanding membership interest in South Central Generating, Cleco paid cash of approximately $962.2 million, which represents the $1.0 billion acquisition price net of working capital and other adjustments of $37.8 million.
Cleco Cajun accounted for the Cleco Cajun Transaction as a business combination, and accordingly, the assets acquired and liabilities assumed were recorded at their estimated fair values as of the date of the acquisition. Cleco made certain measurement period adjustments at June 30, 2019. The following chart presents Cleco’s purchase price allocation:
Purchase Price Allocation
(THOUSANDS)
AT FEB. 4, 2019
Current assets
Cash and cash equivalents
$146,494
Customer and other accounts receivable
49,809
Fuel inventory
22,060
Materials and supplies
25,659
Energy risk management assets
4,193
Other current assets
10,056
Non-current assets
Property, plant, and equipment, net
741,203
Prepayments
36,166
Restricted cash and cash equivalents
707
Intangible assets
98,900
Other deferred charges
133
Total assets acquired
1,135,380
Current liabilities
Accounts payable
38,478
Taxes payable
723
Energy risk management liabilities
241
Other current liabilities
14,570
Non-current liabilities
Accumulated deferred federal and state income taxes, net
7,165
Deferred lease revenue
58,300
Intangible liabilities
38,300
Asset retirement obligations
15,323
Operating lease liabilities
110
Total liabilities assumed
173,210
Total purchase price consideration
$962,170
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During the second quarter of 2019, certain modifications were made to the preliminary valuations as of February 4, 2019, due to the refinement of valuation models, assumptions, and inputs. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date.
Measurement Period Adjustments
(THOUSANDS)
AT JUNE 30, 2019
Current assets
Customer and other accounts receivable
$1,408
Other current assets
$56
Non-current assets
Property, plant, and equipment, net
$13,297
Prepayments
$(56)
Intangible assets
$(3,600)
Other deferred charges
$1
Current liabilities
Accounts payable
$3,022
Energy risk management liabilities
$(1)
Other current liabilities
$327
Non-current liabilities
Accumulated deferred federal and state income taxes, net
$421
Deferred lease revenue
$(3,600)
Intangible liabilities
$6,400
Asset retirement obligations
$4,534
Operating lease liabilities
$3
The measurement period adjustments resulted in an increase in electric operations revenue of $0.5 million, a decrease in other operations revenue of $0.1 million, and an increase in depreciation expense of $0.2 million recorded for the three months ended June 30, 2019.
As of December 31, 2019, Cleco completed its evaluation and determination of the fair value of assets acquired and liabilities assumed in the Cleco Cajun Transaction. There were no adjustments to those amounts during the three months ended March 31, 2020.
Pro forma Impact of the Cleco Cajun Transaction
The following table includes the unaudited pro forma financial information reflecting the consolidated results of operations of Cleco as if the Cleco Cajun Transaction had taken place on January 1, 2018. The pro forma net income for the three months ended March 31, 2019, was adjusted to exclude nonrecurring transaction-related expenses of $3.9 million.
The unaudited pro forma financial information presented in the following table is not necessarily indicative of the consolidated results of operations that would have been achieved had the transaction taken place on the date indicated, or the future consolidated results of operations of the combined companies.
Unaudited Pro Forma Financial Information
(THOUSANDS)
FOR THE THREE
MONTHS ENDED
MAR. 31, 2019
Operating revenue, net
$381,796
Net income
$32,986
Note 3 — Recent Authoritative Guidance
In June 2016, FASB amended the guidance for the measurement of credit losses on receivables and certain other assets. In-scope items for Cleco include unbilled revenue, trade receivables, notes receivables, other accounts receivables, and guarantees. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses. Effective January 1, 2020, Cleco adopted the amended guidance using the
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prospective transition method. Adoption of this standard resulted in a $0.1 million increase in credit loss reserves related to unbilled revenue and trade receivables. The current expected credit loss model did not impact reserves related to any other in-scope items. For more information on Cleco’s accounting for credit losses, see Note 1 — “Summary of Significant Accounting Policies — Reserves for Credit Losses.”
In August 2018, FASB issued guidance that allows for the deferral of certain implementation costs incurred in a cloud computing arrangement. Effective January 1, 2020, Cleco adopted the guidance using the prospective transition method. Adoption of this guidance did not materially impact the Registrants’ results of operations, financial condition, or cash flows.
In March 2020, FASB issued amendments that are elective and apply to all entities, subject to meeting certain criteria, for the contract modifications or hedging relationships that are referencing LIBOR or another reference rate expected to be discontinued due to reference rate reform. The amendments include a general principal that permits an entity to consider contract modifications due to reference rate reform to be an event that does not require contract remeasurement at the modification date or reassessment of a previous accounting determination. The amendment became effective March 12, 2020. Management is evaluating this guidance and the impact it may have on the Registrants’ results of operations, financial condition, or cash flows.
Note 4 — Leases
Cleco maintains operating and finance leases in its ordinary course of business activities.
Cottonwood Sale Leaseback Agreement
Upon closing the Cleco Cajun Transaction, the Cottonwood Sale Leaseback was executed. Under the terms of the lease, NRG Energy will operate the Cottonwood Plant, incur all costs, and receive all revenues from the operations of the plant. Cottonwood Energy will receive fixed lease payments of $40.0 million per year and variable lease payments for LTSA costs and property taxes paid by NRG Energy on behalf of Cleco. Cleco may terminate the lease contract under specific circumstances stated in the lease contract. The residual value under the Cottonwood Sale Leaseback is expected to be recovered through sales of power generation from the plant. The residual value of the Cottonwood Plant has been determined using the plant’s estimated economic life.
Cleco Cajun is Cleco’s only entity with lessor arrangements. Cleco Cajun’s lease income under the Cottonwood Sale Leaseback for the three months ended March 31, 2020, and 2019, was as follows:
 
FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Fixed payments
$10,000
$6,667
Variable payments
5,566
3,151
Amortization of deferred lease liability(1)
2,302
1,440
Total lease income
$17,868
$11,258
(1)
Consists of the deferred lease revenue resulting from the fair value of the lease between Cottonwood Energy and a special-purpose entity that is a subsidiary of NRG Energy. For more information, see Note 2 — “Business Combinations.”
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Note 5 — Revenue Recognition
Disaggregated Revenue
Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a reportable segment. For more information on the transaction, see Note 2 — “Business Combinations.”
Operating revenue, net for the three months ended March 31, 2020, and 2019, was as follows:
 
FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)
CLECO
POWER
CLECO
CAJUN
OTHER
ELIMINATIONS
TOTAL
Revenue from contracts with customers
 
 
 
 
 
Retail revenue
 
 
 
 
 
Residential(1)
$81,571
$
$
$
$81,571
Commercial(1)
61,110
61,110
Industrial(1)
32,210
32,210
Other retail(1)
3,461
3,461
Surcharge
2,443
2,443
Electric customer credits
(8,340)
(8,340)
Total retail revenue
172,455
172,455
Wholesale, net
42,229(1)
89,147
(2,420)(2)
128,956
Transmission, net
12,069
12,931(3)
(1,818)
23,182
Other
3,695(4)
1
3,696
Affiliate(5)
1,106
161
29,278
(30,545)
Total revenue from contracts with customers
231,554
102,239
26,859
(32,363)
328,289
Revenue unrelated to contracts with customers
 
 
 
 
 
Other
1,406(6)
17,877(7)
19,283
Total revenue unrelated to contracts with customers
1,406
17,877
19,283
Operating revenue, net
$232,960
$120,116
$26,859
$(32,363)
$347,572
(1)
Includes fuel recovery revenue.
(2)
Amortization of intangible assets related to Cleco Power’s wholesale power supply agreements.
(3)
Includes $0.2 million of electric customer credits.
(4)
Includes $3.7 million of other miscellaneous fee revenue.
(5)
Includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.
(6)
Includes realized gains associated with FTRs of $1.4 million.
(7)
Includes $15.6 million in lease revenue related to the Cottonwood Sale Leaseback and $2.3 million of deferred lease revenue amortization.
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FOR THE THREE MONTHS ENDED MAR. 31, 2019
(THOUSANDS)
CLECO
POWER
CLECO
CAJUN
OTHER
ELIMINATIONS
TOTAL
Revenue from contracts with customers
 
 
 
 
 
Retail revenue
 
 
 
 
 
Residential(1)
$87,148
$
$
$
$87,148
Commercial(1)
65,380
65,380
Industrial(1)
37,870
37,870
Other retail(1)
3,681
3,681
Surcharge
5,321
5,321
Electric customer credits
(8,160)
(8,160)
Total retail revenue
191,240
191,240
Wholesale, net
55,546(1)
58,191
(2,420)(2)
111,317
Transmission
12,579
8,727
21,306
Other
6,851(3)
(26)
2
6,827
Affiliate(4)
300
26,535
(26,835)
Total revenue from contracts with customers
266,516
66,892
24,117
(26,835)
330,690
Revenue unrelated to contracts with customers
 
 
 
 
 
Other
2,229(5)
11,267(6)
13,496
Total revenue unrelated to contracts with customers
2,229
11,267
13,496
Operating revenue, net
$268,745
$78,159
$24,117
$(26,835)
$344,186
(1)
Includes fuel recovery revenue.
(2)
Amortization of intangible assets related to Cleco Power’s wholesale power supply agreements.
(3)
Includes $4.4 million of other miscellaneous fee revenue and $2.4 million of Teche Unit 3 SSR revenue at Cleco Power.
(4)
Includes interdepartmental rents and support services. This revenue is eliminated upon consolidation.
(5)
Includes realized gains associated with FTRs of $4.8 million and the reversal of the LCFC revenue of $(2.6) million.
(6)
Includes $9.8 million in lease revenue related to the Cottonwood Sale Leaseback and $1.4 million of deferred lease revenue amortization.
Cleco and Cleco Power have unsatisfied performance obligations with durations ranging between 1 and 15 years that primarily relate to stand-ready obligations as part of fixed capacity minimums. At March 31, 2020, Cleco and Cleco Power had $80.7 million of unsatisfied performance obligations that will be recognized as revenue over the term of such contracts as the stand-ready obligation to provide energy is provided.
Note 6 — Regulatory Assets and Liabilities
Cleco Power capitalizes or defers certain costs for recovery from customers and recognizes a liability for amounts expected to be returned to customers based on regulatory approval and management’s ongoing assessment that it is probable these items will be recovered or refunded through the ratemaking process.
Under the current regulatory environment, Cleco Power believes these regulatory assets will be fully recoverable; however, if in the future, as a result of regulatory changes or competition, Cleco Power’s ability to recover these regulatory assets would no longer be probable, then to the extent that such regulatory assets were determined not to be recoverable, Cleco Power would be required to write-down such assets. In addition, potential deregulation of the industry or possible future changes in the method of rate regulation of Cleco Power could require discontinuance of the application of the authoritative guidance on regulated operations.
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The following table summarizes Cleco Power’s regulatory assets and liabilities:
Cleco Power
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Regulatory assets (liabilities)
 
 
Deferred taxes, net
$(146,225)
$(146,948)
Interest costs
3,896
3,958
AROs
3,815
3,668
Postretirement costs
147,889
151,543
Tree trimming costs
11,384
11,341
Training costs
6,202
6,241
Surcredits, net(1)
72
145
AMI deferred revenue requirement
3,000
3,136
Emergency declarations
948
1,349
Production operations and maintenance expenses
6,756
7,985
AFUDC equity gross-up(1)
71,992
72,766
Acadia Unit 1 acquisition costs
2,098
2,124
Financing costs
7,461
7,554
Coughlin transaction costs
899
906
Corporate franchise tax, net
(1,145)
(1,145)
Non-service cost of postretirement benefits
7,551
6,739
Energy efficiency
2,820
2,820
Accumulated deferred fuel
16,353
22,910
Other, net
(1,039)
(4,543)
Total regulatory assets, net
$144,727
$152,549
(1)
Represents regulatory assets for past expenditures that were not earning a return on investment at March 31, 2020, and December 31, 2019, respectively. All other assets are earning a return on investment.
The following table summarizes Cleco’s net regulatory assets and liabilities:
Cleco
 
 
(THOUSANDS)
AT MAR. 31,
2020
AT DEC. 31,
2019
Total Cleco Power regulatory assets, net
$144,727
$152,549
2016 Merger adjustments(1)
 
 
Fair value of long-term debt
125,105
127,977
Postretirement costs
16,902
17,399
Financing costs
7,849
7,935
Debt issuance costs
5,504
5,665
Total Cleco regulatory assets, net
$300,087
$311,525
(1)
Cleco regulatory assets include acquisition accounting adjustments as a result of the 2016 Merger.
Note 7 — Fair Value Accounting
The amounts reflected on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020, and December 31, 2019, for cash equivalents, restricted cash equivalents, accounts receivable, other accounts receivable, short-term debt, and accounts payable approximate fair value because of their short-term nature. Cleco applies the provisions of the fair value measurement standard to its non-recurring, non-financial measurements including business combinations, as well as impairment related to goodwill and other long-lived assets.
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The following tables summarize the carrying value and estimated market value of Cleco and Cleco Power’s financial instruments not measured at fair value on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets:
Cleco
 
 
 
AT MAR. 31, 2020
AT DEC. 31, 2019
(THOUSANDS)
CARRYING
VALUE*
FAIR VALUE
CARRYING
VALUE*
FAIR VALUE
Long-term debt
$3,174,821
$3,295,214
$3,188,664
$3,371,915
*
The carrying value of long-term debt does not include deferred issuance costs of $13.2 million at March 31, 2020, and $13.7 million at December 31, 2019.
Cleco Power
 
 
 
AT MAR. 31, 2020
AT DEC. 31, 2019
(THOUSANDS)
CARRYING
VALUE*
FAIR VALUE
CARRYING
VALUE*
FAIR VALUE
Long-term debt
$1,369,716
$1,696,053
$1,380,688
$1,601,865
*
The carrying value of long-term debt does not include deferred issuance costs of $7.2 million at March 31, 2020, and $7.4 million at December 31, 2019.
In order to fund capital requirements, Cleco issues fixed and variable rate long-term debt with various tenors. The fair value of this class fluctuates as the market interest rates for fixed and variable rate debt with similar tenors and credit ratings change. The fair value of the debt could also change from period to period due to changes in the credit rating of the Cleco entity by which the debt was issued. The fair value of long-term debt is classified as Level 2 in the fair value hierarchy.
Fair Value Measurements and Disclosures
Cleco classifies assets and liabilities that are measured at their fair value according to three different levels depending on the inputs used in determining fair value.
The following tables disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured on a recurring basis:
Cleco
 
 
 
 
 
 
 
 
 
FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)
AT MAR. 31,
2020
QUOTED
PRICES
IN ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
AT DEC. 31,
2019
QUOTED
PRICES
IN ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
Asset description
 
 
 
 
 
 
 
 
Institutional money market funds
$352,549
$—
$352,549
$
$129,643
$—
$129,643
$
FTRs
1,779
1,779
6,822
6,822
Other commodity derivatives
213
213
201
201
Total assets
$354,541
$—
$352,762
$1,779
$136,666
$—
$129,844
$6,822
Liability description
 
 
 
 
 
 
 
 
FTRs
$683
$—
$
$683
$1,044
$—
$
$1,044
Other commodity derivatives
12,494
12,494
5,373
5,373
Total liabilities
$13,177
$—
$12,494
$683
$6,417
$—
$5,373
$1,044
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Cleco Power
 
 
 
 
 
 
 
 
 
FAIR VALUE MEASUREMENTS AT REPORTING DATE
(THOUSANDS)
AT MAR. 31,
2020
QUOTED
PRICES IN
ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
AT DEC. 31,
2019
QUOTED
PRICES
IN ACTIVE
MARKETS
FOR
IDENTICAL
ASSETS
(LEVEL 1)
SIGNIFICANT
OTHER
OBSERVABLE
INPUTS
(LEVEL 2)
SIGNIFICANT
UNOBSERVABLE
INPUTS
(LEVEL 3)
Asset description
 
 
 
 
 
 
 
 
Institutional money market funds
$198,006
$—
$198,006
$
$74,903
$—
$74,903
$
FTRs
1,673
1,673
6,311
6,311
Total assets
$199,679
$—
$198,006
$1,673
$81,214
$—
$74,903
$6,311
Liability description
 
 
 
 
 
 
 
 
FTRs
$524
$—
$
$524
$586
$—
$
$586
Total liabilities
$524
$—
$
$524
$586
$—
$
$586
The following tables summarize the net changes in the net fair value of FTR assets and liabilities classified as Level 3 in the fair value hierarchy for Cleco and Cleco Power:
Cleco
 
 
 
FOR THE THREE
MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Beginning balance
$5,778
$22,887
Unrealized losses*
(1,398)
(1,917)
Purchases
466
5,237
Settlements
(3,750)
(18,397)
Ending balance
$1,096
$7,810
*
Cleco Power’s unrealized losses are reported through Accumulated deferred fuel on Cleco’s Condensed Consolidated Balance Sheet. Cleco Cajun’s unrealized (losses) gains are reported through Purchased power on Cleco’s Condensed Consolidated Income Statement.
Cleco Power
 
 
 
FOR THE THREE
MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
Beginning balance
$5,725
$22,887
Unrealized losses*
(1,311)
(2,939)
Purchases
466
1,286
Settlements
(3,731)
(16,422)
Ending balance
$1,149
$4,812
*
Unrealized losses are reported through Accumulated deferred fuel on Cleco Power’s Condensed Consolidated Balance Sheet.
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The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for Cleco and Cleco Power as of March 31, 2020, and December 31, 2019:
Cleco
 
 
 
 
 
FAIR VALUE
VALUATION
TECHNIQUE
SIGNIFICANT
UNOBSERVABLE
INPUTS
FORWARD PRICE
RANGE
(THOUSANDS, EXCEPT FORWARD PRICE RANGE)
ASSETS
LIABILITIES
 
 
LOW
HIGH
FTRs at Mar. 31, 2020
$1,779
$683
RTO auction pricing
FTR price - per MWh
$(1.40)
$2.93
FTRs at Dec. 31, 2019
$6,822
$1,044
RTO auction pricing
FTR price -
per MWh
$(2.57)
$2.86
Cleco Power
 
 
 
 
 
FAIR VALUE
VALUATION
TECHNIQUE
SIGNIFICANT
UNOBSERVABLE
INPUTS
FORWARD PRICE
RANGE
(THOUSANDS, EXCEPT FORWARD PRICE RANGE)
ASSETS
LIABILITIES
 
 
LOW
HIGH
FTRs at Mar. 31, 2020
$1,673
$524
RTO auction pricing
FTR price -
per MWh
$(1.40)
$2.93
FTRs at Dec. 31, 2019
$6,311
$586
RTO auction
pricing
FTR price -
per MWh
$(2.04)
$2.86
Cleco utilizes different valuation techniques for fair value calculations. In order to measure the fair value for Level 1 assets and liabilities, Cleco obtains the closing price from published indices in active markets for the various instruments and multiplies this price by the appropriate number of instruments held. Level 2 fair values are determined by obtaining the closing price of similar assets and liabilities from published indices in active markets. Institutional money market funds assets are discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return. Level 3 fair values occur in situations in which there is little, if any, market activity for the asset or liability at the measurement date and prices are not observable. Cleco has consistently applied the Level 2 and Level 3 fair value techniques from fiscal period to fiscal period. Significant increases or decreases in any of those inputs in isolation would result in a significantly different fair value measurement. The assets and liabilities reported at fair value are grouped into classes based on the underlying nature and risks associated with the individual asset or liability.
At March 31, 2020, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents and restricted cash equivalents. The following tables present the institutional money market funds in cash and cash equivalents and restricted cash and cash equivalents as recorded on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020, and December 31, 2019:
Cleco
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Cash and cash equivalents
$338,611
$103,409
Current restricted cash and cash equivalents
$4,054
$11,100
Non-current restricted cash and cash equivalents
$9,883
$15,134
Cleco Power
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Cash and cash equivalents
$184,911
$49,509
Current restricted cash and cash equivalents
$4,054
$11,100
Non-current restricted cash and cash equivalents
$9,041
$14,294
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If the money market funds failed to perform under the terms of the investments, Cleco and Cleco Power would be exposed to a loss of the invested amounts. Collateral on these types of investments is not required by either Cleco or Cleco Power. The Level 2 institutional money market funds asset consists of a single class. In order to capture interest income and minimize risk, cash is invested in money market funds that invest primarily in short-term securities issued by the U.S. Treasury to maintain liquidity and achieve the goal of a net asset value of a dollar. The risks associated with this class are counterparty risk of the fund manager and risk of price volatility associated with the underlying securities of the fund.
Other commodity derivatives include fixed price physical forwards and swap transactions. These contracts contain counterparty credit risk because they are transacted directly with a counterparty and are not cleared on an exchange. With respect to any open trading contracts that Cleco has entered into or may enter into in the future, Cleco may be required to provide credit support or pay liquidated damages under such contracts. The amount of credit support that Cleco may be required to provide at any point in the future is dependent on the amount of the initial contract, changes in the market price, changes in open contracts, and changes in the amounts counterparties owe to Cleco. Changes in any of these factors could cause the amount of requested credit support to increase or decrease. These other commodity derivatives are recorded at fair value and categorized as Level 2 because pricing is indexed to other contracts.
Cleco Power and Cleco Cajun’s FTRs were priced using MISO’s monthly auction prices. Forward seasonal periods are not included in every monthly auction; therefore, the average of the most recent seasonal auction prices is used for monthly valuation. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from MISO auctions, which occur monthly in the Multi-Period Monthly Auction.
During the three months ended March 31, 2020, and the year ended December 31, 2019, Cleco did not experience any transfers between levels within the fair value hierarchy.
Commodity Contracts
The following tables present the fair values of derivative instruments and their respective line items as recorded on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020, and December 31, 2019:
Cleco
 
 
 
 
DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)
BALANCE SHEET LINE ITEM
AT MAR. 31, 2020
AT DEC. 31, 2019
Commodity-related contracts
 
 
 
FTRs
 
 
 
Current
Energy risk management assets
$1,779
$6,822
Current
Energy risk management liabilities
(683)
(1,044)
Other commodity derivatives
 
 
 
Current
Energy risk management assets
213
201
Current
Energy risk management liabilities
(9,014)
(3,069)
Non-current
Other deferred credits
(3,480)
(2,304)
Commodity-related contracts, net
 
$(11,185)
$606
Cleco Power
 
 
 
 
DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS
(THOUSANDS)
BALANCE SHEET LINE ITEM
AT MAR. 31, 2020
AT DEC. 31, 2019
Commodity-related contracts
 
 
 
FTRs
 
 
 
Current
Energy risk management assets
$1,673
$6,311
Current
Energy risk management liabilities
(524)
(586)
Commodity-related contracts, net
 
$1,149
$5,725
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The following tables present the effect of derivatives not designated as hedging instruments on Cleco and Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2020, and 2019:
Cleco
 
 
 
AMOUNT OF GAIN(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES
 
 
FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
INCOME STATEMENT LINE ITEM
2020
2019
Commodity-related contracts
 
 
 
FTRs(1)
Electric operations
$1,396
$5,209
FTRs(1)
Purchased power
(381)
(3,324)
Other commodity derivatives
Fuel used for electric generation
(7,108)
Total
 
$(6,093)
$1,885
(1)
For the three months ended March 31, 2020, unrealized losses associated with FTRs for Cleco Power of $1.3 million were reported through Accumulated deferred fuel on the balance sheet. For the three months ended March 31, 2019, unrealized losses associated with FTRs for Cleco Power of $2.9 million were reported through Accumulated deferred fuel on the balance sheet.
Cleco Power
 
 
 
 
AMOUNT OF GAIN(LOSS) RECOGNIZED IN INCOME ON DERIVATIVES
 
 
FOR THE THREE MONTHS ENDED MAR. 31,
(THOUSANDS)
INCOME STATEMENT LINE ITEM
2020
2019
Commodity-related contracts
 
 
 
FTRs(1)
��
Electric operations
$1,396
$5,206
FTRs(1)
Purchased power
(751)
(1,983)
Total
 
$645
$3,223
(1)
For the three months ended March 31, 2020, unrealized losses associated with FTRs of $1.3 million were reported through Accumulated deferred fuel on the balance sheet. For the three months ended March 31, 2019, unrealized losses associated with FTRs of $2.9 million were reported through Accumulated deferred fuel on the balance sheet.
The total volume of FTRs that Cleco Power had outstanding at March 31, 2020, and December 31, 2019, was 3.4 million MWh and 9.2 million MWh, respectively. The total volume of FTRs that Cleco had outstanding at March 31, 2020, and December 31, 2019, was 5.4 million MWh and 14.6 million MWh, respectively. The total volume of other commodity derivatives Cleco had outstanding at March 31, 2020, and December 31, 2019, was 54.8 million MMBtus and 58.5 million MMBtus, respectively.
Note 8 — Debt
On March 2, 2020, Cleco Power made the final $11.1 million principal payment and completed the repayment in full of its Cleco Katrina/Rita storm recovery bonds issued in March 2008.
On May 1, 2020, Cleco Power repriced at a mandatory tender date its $50.0 million 2008 series A GO Zone bonds and entered into a new interest rate period with a mandatory tender date of May 1, 2025. The interest rate for the new interest rate period is fixed at 2.50% per annum.
At March 31, 2020, Cleco Holdings had $88.0 million of borrowings outstanding under its $175.0 million credit facility at an all-in interest rate of 2.50%. The borrowing costs under the facility are equal to LIBOR plus 1.75% or ABR plus 0.75%, plus commitment fees of 0.275%.
At March 31, 2020, Cleco Power had $150.0 million of borrowings outstanding under its $300.0 million credit facility at an all-in interest rate of 1.875%. The borrowing costs under the facility are equal to LIBOR plus 1.125% or ABR plus 0.125%, plus commitment fees of 0.125%.
Note 9 — Pension Plan and Employee Benefits
Pension Plan and Other Benefits Plan
Employees hired before August 1, 2007, are covered by a non-contributory, defined benefit pension plan. In September 2019, Cleco made a $12.3 million discretionary contribution to the pension plan. Based on updated
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funding assumptions at December 31, 2019, management estimates that $66.5 million in pension contributions will be required through 2024. Cleco expects to make a $15.5 million minimum required contribution to the pension plan in 2020.
Cleco Power is the plan sponsor and Support Group is the plan administrator. The plan was amended on February 4, 2019, to include certain former NRG Energy employees who are now Cleco Cajun employees. The Cleco Cajun employees are eligible to participate as a cash balance participant and are credited with all service that was credited to them under the NRG Pension Plan as of February 4, 2019. Benefits under the plan amendment reflect an employee’s years of service, age at retirement, and accrued benefit at retirement.
Cleco’s retirees may be eligible to receive Other Benefits. Dependents of Cleco’s retirees may also be eligible to receive Other Benefits with the exception of life insurance benefits.
The non-service components of net periodic pension and Other Benefits cost are included in Other income (expense), net within Cleco and Cleco Power’s Condensed Consolidated Statements of Income. The components of net periodic pension and Other Benefits cost for the three months ended March 31, 2020, and 2019 were as follows:
 
PENSION BENEFITS
OTHER BENEFITS
 
FOR THE THREE
MONTHS ENDED MAR. 31,
FOR THE THREE
MONTHS ENDED MAR. 31,
(THOUSANDS)
2020
2019
2020
2019
Components of periodic benefit costs
 
 
 
 
Service cost
$2,328
$2,067
$508
$288
Interest cost
5,130
5,650
410
400
Expected return on plan assets
(6,245)
(6,622)
Amortizations
 
 
 
 
Prior period service credit
(15)
(18)
Net loss (gain)
3,672
1,875
339
(45)
Net periodic benefit cost
$4,870
$2,952
$1,257
$643
Because Cleco Power is the pension plan sponsor and the related trust holds the assets, the net unfunded status of the pension plan is reflected at Cleco Power. The liability of Cleco’s other subsidiaries is transferred with a like amount of assets to Cleco Power monthly. The expense of the pension plan related to Cleco’s other subsidiaries for the three months ended March 31, 2020, was $0.4 million. The expense of the pension plan related to Cleco’s other subsidiaries for the three months ended March 31, 2019, was $0.5 million.
Cleco Holdings is the plan sponsor for the other benefit plans. There are no assets set aside in a trust, and the liabilities are reported on the individual subsidiaries’ financial statements. The expense related to other benefits reflected in Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2020, was $1.2 million. The expense related to other benefits reflected in Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2019, was $0.7 million. The current and non-current portions of the Other Benefits liability for Cleco and Cleco Power at March 31, 2020, and December 31, 2019, were as follows:
Cleco
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Current
$4,401
$4,401
Non-current
$48,175
$48,321
Cleco Power
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Current
$3,815
$3,815
Non-current
$41,994
$42,080
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SERP
Certain Cleco officers are covered by SERP. Cleco does not fund the SERP liability, but instead pays for current benefits out of the general funds available. Cleco Power has formed a rabbi trust. The life insurance policies issued on SERP participants designate the rabbi trust as the beneficiary. Market conditions could have a significant impact on the cash surrender value of the life insurance policies. Proceeds from the life insurance policies are expected to be used to pay the SERP participants’ death benefits, as well as future SERP payments. However, because SERP is a non-qualified plan, the assets of the trust could be used to satisfy general creditors of Cleco Power in the event of insolvency. All SERP benefits are paid out of the general cash available of the respective companies that employed the officer. Cleco Power is the plan sponsor and Support Group is the plan administrator.
The non-service components of net periodic benefit cost related to SERP are included in Other income (expense), net within Cleco and Cleco Power’s Condensed Consolidated Statements of Income. The components of the net periodic benefit cost related to SERP for the three months ended March 31, 2020, and 2019 were as follows:
 
FOR THE THREE MONTHS
ENDED MAR. 31,
(THOUSANDS)
2020
2019
Components of periodic benefit costs
 
 
Service cost
$95
$113
Interest cost
733
825
Amortizations
 
 
Prior period service credit
(40)
(35)
Net loss
757
392
Net periodic benefit cost
$1,545
$1,295
The expense related to SERP reflected on Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2020, was $0.2 million. The expense related to SERP reflected on Cleco Power’s Condensed Consolidated Statements of Income for the three months ended March 31, 2019, was $0.3 million.
Liabilities relating to SERP are reported on the individual subsidiaries’ financial statements. The current and non-current portions of the SERP liability for Cleco and Cleco Power at March 31, 2020, and December 31, 2019, were as follows:
Cleco
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Current
$4,599
$4,599
Non-current
$84,219
$84,529
Cleco Power
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Current
$760
$760
Non-current
$13,863
$13,964
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401(k) Plan
Cleco’s 401(k) Plan is intended to provide active, eligible employees with voluntary, long-term savings and investment opportunities. The 401(k) Plan is a defined contribution plan and is subject to the applicable provisions of the Employee Retirement Income Security Act of 1974. In accordance with the 401(k) Plan, employer contributions are made in the form of cash. Cash contributions are invested in proportion to the participant’s voluntary contribution investment choices. Participation in the Plan is voluntary, and active Cleco employees are eligible to participate. Cleco’s 401(k) Plan was amended upon the close of the Cleco Cajun Transaction to include Cleco Cajun employees. Cleco’s 401(k) Plan expense for the three months ended March 31, 2020, and 2019 was as follows:
 
FOR THE THREE MONTHS
ENDED MAR. 31,
(THOUSANDS)
2020
2019
401(k) Plan expense
$3,256
$2,267
Cleco Power is the plan sponsor for the 401(k) Plan. The expense of the 401(k) Plan related to Cleco’s other subsidiaries for the three months ended March 31, 2020, and 2019 was as follows:
 
FOR THE THREE MONTHS
ENDED MAR. 31,
(THOUSANDS)
2020
2019
401(k) Plan expense
$1,662
$930
Note 10 — Income Taxes
Effective Tax Rates
The following tables summarize the effective income tax rates for Cleco and Cleco Power for the three months ended March 31, 2020, and 2019:
Cleco
 
 
 
FOR THE THREE MONTHS
ENDED MAR. 31,
 
2020
2019
Effective tax rate
19.8%
22.6%
Cleco Power
 
 
 
FOR THE THREE MONTHS
ENDED MAR. 31,
 
2020
2019
Effective tax rate
22.0%
23.0%
For the three months ended March 31, 2020, and 2019, the effective income tax rates for both Cleco and Cleco Power were different than the federal statutory rate primarily due to permanent tax differences; the flowthrough of tax benefits, including AFUDC equity; and state tax expense.
Net Operating Loss
For the 2019 tax year, Cleco created approximately $551.4 million and $82.6 million of federal and state net operating losses, respectively, primarily due to the Cleco Cajun Transaction.
The federal net operating loss may be carried forward indefinitely, and state net operating loss carryforwards will begin to expire in 2039.
Cleco considers it more likely than not that these income tax losses will be utilized to reduce future income tax payments and utilize the entire net operating loss carryforward within the statutory deadlines.
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Uncertain Tax Positions
Cleco classifies all interest related to uncertain tax positions as a component of interest payable and interest expense. At March 31, 2020, and December 31, 2019, Cleco and Cleco Power had no liability for uncertain tax positions or interest payable related to uncertain tax positions. Cleco estimates that it is reasonably possible that the balance of unrecognized tax benefits as of March 31, 2020, for Cleco and Cleco Power would be unchanged in the next 12 months. The settlement of open tax years could involve the payment of additional taxes, and/or the recognition of tax benefits, which may have an effect on Cleco’s effective tax rate.
Income Tax Audits
Cleco participates in the IRS’s Compliance Assurance Process in which financial results are examined and agreed upon prior to filing the federal consolidated tax return. While the statute of limitations remains open for tax years 2016, 2017, and 2018, management believes the likelihood of further examination by the IRS is remote.
The state income tax years 2016, 2017, and 2018 remain subject to examination by the Louisiana Department of Revenue.
Cleco classifies income tax penalties as a component of other expense. For the three months ended March 31, 2020, and 2019, no penalties were recognized.
Coronavirus Aid, Relief and Economic Security (CARES Act)
On March 27, 2020, the CARES Act was enacted and signed into law in response to the COVID-19 pandemic. Among other provisions, the CARES Act includes modifications on the limitations of business interest for the 2019 and 2020 tax years. The modifications increase the allowable business interest deduction from 30% to 50% of adjusted taxable income. The modification increased Cleco’s allowable interest expense deduction and, as a result, decreased taxable income, creating larger net operating loss carryforwards for the tax year ended December 31, 2019. As a result of the CARES Act, Cleco does not expect any disallowed interest for the 2019 and 2020 tax years.
Note 11 — Disclosures about Segments
Cleco’s reportable segments are based on its method of internal reporting, which disaggregates business units by its first-tier subsidiary. Cleco’s reportable segments are Cleco Power and Cleco Cajun.
Each reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco’s CEO with discrete financial information and, at least quarterly, present discrete financial information to Cleco and Cleco Power’s Boards of Managers. The reportable segment prepares budgets that are presented to and approved by Cleco and Cleco Power’s Boards of Managers. The column shown as Other in the following tables includes the holding company, a shared services subsidiary, and an investment subsidiary. Upon the completion of the Cleco Cajun Transaction on February 4, 2019, Cleco Cajun became a reportable segment. For more information on the transaction, see Note 2 — “Business Combinations.” There are no other changes to Cleco’s existing reportable segments.
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The financial results in the following tables are presented on an accrual basis. Management evaluates the performance of its segments and allocates resources to them based on segment profit and the requirements to implement strategic initiatives and projects to meet current business objectives. Material intercompany transactions occur on a regular basis. These intercompany transactions relate primarily to joint and common administrative support services as well as transmission services provided by Cleco Power to Cleco Cajun.
Segment Information For The Three Months Ended Mar. 31,
 
 
 
 
 
2020 (THOUSANDS)
CLECO
POWER
CLECO
CAJUN
OTHER
ELIMINATIONS
CONSOLIDATED
Revenue
 
 
 
 
 
Electric operations
$224,430
$89,147
$(2,420)
$
$311,157
Other operations
15,764
30,961
1
(1,818)
44,908
Affiliate revenue
1,106
161
29,278
(30,545)
Electric customer credits
(8,340)
(153)
(8,493)
Operating revenue, net
$232,960
$120,116
$26,859
$(32,363)
$347,572
Depreciation and amortization
$43,677
$10,103
$2,094
$(1)
$55,873
Interest income
$954
$155
$100
$(52)
$1,157
Interest charges
$18,581
$10
$16,610
$(52)
$35,149
Federal and state income tax expense (benefit)
$3,338
$6,421
$(8,197)
$
$1,562
Net income (loss)
$11,831
$19,535
$(25,039)
$1
$6,328
Additions to property, plant, and equipment
$61,477
$3,341
$806
$
$65,624
Equity investment in investees
$17,072
$
$
$
$17,072
Goodwill
$1,490,797
$
$
$
$1,490,797
Total segment assets
$6,098,446
$1,020,099
$616,068
$(58,418)
$7,676,195
2019 (THOUSANDS)
CLECO
POWER
CLECO
CAJUN
OTHER
ELIMINATIONS
CONSOLIDATED
Revenue
 
 
 
 
 
Electric operations
$257,175
$58,194
$(2,420)
$
$312,949
Other operations
19,430
19,965
2
39,397
Affiliate revenue
300
26,535
(26,835)
Electric customer credits
(8,160)
(8,160)
Operating revenue, net
$268,745
$78,159
$24,117
$(26,835)
$344,186
Depreciation and amortization
$42,377
$5,410
$2,069
$
$49,856
Interest income
$994
$254
$417
$(174)
$1,491
Interest charges
$17,145
$
$17,028
$(174)
$33,999
Federal and state income tax expense (benefit)
$7,998
$3,529
$(5,540)
$(1)
$5,986
Net income (loss)
$26,712
$11,056
$(17,210)
$(1)
$20,557
Additions to property, plant, and equipment
$81,040
$1,530
$1,109
$
$83,679
Equity investment in investees(1)
$17,072
$
$
$
$17,072
Goodwill(1)
$1,490,797
$
$
$
$1,490,797
Total segment assets(1)
$5,967,327
$1,011,591
$546,096
$(48,716)
$7,476,298
(1)
Balances as of December 31, 2019
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Note 12 — Regulation and Rates
At March 31, 2020, Provision for rate refund on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets consisted primarily of $19.7 million for the estimated refund for the tax-related benefits from the TCJA, $3.5 million for the estimated refund related to the FERC audit, $2.2 million for the cost of service savings refunds, and $1.0 million for the change in transmission ROE. For more information about the FERC audit, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — FERC Audit.”
Transmission ROE
Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. As of March 31, 2020, Cleco Power had $1.0 million accrued for the change in ROE. For more information on the ROE complaints, see Note 14 — “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Litigation — Transmission ROE.”
FRP
Cleco Power’s annual retail earnings are subject to an FRP that was approved by the LPSC in June 2014. Under the terms of Cleco Power’s current FRP, Cleco Power is allowed to earn a target ROE of 10.0%, while providing the opportunity to earn up to 10.9%. Additionally, 60.0% of retail earnings between 10.9% and 11.75%, and all retail earnings over 11.75%, are required to be refunded to customers. The amount of credits due to customers, if any, is determined by Cleco Power and the LPSC, annually. Credits are typically included on customers’ bills the following summer, but the amount and timing of the refunds are ultimately subject to LPSC approval. On June 28, 2019, Cleco Power filed an application with the LPSC for a new FRP, with anticipated new rates being effective July 1, 2020. Cleco Power has responded to several sets of data requests relating to the new FRP.
Cleco Power must file annual monitoring reports no later than October 31 for the 12-month period ending June 30. In January 2020, Cleco Power reached an agreement with the LPSC Staff regarding the treatment and realignment of SSR revenue between base and fuel revenue that resulted in $2.3 million of refunds for the 2018 monitoring report and confirmed no refunds for the 2017 monitoring report. The settlement also applies to treatment of SSR revenues for the 2019 monitoring report. The 2017 monitoring report was approved by the LPSC Staff on February 19, 2020. Cleco Power refunded the $2.3 million for the 2018 monitoring report in March 2020 as agreed to in the settlement of the 2017 monitoring report.
On April 30, 2020, the LPSC filed the uncontested Joint Report and Draft Order on Cleco Power’s FRP for the 12 months ended June 30, 2018. The conclusions were an earnings-related refund of $2.3 million, which was refunded on March 2020 bills, and no adjustments to rider FRP. Cleco Power expects approval on the 2018 monitoring report in the second quarter of 2020. Cleco Power has also responded to data requests relating to the 2019 FRP monitoring report.
Cleco Power’s monitoring reports also included a $1.2 million annual cost of service savings as a result of the 2016 Merger Commitments. The cost of service savings are not subject to the target ROE or any sharing mechanism. The cost of service savings are refunded annually in September and will continue until Cleco Power’s next FRP is in effect, which is expected in July 2020. At March 31, 2020, Cleco Power had $2.2 million accrued for the estimated cost of service savings refunds.
TCJA
The provisions of the TCJA reduced the top federal statutory corporate income tax rate from 35% to 21%. As a result of the tax rate reduction, on January 1, 2018, Cleco Power began accruing an estimated reserve for the reduction in the federal statutory corporate income tax rate. In February 2018, the LPSC directed utilities, including Cleco Power, to provide considerations of the appropriate manner to flow through to ratepayers the benefits of the reduction in corporate income taxes as a result of the TCJA. In July 2019, the LPSC approved Cleco Power’s rate refund of $79.2 million, plus interest, for the reduction in the statutory federal tax rate for the period from January 2018 to June 2020. The refund is being credited to customers over 12 months beginning August 1, 2019. At March 31, 2020, Cleco Power had $19.7 million accrued for the estimated federal tax-related benefits from the TCJA and $1.6 million accrued in related interest.
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Also, in July 2019, the LPSC approved Cleco Power’s motion to address the rate redesign and the regulatory liability for excess ADIT, resulting from the enactment of the TCJA, in Cleco Power’s application for its next FRP, which was filed on June 28, 2019.
SSR
In September 2016, Cleco Power filed an Attachment Y with MISO requesting retirement of Teche Unit 3 effective April 1, 2017. MISO conducted a study which determined the proposed retirement of Teche Unit 3 would result in violations of specific applicable reliability standards for which no mitigation is available. As a result, MISO designated Teche Unit 3 as an SSR unit until such time that an appropriate alternative solution could be implemented to mitigate reliability issues. One mitigating factor identified was Cleco Power’s Terrebonne to Bayou Vista Transmission project, which was completed in April 2019. Cleco Power received a termination notice, effective April 30, 2019, and filed paperwork to withdraw the filed Attachment Y. While operating as an SSR unit, Cleco Power received monthly payments that included recovery of expenses, including capital expenditures, related to the operations of Teche Unit 3. Additionally, MISO allocated SSR costs to the load serving entities that required the operation of the SSR unit, including Cleco Power. These payments and cost allocations were finalized as part of a MISO SSR settlement approved in December 2018. Cleco Power operated Teche Unit 3 as an SSR unit from April 2017 until April 2019.
Cleco Power expects Teche Unit 3 to be available to run until the estimated 2021 in-service date of the Bayou Vista to Segura Transmission project, at which time Cleco Power does not expect to offer the unit into MISO, barring any grid or customer reliability issues or other similar reasons. At March 31, 2020, Cleco Power had $6.1 million accrued for the net capital refund for capital expenditures paid for by third parties while operating under the SSR agreement. As part of the settlement, one of the load serving entities agreed to reimburse Cleco Power for their portion of the capital refund. Management is unable to determine the timing of the capital refund.
Note 13 — Variable Interest Entities
Cleco and Cleco Power apply the equity method of accounting to report the investment in Oxbow in the consolidated financial statements. Under the equity method, the assets and liabilities of this entity are reported as Equity investment in investee on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets. The revenue and expenses (excluding income taxes) of this entity are netted and reported as equity income or loss from investees on Cleco and Cleco Power’s Condensed Consolidated Statements of Income.
Oxbow is owned 50% by Cleco Power and 50% by SWEPCO. Cleco Power is not the primary beneficiary because it shares the power to control Oxbow’s significant activities with SWEPCO. Cleco Power’s current assessment of its maximum exposure to loss related to Oxbow at March 31, 2020, consisted of its equity investment of $17.1 million.
The following table presents the components of Cleco Power’s equity investment in Oxbow:
INCEPTION TO DATE (THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Purchase price
$12,873
$12,873
Cash contributions
6,399
6,399
Dividends
(2,200)
(2,200)
Total equity investment in investee
$17,072
$17,072
The following table compares the carrying amount of Oxbow’s assets and liabilities with Cleco Power’s maximum exposure to loss related to its investment in Oxbow:
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Oxbow’s net assets/liabilities
$34,145
$34,145
Cleco Power’s 50% equity
$17,072
$17,072
Cleco Power’s maximum exposure to loss
$17,072
$17,072
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The following table contains summarized financial information for Oxbow:
 
FOR THE THREE MONTHS
ENDED MAR. 31,
(THOUSANDS)
2020
2019
Operating revenue
$1,882
$1,958
Operating expenses
1,882
1,958
Income before taxes
$
$
DHLC mines lignite reserves at Oxbow through the Amended Lignite Mining Agreement. The lignite reserves are intended to be used to provide fuel to the Dolet Hills Power Station. For more information on DHLC and the Oxbow mine, see Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees — Risks and Uncertainties.”
Oxbow has no third-party agreements, guarantees, or other third-party commitments that contain obligations affecting Cleco Power’s investment in Oxbow.
Note 14 — Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees
Litigation
2016 Merger
In connection with the 2016 Merger, four actions were filed in the Ninth Judicial District Court for Rapides Parish, Louisiana and three actions were filed in the Civil District Court for Orleans Parish, Louisiana. The petitions in each action generally alleged, among other things, that the members of Cleco Corporation’s Board of Directors breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process, agreeing to the 2016 Merger at a price that allegedly undervalued Cleco, and failing to disclose material information about the 2016 Merger. The petitions also alleged that Como 1, Cleco Corporation, Merger Sub, and, in some cases, certain of the investors in Como 1 either aided and abetted or entered into a civil conspiracy to advance those supposed breaches of duty. The petitions sought various remedies, including monetary damages, which includes attorneys’ fees and expenses.
The four actions filed in the Ninth Judicial District Court for Rapides Parish are captioned as follows:
Braunstein v. Cleco Corporation, No. 251,383B (filed October 27, 2014),
Moore v. Macquarie Infrastructure and Real Assets, No. 251,417C (filed October 30, 2014),
Trahan v. Williamson, No. 251,456C (filed November 5, 2014), and
L’Herisson v. Macquarie Infrastructure and Real Assets, No. 251,515F (filed November 14, 2014).
In November 2014, the plaintiff in the Braunstein action moved for a dismissal of the action without prejudice, and that motion was granted in November 2014. In December 2014, the Court consolidated the remaining three actions and appointed interim co-lead counsel, and dismissed the investors in Cleco Partners as defendants, per agreement of the parties. Also, in December 2014, the plaintiffs in the consolidated action filed a Consolidated Amended Verified Derivative and Class Action Petition for Damages and Preliminary and Permanent Injunction.
The three actions filed in the Civil District Court for Orleans Parish were captioned as follows:
Butler v. Cleco Corporation, No. 2014-10776 (filed November 7, 2014),
Creative Life Services, Inc. v. Cleco Corporation, No. 2014-11098 (filed November 19, 2014), and
Cashen v. Cleco Corporation, No. 2014-11236 (filed November 21, 2014).
In December 2014, the directors and Cleco filed declinatory exceptions in each action on the basis that each action was improperly brought in Orleans Parish and should either be transferred to the Ninth Judicial District Court for Rapides Parish or dismissed. Also, in December 2014, the plaintiffs in each action jointly filed a motion to consolidate the three actions pending in Orleans Parish and to appoint interim co-lead plaintiffs and co-lead counsel. In January 2015, the Court in the Creative Life Services case sustained the defendants’ declinatory exceptions and dismissed the case so that it could be transferred to the Ninth Judicial District Court for Rapides Parish. In February 2015, the plaintiffs in Butler and Cashen also consented to the dismissal of their
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cases from Orleans Parish so they could be transferred to the Ninth Judicial District Court for Rapides Parish. By operation of the December 2014 order of the Ninth Judicial District Court for Rapides Parish, the Butler, Cashen, and Creative Life Services actions were consolidated into the actions pending in Rapides Parish.
In February 2015, the Ninth Judicial District Court for Rapides Parish held a hearing on a motion for preliminary injunction filed by plaintiffs in the consolidated action seeking to enjoin the shareholder vote for approval of the Merger Agreement. The District Court heard and denied the plaintiffs’ motion. In June 2015, the plaintiffs filed their Second Consolidated Amended Verified Derivative and Class Action Petition. Cleco filed exceptions seeking dismissal of the second amended petition in July 2015. The LPSC voted to approve the 2016 Merger before the Court could consider the plaintiffs’ peremptory exceptions.
In March 2016 and May 2016, the plaintiffs filed their Third Consolidated Amended Verified Derivative Petition for Damages and Preliminary and Permanent Injunction and their Fourth Verified Consolidated Amended Class Action Petition, respectively. The fourth amended petition, which remains the operative petition and was filed after the 2016 Merger closed, eliminated the request for preliminary and permanent injunction and also named an additional executive officer as a defendant. The defendants filed exceptions seeking dismissal of the fourth amended Petition. In September 2016, and the District Court granted the exceptions of no cause of action and no right of action and dismissed all claims asserted by the former shareholders. The plaintiffs appealed the District Court’s ruling to the Louisiana Third Circuit Court of Appeal. In December 2017, the Third Circuit Court of Appeal issued an order reversing and remanding the case to the District Court for further proceedings. In January 2018, Cleco filed a writ with the Louisiana Supreme Court seeking review of the Third Circuit Court of Appeal’s decision. The writ was denied in March 2018 and the parties are engaged in discovery in the District Court. In November 2018, Cleco filed renewed exceptions of no cause of action and res judicata, seeking to dismiss all claims. On December 21, 2018, the court dismissed Cleco Partners and Cleco Holdings as defendants per the agreement of the parties, leaving as the only remaining defendants certain former executive officers and independent directors. The District Court denied the defendants’ exceptions on January 14, 2019. A hearing on the plaintiffs’ motion for certification of a class was scheduled for August 26, 2019; however, prior to the hearing, the parties reached an agreement to certify a limited class. On September 7, 2019, the District Court certified a class limited to shareholders who voted against, abstained from voting, or did not vote on the 2016 Merger. Cleco believes that the allegations of the petitions in each action are without merit and that it has substantial meritorious defenses to the claims set forth in each of the petitions.
Gulf Coast Spinning
In September 2015, a potential customer sued Cleco for failure to fully perform an alleged verbal agreement to lend or otherwise fund its startup costs to the extent of $6.5 million. Gulf Coast Spinning Company, LLC (Gulf Coast), the primary plaintiff, alleges that Cleco promised to assist it in raising approximately $60.0 million, which Gulf Coast needed to construct a cotton spinning facility near Bunkie, Louisiana. According to the petition filed by Gulf Coast in the 12th Judicial District Court for Avoyelles Parish, Louisiana (the “District Court”), Cleco made such promises of funding assistance in order to cultivate a new industrial electric customer which would increase its revenues under a power supply agreement that it executed with Gulf Coast. Gulf Coast seeks unspecified damages arising from its inability to raise sufficient funds to complete the project, including lost profits.
Cleco filed an Exception of No Cause of Action arguing that the case should be dismissed. The District Court denied Cleco’s exception in December 2015, after considering briefs and arguments. In January 2016, Cleco appealed the District Court’s denial of its exception by filing with the Third Circuit Court of Appeal. In June 2016, the Third Circuit Court of Appeal denied the request to have the case dismissed. In July 2016, Cleco filed a writ to the Louisiana Supreme Court seeking a review of the District Court’s denial of Cleco’s exception. In November 2016, the Louisiana Supreme Court denied Cleco’s writ application.
In February 2016, the parties agreed to a stay of all proceedings pending discussions concerning settlement. In May 2016, the District Court lifted the stay at the request of Gulf Coast. The parties are currently participating in discovery. Cleco believes the allegations of the petition are contradicted by the written documents executed by Gulf Coast, are otherwise without merit, and that it has substantial meritorious defenses to the claims alleged by Gulf Coast.
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Sabine River Flood
In March 2017, Cleco was served with a summons in Perry Bonin, Ace Chandler, and Michael Manuel, et al v. Sabine River Authority of Texas and Sabine River Authority of Louisiana, No. B-160173-C. The action was filed in the 163rd Judicial District Court for Orange County, Texas, and relates to flooding that occurred in Texas and Louisiana in March 2016. The plaintiffs have alleged that the flooding was the result of the release of water from the Toledo Bend spillway gates into the Sabine River. While the plaintiffs have made numerous allegations, they have specifically alleged that Cleco Power, included as one of several companies and governmental bodies, failed to repair one of the two hydroelectric generators at the Toledo Bend Dam, which in turn contributed to the flooding. Cleco Power does not operate the hydroelectric generator.
The suit was removed to federal court in Texas. The new federal case is Perry Bonin, et al. v. Sabine River Authority of Texas et al., No. 17-cv-134, U.S. District Court for the Eastern District of Texas (Bonin Case). The plaintiffs moved to remand the case to state court, but the district court found that the case raises a substantial federal question and denied the motion to remand. Cleco Power, along with its co-defendants, filed a motion to dismiss on various grounds, primarily arguing that the plaintiffs’ claims are preempted because they infringe on FERC’s exclusive control of dam operations. The district court granted the motion to dismiss in part, declining to rule on some of the arguments raised by the defendants, and granted the plaintiffs leave to amend their complaint. The plaintiffs filed a Fifth Amended Complaint in March 2018. Cleco Power filed a new motion to dismiss the plaintiffs’ claims.
In March 2018, approximately 26 other individual plaintiffs filed a petition against Cleco Power and other defendants in Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. D180096-C. The action was filed in the 260th Judicial District Court for Orange County, Texas. The defendants removed the case to federal court in April 2018. The new federal case is Larry Addison, et al. v. Sabine River Authority of Texas, et al., No. 18-cv-153, U.S. District Court for the Eastern District of Texas. The allegations are essentially identical to those in the Bonin Case. Also, in April 2018, Cleco Power filed a motion to dismiss on the same grounds that previously were successful in the Bonin Case. In July 2018, the district court entered an order consolidating the Addison Case with the Bonin Case. Management believes that both cases, as they relate to Cleco Power, have no merit. In August 2018, the Judge entered an order requiring the plaintiffs to file a more definitive statement to clarify the plaintiffs’ claims. In response thereto, the plaintiffs filed a Sixth Amended Petition in September 2018. Cleco Power filed a response in October 2018. All claims were dismissed against Cleco Power by ruling of the Judge on March 18, 2019. The plaintiffs filed an appeal of the dismissal with the United States Court of Appeals for the Fifth Circuit. The case is fully briefed before the Fifth Circuit Court of Appeals, and an oral argument was scheduled for the week of March 30, 2020; however, oral arguments have been delayed due to impacts from the COVID-19 pandemic.
Dispute with Saulsbury Industries
In October 2018, Cleco Power sued Saulsbury Industries, Inc., the former general contractor for the St. Mary Clean Energy Center project, seeking damages for Saulsbury Industries, Inc.’s failure to complete the St. Mary Clean Energy Center project on time and for costs incurred by Cleco Power in hiring a replacement general contractor. The action was filed in the Ninth Judicial District Court for Rapides Parish, No. 263339. Saulsbury Industries, Inc. removed the case to the U.S. District Court for the Western District of Louisiana, on March 1, 2019.
In January 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC, in the U.S. District Court for the Western District of Louisiana. Saulsbury Industries, Inc. alleging that Cleco Power and Cabot Corporation caused delays in the St. Mary Clean Energy Center project, resulting in alleged impacts to Saulsbury Industries, Inc.’s direct and indirect costs. On June 5, 2019, Cleco Power and Cabot Corporation each filed separate motions to dismiss. On October 24, 2019, the District Court denied Cleco’s motion as premature and ruled that Saulsbury Industries, Inc. had six weeks to conduct discovery on specified jurisdictional issues. The current procedural posture of the Western District of Louisiana case reflects a recognition by Cleco Power and Saulsbury Industries, Inc. that subject matter jurisdiction has not been established in relation to Cleco Power and Saulsbury Industries, Inc. and that this action, insofar as it relates to Cleco Power and Saulsbury Industries, Inc., will not proceed in federal court.
On October 10, 2019, Cleco Power was served with a summons in Saulsbury Industries, Inc. v. Cabot Corporation and Cleco Power LLC in the 16th Judicial District Court for St. Mary Parish, No. 133910-A.
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Saulsbury Industries, Inc. asserted the same claim as the Western District Litigation and further asserts claims for payment on an open account. On December 9, 2019, Cleco moved to stay the case, arguing that the Rapides Parish suit should proceed. On February 14, 2020, the court granted Cleco’s motion, which stay order remains in place until lifted.
LPSC Audits
Fuel Audit
Generally, Cleco Power’s cost of fuel used for electric generation and the cost of purchased power are recovered through the LPSC-established FAC that enables Cleco Power to pass on to its customers substantially all such charges. Recovery of FAC costs is subject to periodic fuel audits by the LPSC. The LPSC FAC General Order issued in November 1997, in Docket No. U-21497 provides that an audit of FAC filings will be performed at least every other year. Cleco Power has FAC filings for January 2018 and thereafter that remain subject to audit. On April 21, 2020, Cleco Power received notice from the LPSC of its filing for Request For Proposals to hire outside consultants to perform the FAC audit for the period of January 2018 to December 2019. The total amount of fuel expense expected to be included in the audit is $565.8 million. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. Historically, the disallowances have not been material. If a disallowance of fuel cost is ordered resulting in a refund, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.
Environmental Audit
In 2009, the LPSC issued Docket No. U-29380 Subdocket A, which provides Cleco Power an EAC to recover from its customers certain costs of environmental compliance. The costs eligible for recovery are prudently incurred air emissions credits associated with complying with federal, state, and local air emission regulations that apply to the generation of electricity reduced by the sale of such allowances. Also eligible for recovery are variable emission mitigation costs, which are the costs of reagents such as ammonia and limestone that are a part of the fuel mix used to reduce air emissions, among other things. Cleco Power has EAC filings for January 2018 and thereafter that remain subject to audit. On March 11, 2020, Cleco Power received notice from the LPSC of its filing for Request For Proposals to hire outside consultants to perform the EAC audit for the period of January 2018 to December 2019. The total amount of environmental expense expected to be included in the audit is $26.2 million. Management is unable to predict or give a reasonable estimate of the possible range of the disallowance, if any, related to these filings. Historically, the disallowances have not been material. If a disallowance of environmental cost is ordered resulting in a refund to Cleco Power’s customers, any such refund could have a material adverse effect on the results of operations, financial condition, or cash flows of the Registrants.
Cleco Power incurs environmental compliance expenses for reagents associated with the compliance standards of Mercury and Air Toxics Standards (MATS). In June 2015, the U.S. Supreme Court remanded the MATS rule to the D.C. Circuit Court of Appeals. In December 2015, the D.C. Circuit Court of Appeals remanded the rule to the EPA; however, the D.C. Circuit Court of Appeals did not vacate this rule. In April 2016, the EPA released a final supplemental finding that, even considering costs, it is appropriate and necessary to regulate hazardous air pollutants. By the June 2016 deadline, six petitions were filed with the U.S. Court of Appeals for the D.C. Circuit Court of Appeals for review of the EPA’s findings. At the request of the EPA, in April 2017, the court issued an order holding the cases in abeyance pending the EPA’s review of its supplemental finding. These expenses are also eligible for recovery through Cleco Power’s EAC and are subject to periodic review by the LPSC.
FERC Audit
Generally, Cleco Power records wholesale transmission revenue through approved formula rates, Attachment O of the MISO tariff and certain grandfathered agreements. The calculation of the rate formulas, as well as FERC accounting and reporting requirements, are subject to periodic audits by FERC. In March 2018, the Division of Audits and Accounting, within the Office of Enforcement of FERC, initiated an audit of Cleco Power for the period of January 1, 2014, through June 30, 2019. On September 27, 2019, Cleco Power received the final audit report, which indicated 12 findings of noncompliance with a combination of FERC accounting and
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reporting requirements and computation of revenue requirements along with 59 recommendations associated with the audit period. Cleco Power submitted a plan for implementing the audit recommendations on October 28, 2019. Cleco Power also submitted the refund analysis on November 7, 2019, which resulted in an estimated refund of $3.5 million related to the FERC audit findings, pending final assessment by the FERC Division of Audits and Accounting. This amount was recorded in Provision for rate refund on Cleco and Cleco Power’s Condensed Consolidated Balance Sheets at March 31, 2020. Cleco Power anticipates this amount to be refunded to its wholesale transmission customers as a reduction in Attachment O and grandfathered agreement rates over 12 months beginning June 1, 2020.
Transmission ROE
Two complaints were filed with FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including Cleco, may collect under the MISO tariff. The complaints sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 6.68%.
The complaints covered the period December 2013 through May 2016. In June 2016, an administrative law judge issued an initial decision in the second rate case docket recommending a 9.70% base ROE. In September 2016, FERC issued a Final Order in response to the first complaint establishing a 10.32% ROE. However, on November 21, 2019, FERC voted to adopt a new methodology for evaluating base ROE for public utilities under the Federal Power Act. In addition, FERC set the MISO transmission owners’ region-wide base ROE at 9.88% for the refund period covered in the first complaint and going forward. The draft FERC order further found that complainants in the second complaint proceeding failed to show that the 9.88% base ROE was unjust and unreasonable and thus dismissed the second complaint. Cleco Power is unable to determine when a final FERC Order will be issued. As of March 31, 2020, Cleco Power had $1.0 million accrued for the change in the ROE.
In November 2014, the MISO transmission owners committee, of which Cleco is a member, filed a request with FERC for an incentive to increase the new ROE by 50 basis points for RTO participation as allowed by the MISO tariff. In January 2015, FERC granted the request. Beginning January 1, 2020, the collection of the adder is being included in MISO’s transmission rates for a total ROE of 10.38%.
South Central Generating
In 2017, Louisiana Generating received insurance settlement proceeds for costs incurred to resolve a lawsuit which was brought by the EPA and the LDEQ against Louisiana Generating related to Big Cajun II, Unit 3. Entergy Gulf States, as co-owner of Big Cajun II, Unit 3, is expected to be allocated a portion of the insurance settlement proceeds. Any amount allocated to Entergy Gulf States will be determined by ongoing litigation and negotiations. South Central Generating estimated this amount to be $10.0 million. As part of the Cleco Cajun Transaction, Cleco Cajun assumed the $10.0 million contingent liability and NRG Energy indemnified Cleco for losses associated with this litigation matter. As a result, Cleco also recorded a $10.0 million indemnification asset, which was included in the purchase price allocation.
Prior to the Cleco Cajun Transaction, South Central Generating was involved in various litigation matters, including environmental and contract proceedings, before various courts regarding matters arising out of the ordinary course of business. Management is unable to estimate any potential losses that Cleco Cajun may ultimately be responsible for with respect to any one of these matters. As part of the Cleco Cajun Transaction, NRG Energy indemnified Cleco for losses as of the closing date associated with matters that existed as of the closing date, including pending litigation.
Other
Cleco is involved in various litigation matters, including regulatory, environmental, and administrative proceedings before various courts, regulatory commissions, arbitrators, and governmental agencies regarding matters arising in the ordinary course of business. The liability Cleco may ultimately incur with respect to any one of these matters may be in excess of amounts currently accrued. Management regularly analyzes current information and, as of March 31, 2020, believes the probable and reasonably estimable liabilities based on the eventual disposition of these matters are $5.1 million and has accrued this amount.
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Off-Balance Sheet Commitments and Guarantees
Cleco Holdings and Cleco Power have entered into various off-balance sheet commitments, in the form of guarantees and standby letters of credit, in order to facilitate their activities and the activities of Cleco Holdings’ subsidiaries and equity investees (affiliates). Cleco Holdings and Cleco Power have also agreed to contractual terms that require the Registrants to pay third parties if certain triggering events occur. These contractual terms generally are defined as guarantees.
Cleco Holdings entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of credit assurance to the counterparty in the event Cleco’s affiliates do not fulfill certain contractual obligations. If Cleco Holdings had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.
The off-balance sheet commitments are not recognized on Cleco and Cleco Power’s Consolidated Balance Sheets because management has determined that Cleco and Cleco Power’s affiliates are able to perform the obligations under their contracts and that it is not probable that payments by Cleco or Cleco Power will be required.
Cleco Holdings provided guarantees and indemnities to Entergy Louisiana and Entergy Gulf States as a result of the sale of the Perryville generation facility in 2005. The remaining indemnifications relate to environmental matters that may have been present prior to closing. These remaining indemnifications have no time limitations. The maximum amount of the potential payment to Entergy Louisiana and Entergy Gulf States is $42.4 million. Management does not expect to be required to pay Entergy Louisiana and Entergy Gulf States under these guarantees.
On behalf of Acadia, Cleco Holdings provided guarantees and indemnifications as a result of the sales of Acadia Unit 1 to Cleco Power and Acadia Unit 2 to Entergy Louisiana in 2010 and 2011, respectively. The remaining indemnifications relate to the fundamental organizational structure of Acadia. These remaining indemnifications have no time limitations or maximum potential future payments. Management does not expect to be required to pay Cleco Power or Entergy Louisiana under these guarantees.
Cleco Holdings provided indemnifications to Cleco Power as a result of the transfer of Coughlin to Cleco Power in March 2014. Cleco Power also provided indemnifications to Cleco Holdings and Evangeline as a result of the transfer of Coughlin to Cleco Power. The maximum amount of the potential payment to Cleco Power, Cleco Holdings, and Evangeline for their respective indemnifications is $40.0 million, except for indemnifications relating to the fundamental organizational structure of each respective entity, of which the maximum amount is $400.0 million. Management does not expect to be required to make any payments under these indemnifications.
As part of the Amended Lignite Mining Agreement, Cleco Power and SWEPCO, joint owners of Dolet Hills Power Station, have agreed to pay the loan and lease principal obligations of the lignite miner, DHLC, when due if DHLC does not have sufficient funds or credit to pay. Any amounts paid on behalf of the miner would be credited by the lignite miner against future invoices for lignite delivered. The maximum projected payment by Cleco Power under this guarantee is estimated to be $83.0 million; however, the Amended Lignite Mining Agreement does not contain a cap. The projection is based on the forecasted loan and lease obligations to be incurred by DHLC, primarily for purchases of equipment. Cleco Power has the right to dispute the incurrence of loan and lease obligations through the review of the mining plan before the incurrence of such loan and lease obligations. In April 2020, Cleco Power and SWEPCO mutually agreed to not develop additional mining areas for future lignite extraction and subsequently provided notice to the LPSC of the intent to cease mining at the Dolet Hills and Oxbow mines by June 2020. The mine closure is subject to LPSC review and approval. The Amended Lignite Mining Agreement does not affect the amount the Registrants can borrow under their credit facilities. Currently, management does not expect to be required to pay DHLC under this guarantee.
At March 31, 2020, Cleco Holdings had a $34.5 million letter of credit to MISO pursuant to energy market requirements related to Cleco Cajun’s participation in MISO. The letter of credit automatically renews each year and has no impact on the Cleco Holdings’ credit facility.
Generally, neither Cleco Holdings nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations. There are no assets held as collateral for third parties that either Cleco Holdings or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees or indemnification obligations.
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Other Commitments
Cleco has accrued for liabilities related to third parties, employee medical benefits, and AROs.
Risks and Uncertainties
Cleco could be subject to possible adverse consequences if Cleco’s counterparties fail to perform their obligations or if Cleco or its affiliates are not in compliance with loan agreements or bond indentures.
Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows.
Changes in the regulatory environment or market forces could cause Cleco to determine its assets have suffered an other-than-temporary decline in value, whereby an impairment would be required and Cleco’s financial condition could be materially adversely affected.
Cleco Power and Cleco Cajun are participants in the MISO market. Energy prices in the MISO market are based on LMP, which includes a component directly related to congestion on the transmission system. Pricing zones with greater transmission congestion may have higher LMPs. Physical transmission constraints present in the MISO market could increase energy costs within pricing zones. Cleco Power and Cleco Cajun use FTRs to mitigate transmission congestion price risks. Changes to anticipated transmission paths may result in an unexpected increase in energy costs.
On March 1, 2019, Cleco Power began to operate Dolet Hills Power Station from June through September of each year; however, Dolet Hills Power Station will continue to be available to operate in other months, if needed. In January 2020, Cleco Power’s joint owner in Dolet Hills Power Station unilaterally entered into a settlement with the Arkansas Public Service Commission to seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. This settlement does not bind Cleco Power to agree to retire the Dolet Hills Power Station by 2026.
In April 2020, Cleco Power and SWEPCO mutually agreed to not develop additional mining areas for future lignite extraction and subsequently provided notice to the LPSC of the intent to cease mining at the Dolet Hills and Oxbow mines by June 2020, subject to LPSC review and approval. Early closure of the mines would most likely result in increased costs billed through fuel, which management currently believes are recoverable. Management does not believe an early closure of the mines would have an adverse impact on the recovery value of the plant. Cleco Power has the ability to secure alternative fuel sources and expects to have sufficient lignite fuel available to continue seasonal operations of the Dolet Hills Power Station through at least the 2020 and 2021 seasonal operations periods. Also in April 2020, Cleco Power announced its intent to seek regulatory approval to retire the Dolet Hills Power Station at the end of 2021, subject to recovery mechanisms. This does not bind Cleco Power to a specific retirement plan and Cleco Power will continue to evaluate the cost of operating the Dolet Hills Power Station compared with other alternatives and decide the best course of action for the Dolet Hills Power Station within the LPSC regulatory requirements and recovery mechanisms.
Note 15 — Affiliate Transactions
At March 31, 2020, Cleco had an affiliate payable of $33.8 million to Cleco Group primarily for affiliate settlement of taxes payable.
Cleco Power has balances that are payable to or due from its affiliates. The following table is a summary of those balances:
 
AT MAR. 31, 2020
AT DEC. 31, 2019
(THOUSANDS)
ACCOUNTS
RECEIVABLE
ACCOUNTS
PAYABLE
ACCOUNTS
RECEIVABLE
ACCOUNTS
PAYABLE
Cleco Holdings
$10,420
$170
$10,351
$194
Support Group
1,082
10,197
3,172
13,890
Cleco Cajun
535
119
958
39
Total
$12,037
$10,486
$14,481
$14,123
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Note 16 — Intangible Assets and Liabilities
During 2008, Cleco Katrina/Rita acquired a $177.5 million intangible asset which includes $176.0 million for the right to bill and collect storm recovery charges from customers of Cleco Power and $1.5 million of financing costs. This intangible asset was fully amortized in March 2020 and had no residual value at the end of its life.
As a result of the 2016 Merger, fair value adjustments were recorded on Cleco’s Condensed Consolidated Balance Sheet for the valuation of the Cleco trade name and long-term wholesale power supply agreements. At the end of their life, these intangible assets will have no residual value. The trade name intangible asset is being amortized over its estimated economic useful life of 20 years. The intangible assets related to the power supply agreements are amortized over the estimated life of each applicable contract ranging between 7 and 19 years and the amortization is included in Electric operations on Cleco’s Condensed Consolidated Statements of Income.
As a result of the Cleco Cajun Transaction, fair value adjustments were recorded on Cleco’s Condensed Consolidated Balance Sheet for the difference between the contract and market price of acquired long-term wholesale power agreements. The fair value of intangible assets of $98.9 million and intangible liabilities of $14.2 million was reflected in the purchase price allocation. At the end of their life, these intangible assets and liabilities will have no residual value. These intangibles are amortized over the estimated life of each applicable contract ranging between 2 and 8 years. The amortization is included in Electric operations on Cleco’s Condensed Consolidated Statements of Income.
As part of the Cleco Cajun Transaction, Cleco assumed an LTSA for maintenance services related to the Cottonwood Plant. An intangible liability of $24.1 million was reflected in the purchase price allocation and is being amortized using the straight-line method over the estimated life of the LTSA of seven years. The amortization is included as a reduction to the LTSA prepayments on Cleco’s Condensed Consolidated Balance Sheet. For more information on the fair value adjustments of intangible assets and liabilities related to the Cleco Cajun Transaction, see Note 2 — “Business Combinations.”
The following tables present Cleco and Cleco Power’s amortization of intangible assets and liabilities:
Cleco
 
 
 
FOR THE THREE MONTHS
ENDED MAR. 31,
(THOUSANDS)
2020
2019
Intangible assets
 
 
Cleco Katrina/Rita right to bill and collect storm recovery charges
$517
$4,870
Trade name
$64
$64
Power supply agreements
$6,400
$5,190
Intangible liabilities
 
 
LTSA
$871
$581
Power supply agreements
$882
$211
Cleco Power
 
 
 
FOR THE THREE MONTHS
ENDED MAR. 31,
(THOUSANDS)
2020
2019
Cleco Katrina/Rita right to bill and collect storm recovery charges
$517
$4,870
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The following tables summarize the balances for intangible assets and liabilities subject to amortization for Cleco and Cleco Power:
Cleco
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Intangible assets
 
 
Cleco Katrina/Rita right to bill and collect storm recovery charges
$70,594
$70,594
Trade name
5,100
5,100
Power supply agreements
184,004
184,004
Total intangible assets carrying amount
259,698
259,698
Intangible liabilities
 
 
LTSA
24,100
24,100
Power supply agreements
14,200
14,200
Total intangible liability carrying amount
38,300
38,300
Net intangible assets carrying amount
221,398
221,398
Accumulated amortization
(120,395)
(115,167)
Net intangible assets subject to amortization
$101,003
$106,231
Cleco Power
 
 
(THOUSANDS)
AT MAR. 31, 2020
AT DEC. 31, 2019
Cleco Katrina/Rita right to bill and collect storm recovery charges
$177,537
$177,537
Accumulated amortization
(177,537)
(177,020)
Net intangible assets subject to amortization
$
$517
Note 17 — Accumulated Other Comprehensive Loss
The components of accumulated other comprehensive loss are summarized in the following tables for Cleco and Cleco Power. All amounts are reported net of income taxes. Amounts in parentheses indicate debits.
Cleco
FOR THE THREE
MONTHS ENDED
MAR. 31, 2020
(THOUSANDS)
POSTRETIREMENT
BENEFIT NET LOSS
Balances, beginning of period
$(17,513)
Amounts reclassified from AOCI
Amortization of postretirement benefit net gain
414
Balances, Mar. 31, 2020
$(17,099)
FOR THE THREE
MONTHS ENDED
MAR. 31, 2019
(THOUSANDS)
POSTRETIREMENT
BENEFIT NET GAIN
Balances, beginning of period
$1,786
Amounts reclassified from AOCI
Amortization of postretirement benefit net loss
(135)
Balances, Mar. 31, 2019
$1,651
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Cleco Power
 
 
 
 
FOR THE THREE MONTHS ENDED MAR. 31, 2020
(THOUSANDS)
POSTRETIREMENT
BENEFIT
NET LOSS
NET
LOSS
ON CASH
FLOW
HEDGES
TOTAL
AOCI
Balances, beginning of period
$(16,717)
$(5,868)
$(22,585)
Amounts reclassified from AOCI
 
 
 
Amortization of postretirement benefit net loss
426
426
Reclassification of net loss to interest charges
64
64
Balances, Mar. 31, 2020
$(16,291)
$(5,804)
$(22,095)
 
FOR THE THREE MONTHS ENDED MAR. 31, 2019
(THOUSANDS)
POSTRETIREMENT
BENEFIT
NET LOSS
NET
LOSS
ON CASH
FLOW
HEDGES
TOTAL
AOCI
Balances, beginning of period
$(7,060)
$(6,122)
$(13,182)
Amounts reclassified from AOCI
 
 
 
Amortization of postretirement benefit net loss
156
156
Reclassification of net loss to interest charges
64
64
Balances, Mar. 31, 2019
$(6,904)
$(6,058)
$(12,962)
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Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of officers and directors.

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 agreementsagreement 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.

Item 21.
Exhibits and financial statement schedules.
(a)
Exhibits: See Exhibit Index immediately before the signature pages.
(b)
Financial Statement Schedules: See Index to Consolidated Financial Statements and the related notes thereto.
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 havehas 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;
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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)
(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)
(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.
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EXHIBIT INDEX
SEC FILE OR
REGISTRATION
NUMBER
REGISTRATION
STATEMENT OR
REPORT
EXHIBIT
NUMBER
2(a)
1-15759
8-K(10/20/14)
2.1
2(b)
1-15759
10-Q(3/18)
2.1
2(c)
1-15759
8-K(2/8/19)
10.6
3(a)
1-15759
8-K(4/19/16)
3.1
3(b)
1-15759
8-K(4/19/16)
3.2
4(a)(1)
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)
333-02895
S-3(4/29/96)
4(a)(2)
4(b)(3)
333-52540
S-3/A(1/26/01)
4(a)(2)
4(b)(4)
333-52540
S-3/A(1/26/01)
4(a)(3)
4(b)(5)
1-05663
8-K(7/6/05)
4.1
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SEC FILE OR
REGISTRATION
NUMBER
REGISTRATION
STATEMENT OR
REPORT
EXHIBIT
NUMBER
4(b)(6)
1-05663
8-K(11/28/05)
4.1
4(b)(7)
1-05663
8-K(6/2/08)
4.1
4(b)(8)
1-05663
8-K(11/12/09)
4.1
4(b)(9)
1-05663
8-K(11/15/10)
4.1
4(c)(1)
1-15759
8-K(5/17/16)
4.1
4(c)(2)
1-15759
8-K(5/17/16)
4.2
4(c)(3)
1-15759
8-K(5/17/16)
4.3
4(c)(4)
1-15759
8-K(5/24/16)
4.2
4(d)(1)
1-15759
8-K(9/12/19)
4.1
4(d)(2)
1-15759
8-K(9/12/19)
4.2
4(d)(3)
1-15759
8-K(9/12/19)
4.3
4(e)
1-05663
10-Q(9/99)
4(c)
*5.1
*5.2
**10(a)(1)
1-15759
10-K(2008)
10(f)(4)
**10(a)(2)
1-15759
8-K(12/9/08)
10.3
**10(a)(3)
1-15759
10-Q(9/11)
10.2
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SEC FILE OR
REGISTRATION
NUMBER
REGISTRATION
STATEMENT OR
REPORT
EXHIBIT
NUMBER
**10(a)(4)
1-15759
10-K(2014)
10(c)(10)
**10(a)(5)
1-15759
8-K(12/21/17)
10.2
**10(a)(6)
1-15759
10-K(2003)
10(e)(1)(c)
**10(a)(7)
1-15759
10-K(2002)
10(z)(1)
**10(a)(8)
1-15759
10-K(2004)
10(v)(3)
**10(b)(1)
1-15759
10-Q(9/11)
10.1
**10(b)(2)
1-15759
8-K(10/24/14)
10.1
**10(b)(3)
1-15759
8-K(12/23/14)
10.1
**10(b)(4)
1-15759
10-Q(6/15)
10.1
**10(b)(5)
1-15759
8-K(3/28/17)
10.1
**10(b)(6)
1-15759
8-K(4/27/11)
10.1
**10(b)(7)
1-15759
8-K(12/21/17)
10.1
**10(b)(8)
1-15759
8-K(12/21/17)
10.3
**10(c)(1)
333-59696
S-8(4/27/01)
4.3
**10(c)(2)
1-15759
10-K(2008)
10(n)(5)
**10(c)(3)
1-15759
8-K(12/9/08)
10.2
**10(c)(4)
1-15759
10-K(2003)
10(u)
**10(c)(5)
1-15759
10-Q(9/11)
10.5
**10(c)(6)
1-15759
8-K(7/5/16)
10.1
II-5

TABLE OF CONTENTS

SEC FILE OR
REGISTRATION
NUMBER
REGISTRATION
STATEMENT OR
REPORT
EXHIBIT
NUMBER
10(d)(1)
1-05663
8-K(05/09/12)
10.1
10(d)(2)
1-15759
8-K(11/13/15)
10.1
10(d)(3)
1-05663
8-K(12/21/16)
10.1
10(d)(4)
1-15759
8-K(12/21/17)
10.1
10(d)(5)
1-15759
8-K(4/19/16)
10.1
10(d)(6)
1-15759
8-K(7/1/16)
10.1
10(d)(7)
1-15759
8-K(2/8/19)
10.2
10(d)(8)
1-15759
8-K(2/8/19)
10.3
10(d)(9)
1-15759
8-K(2/8/19)
10.4
10(d)(10)
1-15759
8-K(2/8/19)
10.5
10(d)(11)
1-15759
8-K(2/8/19)
10.7
10(d)(12)
1-15759
8-K(2/8/19)
10.8
II-6

SIGNATURESTABLE OF CONTENTS

 
SEC FILE OR
REGISTRATION
NUMBER
REGISTRATION
STATEMENT OR
REPORT
EXHIBIT
NUMBER
10(d)(13)
1-15759
8-K(5/21/20)
10.1
10(d)(14)
1-15759
8-K(5/21/20)
10.2
10(d)(15)
1-15759
8-K(5/21/20)
10.3
10(d)(16)
1-15759
8-K(5/21/20)
10.4
10(e)(1)
1-15759
10-Q(3/17)
10.3
10(e)(2)
1-15759
10-Q(3/17)
10.4
10(e)(3)
1-15759
10-Q(3/17)
10.5
10(f)
1-15759
10-Q(3/20)
10.1
10(g)
1-15759
10-Q(3/17)
10.6
21
1-15759
10-K(2019)
21
*23(a)
Included in Exhibit 5.1.
 
*23(b)
Included in Exhibit 5.2.
 
*23(c)
 
 
 
*23(d)
II-7

TABLE OF CONTENTS

SEC FILE OR
REGISTRATION
NUMBER
REGISTRATION
STATEMENT OR
REPORT
EXHIBIT
NUMBER
*24
*25.1
*99.1
*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.
**
Indicates a management contract or compensatory plan or arrangement.
II-8

TABLE OF CONTENTS

Pursuant to the requirements of the Securities Act, the Registrantregistrant 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:
By:
/s/ Peggy ScottWilliam G. Fontenot
(Peggy Scott)William G. Fontenot)
(Chairperson and InterimPresident & Chief Executive Officer)

Date: March 17, 2017

May 27, 2020

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

SIGNATURE

TITLE

DATE

/s/ Peggy Scott

(Peggy Scott)

William G. Fontenot

Chairperson and Interim

President & Chief Executive Officer (Principal
(Principal Executive Officer)

March 17, 2017
May 27, 2020
(William G. Fontenot)

/s/ Terry L. Taylor

(Terry L. Taylor)

Kazi K. Hasan

Chief Financial Officer (Principal
(Principal Financial Officer)

March 17, 2017
May 27, 2020
(Kazi K. Hasan)

/s/ F. Tonita Laprarie

(Tonita Laprarie)

Controller and Chief Accounting Officer (Principal
(Principal Accounting Officer)

March 17, 2017
May 27, 2020
(F. Tonita Laprarie)
MANAGERS*
Andrew M. Chapman
Paraskevas Fronimos
Richard J. Gallot, Jr.
David R. Gilchrist
Gerald C. Hanrahan, Jr.
Christopher J. Leslie
Jon R. R. Perry
Aaron J. Rubin
Peggy B. Scott
Steven J. Turner
Bruce D. Wainer
*By:
/s/ William G. Fontenot
May 27, 2020

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

(William G. Fontenot, as Attorney-in-Fact)

*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.1-157598-K(10/20/14)2.1
3(a)Articles of Entity Conversion of Cleco Corporate Holdings LLC, dated as of April 13, 20161-157598-K(4/19/16)3.1
3(b)Limited Liability Company Agreement of Cleco Corporate Holdings LLC, dated as of April 13, 20161-157598-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 Trustee1-0566310-K(1997)4(a)(1)
4(a)(2)Eighteenth Supplemental Indenture dated as of December 1, 1982, to Exhibit 4(a)(1)1-0566310-K(1993)4(a)(8)
4(a)(3)Nineteenth Supplemental Indenture dated as of January 1, 1983, to Exhibit 4(a)(1)1-0566310-K(1993)4(a)(9)
4(a)(4)Twenty-Sixth Supplemental Indenture dated as of March 15, 1990, to Exhibit 4(a)(1)1-056638-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, 198833-24896S-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 York333-02895S-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 York333-52540S-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 York333-52540S-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.1-056638-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.1-056638-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.1-056638-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)1-056638-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)1-056638-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.1-157598-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.A1-157598-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.A1-157598-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.A1-157598-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 Purchasers1-157598-K(5/17/16)4.4
4(e)Agreement Under Regulation S-K Item 601(b)(4)(iii)(A)1-0566310-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, 20091-1575910-K(2008)10(f)(4)
10(a)(2)Supplemental Executive Retirement Plan (Amended and Restated January 1, 2009), Amendment No. 11-157598-K(12/9/08)10.3
10(a)(3)Cleco Corporation Supplemental Executive Retirement Plan Amendment, effective October 28, 20111-1575910-Q(9/11)10.2
10(a)(4)Cleco Corporation Supplemental Executive Retirement Plan Amended and Restated effective January 1, 2009, Amendment No. 31-1575910-K(2014)10(c)(10)
10(a)(5)Supplemental Executive Retirement Trust dated December 13, 20001-1575910-K(2003)10(e)(1)(c)

II-5


10(a)(6)Supplemental Executive Retirement Plan Participation Agreement between Cleco Corporation and Dilek Samil1-1575910-K(2002)10(z)(1)
10(a)(7)Supplemental Executive Retirement Plan Participation Agreement between Cleco Corporation and Michael H. Madison1-1575910-K(2004)10(v)(3)
10(b)(1)Cleco Corporation Executive Severance Plan, effective October 28, 20111-1575910-Q(9/11)10.1
10(b)(2)Cleco Corporation Executive Severance Plan (As amended and restated) Amendment No. 11-157598-K(10/24/14)10.1
10(b)(3)Cleco Corporation Executive Severance Plan (As amended and restated) Amendment No. 21-157598-K(12/23/14)10.1
10(b)(4)Cleco Corporation Executive Severance Plan (As amended and restated) Amendment No. 31-1575910-Q(6/15)10.1
10(b)(5)Executive Employment Agreement, dated April 21, 2011, by and between Cleco Corporation and Bruce A. Williamson1-157598-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, 20161-157598-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, 20161-157598-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, 20161-157598-K(4/1/16)10.4
10(b)(9)Letter Agreement, dated March 29, 2016, between Bruce A. Williamson and Cleco Corporation1-157598-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 Cleco1-0566310-K(1997)10(m)
10(d)(1)Cleco Corporation Pay for Performance Plan1-1575910-K(2011)10(g)(4)
10(d)(2)Cleco Corporation Pay for Performance Plan, As Amended and Restated December 3, 20121-1575910-K(2012)10(f)(5)
10(e)(1)Cleco Corporation Deferred Compensation Plan333-59696S-8(4/27/01)4.3
10(e)(2)First Amendment to Cleco Corporation Deferred Compensation Plan1-1575910-K(2008)10(n)(5)
10(e)(3)Cleco Corporation Deferred Compensation Plan, Corrective Section 409A Amendment1-157598-K(12/9/08)10.2

II-6


10(e)(4)Deferred Compensation Trust dated January 20011-1575910-K(2003)10(u)
10(e)(5)Cleco Corporation Deferred Compensation Plan Amendment, effective October 28, 20111-1575910-Q(9/11)10.5
10(e)(6)Form of Cleco Corporate Holdings LLC Retention Bonus Plan for calendar years 2016 and 20171-157598-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 thereto1-056638-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 agent1-157598-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 agent1-157598-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 thereto1-157598-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 thereto1-056638-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 thereto1-157598-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 thereto1-157598-K(7/1/16)10.1
10(g)Acadia Power Partners, LLC – Third Amended and Restated Limited Liability Company Agreement dated February 23, 20101-1575910-K(2010)10(j)
10(h)Form of the Cleco Corporation 2014 Recovery Agreement Pay for Performance Plan, effective December 22, 20141-157598-K(12/23/14)10.2
10(i)(1)Form of Board of Managers Services Agreement, dated as of April 13, 20161-157598-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, 20161-1575910-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. Crump1-1575910-K(2016)10(j)
10(k)Interim Executive Employment Agreement, effective February 8, 2017, by and between Peggy Scott and Cleco Group LLC1-1575910-K(2016)10(k)
*12Computation of Ratios of Earnings to Fixed Charges
*21Subsidiaries 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.
*24Power 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.
*99.1Form of Letter of Transmittal.
*99.2Form of Notice of Guaranteed Delivery.
*101.INSXBRL Instance Document
*101.SCHXBRL Taxonomy Extension Schema
*101.CALXBRL Taxonomy Extension Calculation Linkbase
*101.DEFXBRL Taxonomy Extension Definition Linkbase
*101.LABXBRL Taxonomy Extension Label Linkbase
*101.PREXBRL Taxonomy Extension Presentation Linkbase

*Filed herewith.

II-9