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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________
FORM 10
GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(B) OR (G) OF THE SECURITIES EXCHANGE ACT OF 1934
CLECO UTILITY GROUP INC.
(Exact name of registrant as specified in its charter)
LOUISIANA 72-0244480
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification Number)
2030 DONAHUE FERRY ROAD
PINEVILLE, LOUISIANA 71360-5226
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (318) 484-7400
Securities to be registered pursuant to Section 12(b) of the Act:
Name of each exchange on which
Title of each class to be so registered each class is to be registered
--------------------------------------- ------------------------------
NONE. Not applicable.
Securities to be registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $2.00 PAR VALUE
(Title of class)
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TABLE OF CONTENTS
ITEM 1. BUSINESS............................................... 5
ITEM 2. FINANCIAL INFORMATION.................................. 18
ITEM 3. PROPERTIES............................................. 31
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT............................................. 31
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS....................... 35
ITEM 6. EXECUTIVE COMPENSATION................................. 38
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......... 49
ITEM 8. LEGAL PROCEEDINGS...................................... 50
ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S
COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.......... 51
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES................ 52
ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED 52
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.............. 53
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA............ 55
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.................... 55
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS...................... 55
GLOSSARY OF TERMS
References in this registration statement to "we," "us," "the Company" or
other similar terms mean Cleco Utility Group Inc., and references to "Cleco"
mean Cleco Corporation, unless the context clearly indicates otherwise.
Additional abbreviations or acronyms used in this registration statement are
defined below:
Abbreviation or Acronym Definition
1935 Act Public Utility Holding Company Act of 1935
AFUDC Allowance for Funds Used During Construction
AQD Air Quality Division of the LDEQ
Code Internal Revenue Code of 1986, as amended
CPS Coughlin Power Station
DHMV Dolet Hills Mining Venture
Dolet Hills Dolet Hills Power Station
EITF No. 97-4 Deregulation of the Pricing of Electricity - Issues
Related to the Application of FASB Statements
No. 71 and 101
EITF No. 98-10 Accounting for Contracts Involved in Energy Trading
and Risk Management Activities
EITF Emerging Issues Task Force
EMFs Electric and magnetic fields
EPA Environmental Protection Agency
EPS Earnings per share
ERISA Employee Retirement Income Security Act of 1974
ESOP Employee Stock Ownership Plan
Evangeline Cleco Evangeline LLC
FAC Fuel adjustment clause
FASB Financial Accounting Standards Board
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Federal Court Suit Lawsuit filed by the Company and SWEPCO on April 15,
1997 against DHMV and its partners in the United
States District Court for the Western District of
Louisiana
FERC Federal Energy Regulatory Commission
Generation Cleco Generation Services LLC
GIS Geographic information system
Intrastate CLE Intrastate Pipeline Company, Inc.
ISO Independent System Operator
kV Kilovolt
kW Kilowatt
kWh Kilowatt-hour
LBCL Business Corporation Law of the State of Louisiana
LDEQ Louisiana Department of Environmental Quality
LMA Lignite Mining Agreement
LPDES Louisiana Pollution Discharge Elimination System
LPSC Louisiana Public Service Commission
Marketing & Trading Cleco Marketing & Trading LLC
MMBtu Million British thermal units
MW Megawatt
NOx Nitrogen oxides
NPDES National Pollutant Discharge Elimination System
RTO Regional Transmission Organization
Rodemacher Rodemacher Power Station
SEC Securities and Exchange Commission
SERP Cleco Supplemental Executive Retirement Plan
SFAS Statement of Financial Accounting Standards
SFAS No. 71 Accounting for the Effects of Certain Types of
Regulation
SFAS No. 80 Accounting for Futures Contracts
SFAS No. 101 Regulated Enterprises - Accounting for the
Discontinuation of Application of FASB Statement No. 71
SFAS No. 109 Accounting for Income Taxes
SFAS No. 121 Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of
SFAS No. 123 Accounting for Stock-Based Compensation
SFAS No. 125 Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities
SFAS No. 128 Earnings per Share
SFAS No. 131 Disclosures about Segments of an Enterprise and
Related Information
SFAS No. 133 Accounting for Derivative Instruments and Hedging
Activities
SFAS No. 137 Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of
FASB Statement No. 133
SFAS No. 138 Accounting for Certain Derivative Instruments and
Certain Hedging Activities
SO2 Sulfur dioxide
SPP Southwest Power Pool
State Court Suit Lawsuit filed by the Company and SWEPCO on August 13,
1997 against the parent companies of DHMV in the
First Judicial District Court for Caddo Parish,
Louisiana
Support Group Cleco Support Group LLC
SWD Solid Waste Division of the LDEQ
SWEPCO Southwestern Electric Power Company
Teche Teche Electric Cooperative, Inc.
TMDL Total Maximum Daily Loading
The Act Clean Air Act Amendments of 1990
TRI Toxics Release Inventory
UtiliTech Utility Construction & Technology Solutions LLC
Utility Group Cleco Utility Group Inc.
VAR Value-at-risk
Williams Energy Williams Energy Marketing and Trading Company
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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This registration statement, including "Item 1. Business," "Item 2.
Financial Information" and "Item 8. Legal Proceedings," contains forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. These statements relate to future events, our future financial
performance, future legislative and regulatory changes affecting our business
and other matters. These forward-looking statements are based on management's
beliefs as well as assumptions made by and information currently available to
management. Although we believe the expectations reflected in these forward-
looking statements are reasonable, these forward-looking statements are based on
numerous assumptions (some of which may prove to be incorrect) and are subject
to risks and uncertainties that could cause the actual results to differ
materially from our expectations.
When used, the words "anticipate," "estimate," "expect," "objective,"
"projection," "forecast," "goal" and similar expressions are intended to
identify forward-looking statements. In addition to any assumptions and other
factors referred to specifically in connection with these forward-looking
statements, the following list identifies some of the factors that could cause
our actual results to differ materially from those contemplated in any of our
forward-looking statements:
. unusual weather conditions, catastrophic weather-related damage, unscheduled
generation outages, unusual maintenance or repairs, unanticipated changes to
fuel costs, gas supply costs or availability constraints due to higher
demand, shortages, transportation problems or other developments,
environmental incidents or electric transmission or gas pipeline system
constraints;
. increased competition in the electric industry, including effects of industry
restructuring or deregulation, transmission system operation or
administration, retail wheeling or cogeneration;
. unanticipated changes in rate-setting policies or procedures, recovery of
investments made under traditional regulation and the frequency and timing of
rate increases;
. financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board (FASB), the Securities and Exchange
Commission (SEC), the Federal Energy Regulatory Commission (FERC), the
Louisiana Public Service Commission (LPSC) or similar entities with
regulatory or accounting oversight;
. economic conditions, including inflation rates and monetary fluctuations;
. changing market conditions and a variety of other factors associated with
physical energy and financial trading activities, including, but not limited
to price, basis, credit, liquidity, volatility, capacity, transmission,
interest rate and warranty risks;
. employee work force factors, including changes in key executives;
. cost and other effects of legal and administrative proceedings, settlements,
investigations, claims and other matters; and
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. changes in federal, state or local legislative requirements, such as changes
in tax laws or rates, regulating policies or environmental laws and
regulations.
We undertake no obligation to update or revise any forward-looking
statements, whether as a result of changes in actual results, changes in
assumptions or other factors affecting such statements.
ITEM 1. BUSINESS
GENERAL
Cleco Utility Group Inc., formerly Cleco Corporation, was incorporated
under the laws of the State of Louisiana on January 2, 1935. We are an electric
utility that contains LPSC jurisdictional generation, transmission and
distribution electric utility operations. We provide electric utility services
to approximately 249,000 retail and wholesale customers in 63 communities and
rural areas in a 14,000-square-mile region in the State of Louisiana. Our
principal executive offices are located at 2030 Donahue Ferry Road, Pineville,
Louisiana 71360-5226.
Effective July 1, 1999, we were reorganized into a holding company
structure. This reorganization resulted in the creation of a new holding
company, Cleco Corporation (Cleco), which became the owner of all of our
outstanding common stock. In connection with the reorganization, we transferred
the shares of capital stock of all our subsidiaries to Cleco. The
reorganization had no impact on our financial statements because it was
accounted for similarly to a pooling of interest. Cleco, subject to certain
limited exceptions, is exempt from regulation as a public utility holding
company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of
1935 (1935 Act) and Rule 2 thereunder.
On September 21, 2000, we filed applications with the FERC and the LPSC
requesting authorization to convert our form of business organization from a
corporation to a limited liability company. The purpose of our proposed
conversion is to lessen our Louisiana state tax obligations. We must obtain
authorization from the FERC and the LPSC to engage in the conversion because of
their jurisdiction over us as a utility. On November 2, 2000, the LPSC
authorized our conversion to a limited liability company. We anticipate
receiving the necessary authorization from the FERC by the end of 2000 and will
proceed with the conversion if and when such authorization is given.
OPERATIONS
Power Generation
We operate and either own or have an ownership interest in three steam
electric generating stations, the Teche Power Station, the Rodemacher Power
Station (Rodemacher) and the Dolet Hills Power Station (Dolet Hills) and a gas
turbine, the Franklin Gas Turbine. We are the sole owner of Teche Power Station
and Rodemacher Unit 1. We own a 50% interest in Dolet Hills Unit 1 and a 30%
interest in Rodemacher Unit 2. At September 30, 2000, our aggregate
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electric generating capacity was 1,366,900 kilowatts (kW) (excluding 20,000 kW
of firm purchases from the Sabine River Authority). We are the sole owner of the
Franklin Gas Turbine.
The following table sets forth certain information with respect to our
generating facilities.
<TABLE>
<CAPTION>
CAPACITY AT YEAR OF
SEPTEMBER 30, 2000 TYPE OF FUEL USED FOR GENERATING INITIAL
GENERATING STATION (KW) GENERATION(1) UNIT # OPERATION
------------------ ------------------ ---------------------- ----------- ---------
<S> <C> <C> <C> <C>
Franklin Gas Turbine 7,000 gas 1 1973
Teche Power Station 23,000 gas 1 1953
48,000 gas 2 1956
367,000 gas/oil (standby) 3 1971
Rodemacher Power Station 440,000 gas/oil 1 1975
156,900 (2) coal/gas 2 1982
Dolet Hills Power Station 325,000 (3) lignite 1 1986
----------
Total Generating Power 1,366,900
==========
</TABLE>
------------
(1) When oil is used on a standby basis, capacity may be reduced.
(2) Represents our 30% interest in the capacity of Rodemacher Unit 2, a
523,000-kW generating unit.
(3) Represents our 50% interest in the capacity of Dolet Hills Unit 1, a
650,000-kW generating unit.
Fuel
We use various types of fuel for generation of electricity. The
following table sets forth, for the periods indicated, the percentages of power
generated from various fuels at our electric generating plants, the cost of fuel
used per kilowatt hour (kWh) attributable to each such fuel and the weighted
average fuel cost per kWh.
<TABLE>
<CAPTION>
LIGNITE COAL GAS FUEL OIL
--------------------- --------------------- --------------------- --------------------- WEIGHTED
COST PERCENT COST PERCENT COST PERCENT COST PERCENT AVERAGE COST
PER KWH OF PER KWH OF PER KWH OF PER KWH OF PER KWH
PERIOD (MILLS) GENERATION (MILLS) GENERATION (MILLS) GENERATION (MILLS) GENERATION (MILLS)
--------- -------- ---------- -------- ---------- -------- ---------- -------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 (1) 15.55 33.8 15.11 16.3 41.98 49.9 -- -- 28.66
1999 15.74 28.4 14.90 17.2 27.45 54.3 -- -- 21.96
1998 15.85 32.0 14.88 16.7 25.38 51.3 -- -- 20.57
1997 14.85 36.7 17.06 19.1 29.85 44.2 -- -- 21.90
1996 15.45 38.1 16.67 21.3 30.06 39.8 26.09 0.8 21.61
1995 14.86 35.9 18.88 14.3 19.48 49.8 24.77 0.0 17.74
</TABLE>
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(1) Nine months ended September 30, 2000.
Power Purchases
If transmission capacity is available, we purchase electric energy from
neighboring utilities when the price of the energy purchased is less than our
cost of generating energy from our own facilities or when we need power to
supplement our own electric generation. Additionally, we have a long-term
contract under which we purchase a small percentage of our total annual energy
requirements from a hydroelectric generating plant.
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In 1999, the amount of power we purchased increased compared to 1998 as a
result of the increased demand for electric energy and a scheduled major
maintenance outage at Dolet Hills. In the first nine months of 2000, the amount
of power we purchased increased compared to the corresponding period in 1999 due
to increased load requirements and the transfer of the existing assets of
Coughlin Power Station (CPS) from our LPSC-regulated rate base in 1999 into
Cleco Evangeline LLC (Evangeline), an indirect wholly owned subsidiary of Cleco,
which repowered the plant.
The following table sets forth the amounts of power we purchased on the
wholesale market for the periods indicated.
% of Total
Million Energy
Period kWh Requirements
------ ------- ------------
2000(1) 2,464 35%
1999 2,359 27%
1998 2,117 24%
1997 1,924 24%
1996 2,529 33%
1995 1,430 19%
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(1) Nine months ended September 30, 2000.
For information regarding our ability to pass through changes in costs of fuel
to our customers, see "Regulatory Matters, Industry Developments and Franchises-
-Rates" below.
In future years, our generating facilities may not supply enough electric
power to meet our customers' growing demand (native load demand) and we may need
to purchase additional generating capacity and/or purchase power to satisfy
these needs. In March 2000, following a competitive bid process, we entered
into three contracts for firm electric capacity and energy with Williams Energy
Marketing and Trading Company (Williams Energy) and Dynegy Power Marketing,
Inc., for 605 megawatts (MW) of capacity in 2000, increasing to 760 MW of
capacity in 2004. These contracts were approved by the LPSC in March 2000 and
expire in 2004. Management expects the contracts, combined with our own
generation resources or power purchase agreements, to meet substantially all of
our native load demand through 2004. Because of our location on the transmission
grid, we rely on one main supplier of electric transmission and are sometimes
constrained as to the amount of purchased power we can bring into our system.
These three contracts are not expected to be affected by such transmission
constraints.
Natural Gas Supply
During the first nine months of 2000, we purchased a total of 28,876
million British thermal units (MMBtu) of natural gas for the generation of
electricity. The 2000 nine month period and average per-day quantities of gas
we purchased from each supplier are shown in the table below.
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<TABLE>
<CAPTION>
AVERAGE
FIRST NINE MONTHS AMOUNT
OF 2000 PURCHASED PERCENT
PURCHASES PER DAY OF TOTAL
NATURAL GAS SUPPLIER (MMBTU) (MMBTU) GAS USED
-------------------- ------------------- ---------- --------
<S> <C> <C> <C>
Amoco Natural Gas 4,961 163 17.18
LIG Chemical Company 3,717 122 12.87
Reliant Energy Services, Inc. 2,989 98 10.35
KN Energy 2,855 94 9.89
Others 14,354 471 49.71
------ --- ------
28,876 948 100.00%
====== === ======
</TABLE>
CLE Intrastate Pipeline Company, Inc. (Intrastate), a wholly owned
subsidiary of one of our affiliates, owns a series of natural gas
interconnections with Trunkline Gas Company, Columbia Gulf Transmission Co. and
ANR Pipeline Company. For more information regarding the use of these
interconnections, see "--Intercompany Transactions" in "Item 7. Certain
Relationships and Related Transactions," below. The pipeline interconnections
have allowed us to access various additional natural gas supply markets, which
helps to maintain the competitiveness of our generating units.
Natural gas was plentiful and available without interruption throughout
1999 and the first nine months of 2000. We currently meet, and expect to
continue to meet, our natural gas requirements with purchases on the spot market
through daily, monthly and seasonal contracts with various natural gas
suppliers. However, future supplies of natural gas remain vulnerable to
disruptions due to weather events and transportation disruptions. The potential
for disruptions to us has been decreased by the addition of the Intrastate
pipeline interconnections. Nevertheless, large boiler fuel users of natural gas,
including electric utilities, generally have low priority among natural gas
users in the event pipeline suppliers are forced to curtail deliveries due to
inadequate supplies. As a result, supplies of natural gas may become unavailable
from time to time or prices may increase rapidly in response to temporary supply
disruptions. Such events, though rare, may require us to shift our gas-fired
generation to alternative fuel sources, such as fuel oil, to the extent we have
the capability to burn those alternative fuels. Currently, we anticipate that
our alternative fuel capability combined with our solid-fuel generation
resources are adequate to meet our fuel needs during any temporary disruption of
natural gas supplies.
Coal and Lignite Supply
We use coal fuel for generation at Rodemacher Unit 2. The majority of
the coal for Rodemacher Unit 2 is purchased from mines in Wyoming under a long-
term contract with Jacobs Ranch Coal Company expiring in 2007. The contract has
been modified under price reopener procedures initiated in early 1997. The
pricing structure under the modified contract has been defined through mid-2002.
After purchasing a given annual quantity of base coal (approximately 500,000
tons), we have the right to purchase coal from third parties on the spot market
through competitive bidding. Provisions for pricing and terms can again be
renegotiated under a contract reopener provision in early 2002.
The coal for Rodemacher Unit 2 is transported under a long-term rail
transportation contract with the Union Pacific Railroad. In 1997 and 1998,
Union Pacific experienced operating problems that resulted in reduced volumes
delivered to the unit with the coal inventory
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of the unit fluctuating at or below our desired minimum level. However, in 1999
and the first nine months of 2000, the deliveries of coal by the railroad were
back to the normal schedule.
We use lignite fuel for generation at Dolet Hills Unit 1. Substantially
all of the lignite used to fuel Dolet Hills Unit 1 is obtained under two long-
term agreements. We and Southwestern Electric Power Company (SWEPCO), each a
50% owner of Dolet Hills Unit 1, have entered into agreements pursuant to which
each acquired an undivided 50% interest in the other's leased and owned lignite
reserves in northwestern Louisiana. We and SWEPCO also have entered into a
long-term agreement expiring in 2011 with the Dolet Hills Mining Venture (DHMV)
for the mining and delivery of such lignite reserves. These reserves are
expected to provide a substantial portion of the fuel requirements for the
projected operating life of Dolet Hills Unit 1. Our minimum annual purchase
requirement under the agreement with DHMV is 1,750,000 tons. The price of
lignite delivered pursuant to the agreement is a base price per ton, subject to
escalation based on certain inflation indices, plus specified "pass-through"
costs. Additional spot lignite may be obtained through competitive bidding. We
are currently engaged in litigation involving our agreement with DHMV. For
information regarding this litigation, see "Item 8. Legal Proceedings" below.
Additionally, we and SWEPCO have entered into a long-term agreement
expiring in 2011 with Red River Mining Co., a joint venture of the North
American Coal Corporation and Phillips Coal Company, which provides for base
contract purchases and spot purchases of lignite. Our minimum annual purchase
requirement is 550,000 tons. The base lignite price under the agreement is a
base price per MMBtu, subject to escalation, plus certain "pass-through" costs,
while the spot lignite price is determined through competitive bidding.
The continuous supply of coal and lignite from the mining sources
described above may be subject to interruption due to adverse weather conditions
or other factors that may disrupt mining operations or transportation. At
September 30, 2000, our coal inventory at Rodemacher Unit 2 was approximately
128,088 tons (about a 62-day supply) and our lignite inventory at Dolet Hills
Unit 1 was approximately 199,366 tons (about a 34-day supply).
Oil Supply
We store fuel oil as an alternative fuel source. Rodemacher has storage
capacity for an approximate 75-day supply and our other generating stations have
storage capacity totaling about a 20-day supply. However, in accordance with
our current fuel oil inventory practices, at September 30, 2000, we had between
5 to 10 days' supply of fuel oil stored at our generating stations. During 1999
and the first nine months of 2000, no barrels of fuel oil were burned.
Sales
We are a public utility engaged principally in the generation,
transmission, distribution and sale of electricity within the State of
Louisiana. For further information regarding our generating stations and
transmission and distribution facilities, see "--Power Generation" above and
"Item 3. Properties" below.
Our 1999 system peak demand occurred in August and was 1,767,000 kW. Our
2000 year-to-date system peak demand occurred in August and was 1,839,000 kW.
Our sales and peak demand are affected and influenced by weather and are
generally highest during the
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summer air-conditioning and winter heating seasons. For information concerning
the financial effects of seasonal demand on our quarterly operating results, see
Note P to the audited financial statements included in Annex F to this
registration statement. We expect the peak demand on our system to grow at a
compound annual rate of approximately 2% to 3% over the next five years. Our
capacity reserve margin for 1999 was 6.3% and for the first nine months of 2000
was 7.7%. To meet our capacity reserve margin for 2000, we purchased 605 MW of
firm capacity and transmission service that began on June 1, 2000, and increases
to 760 MW in 2004 pursuant to several agreements. See "--Power Purchases" above
for a description of these power purchase agreements. We believe we can meet our
anticipated growth in customer demand by purchasing the required capacity on the
wholesale market. Future capacity requirements may be satisfied by continuing to
purchase power on the wholesale market, adding capacity to existing power plants
or building new power plants.
Marketing Operations
We began marketing electricity into the Entergy market in mid-1998. In
1999, we expanded that activity into the Cinergy market. In 1999, we also began
marketing natural gas. We have seen a reduction in energy marketing revenues in
2000 when compared with prior years due to a reduced level of energy trading
activity resulting from a refinement of trading practices to target selective
market opportunities and due to the transfer of specific CPS generating assets
to Evangeline.
If we have excess electricity capacity or excess natural gas at our power
plants, Cleco Marketing & Trading LLC (Marketing & Trading) markets the excess
on our behalf. Marketing & Trading also develops a monthly gas procurement
strategy for us, giving priority to achieving a reliable supply of gas to fuel
our power plants, maintaining operational flexibility and cost of service in
developing the strategy.
ENERGY MARKETING OPERATIONS
NINE MONTHS ENDED YEAR ENDED
SEPTEMBER 30, DECEMBER 31,
--------------------------- -----------------------
2000 1999 1998
------- ------- -------
(IN THOUSANDS)
Revenue $13,000 $237,731 $32,695
Purchases 9,487 230,084 27,322
------- -------- -------
Gross Margin $ 3,513 $ 7,647 $ 5,373
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REGULATORY MATTERS, INDUSTRY DEVELOPMENTS AND FRANCHISES
Rates
Our retail electric operations are subject to the jurisdiction of the
LPSC with respect to rates, standards of service, accounting and other matters.
We also are subject to the jurisdiction of the FERC with respect to certain
aspects of our business, including rates for wholesale service, interconnections
with other utilities and the transmission of power. Periodically, we have
sought and received increases in base rates from both the LPSC and the FERC to
cover increases in operating costs and costs associated with additions to
generation, transmission and distribution facilities.
Our electric rates include a fuel and purchased power cost adjustment
clause that enables us to adjust rates for monthly fluctuations in the cost of
fuel and short-term purchased power. Pretax income from certain off-system
sales to other utilities is passed on to customers through a reduction in fuel
cost adjustment billing factors. Fuel costs and fuel adjustment billing factors
are approved by the LPSC and the FERC. These cost adjustments are based on costs
from earlier periods that can result in over- or under-recovery for the period
in which the adjustment is made. Any over- or under-recovery is corrected by an
adjustment in later periods. At September 30, 2000, the net accumulated asset
for under-recovery on sales subject to the LPSC's jurisdiction was approximately
$10.6 million, which is reported as Accumulated deferred fuel on the unaudited
Interim Balance Sheets included in Annex F to this registration statement.
The LPSC elected in 1993 to review the earnings of all electric, gas,
water and telecommunications utilities that it regulates to determine whether
the returns on equity of these companies were higher than returns that might be
awarded in the economic environment at that time. In 1996, the LPSC approved a
settlement of our earnings review, which lowered our electricity rates. The
terms of the settlement were to be effective for a five-year period. In
February 1999, the period was extended three years until 2004. For information
regarding this settlement, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations Financial Condition--Retail
Rates" in "Item 2. Financial Information" below.
Franchises
We operate under nonexclusive franchise rights granted by governmental
units, such as municipalities and parishes (counties), and enforced by state
regulation. These franchises are for fixed terms, which vary from 10 years to
50 years. In the past, we have been substantially successful in the timely
renewal of franchises as each reaches the end of its term and expires. We are
currently negotiating with the City of Jeanerette for franchise rights
applicable to its approximately 3,000 customers. Our franchise with the City of
Opelousas, which has 10,873 customers, was scheduled to expire in August 2001.
In November 2000, we successfully negotiated the renewal of that franchise for a
term of ten years, beginning August 2001. Our franchises with the cities of
Washington and Franklinton, and their 1,891 and 2,484 customers respectively,
will be up for renewal in 2003. We were successful in an October 7, 2000,
referendum to renew our franchise agreement with the City of New Iberia, where
we currently serve 18,744 customers, for a term of 25 years.
No other franchises expire until 2008. A number of parishes have
attempted in recent years to impose franchise fees on retail revenues earned
within the unincorporated areas we serve. If the parishes are ultimately
successful, taxes other than income taxes could increase substantially in future
years.
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Industry Developments
Technological improvements in recent years have somewhat lessened the
historical barriers to entry in the electric utility industry and have set in
motion statutory and regulatory changes aimed at increased competition in the
industry. Federal and state legislation and new regulatory initiatives designed
to restructure electricity markets will likely produce even greater competition
at both wholesale and retail levels in the future. The LPSC is investigating
whether retail choice is in the best interest of Louisiana electric utility
customers. During 1999, the LPSC directed its staff to develop a transition-to-
competition plan, which is scheduled to be released by the LPSC in January 2001.
We and a number of parties, including the other Louisiana electric utilities,
certain power marketing companies and various associations representing industry
and consumers, have been participating in electric industry restructuring
proceedings before the LPSC since 1997. Several neighboring states have taken
steps to initiate retail choice by 2002. At the federal level, several bills,
some with conflicting provisions, were introduced during 1999 and 2000 to
promote a more competitive environment in the electric utility industry.
Management expects the debate relating to retail choice and other related issues
to continue in legislative and regulatory bodies through the remainder of 2000
and in 2001. At this time, we cannot predict whether any legislation or
regulation will be enacted or adopted during the remainder of 2000 or in 2001
and, if enacted, what form such legislation or regulation would take.
Wholesale Electric Competition
The Energy Policy Act, enacted by Congress in 1992, significantly changed
U.S. energy policy, including regulations governing the electric utility
industry. The Energy Policy Act allows the FERC, on a case-by-case basis and
with certain restrictions, to order wholesale transmission access and to order
electric utilities to enlarge their transmission systems. The Energy Policy Act
prohibits FERC-ordered retail wheeling (i.e., opening up electric utility
transmission systems to allow customer choice of energy suppliers at the retail
level), including "sham" wholesale transactions. Further, under the Energy
Policy Act, a FERC transmission order requiring a transmitting utility to
provide wholesale transmission services must include provisions generally
permitting the utility to recover from the FERC applicant all of the costs
incurred in connection with the transmission services, including any enlargement
of the transmission system and any associated services.
In addition, the Energy Policy Act revised the 1935 Act to permit
utilities, including registered holding companies, and nonutilities to form
"exempt wholesale generators" without the principal restrictions of the 1935
Act. Under prior law, independent power producers were generally required to
adopt inefficient and complex ownership structures to avoid pervasive regulation
under the 1935 Act.
In 1996, the FERC issued Orders No. 888 and 889 requiring open access to
utilities' transmission systems. The open access provisions require FERC-
regulated electric utilities to offer third parties access to transmission under
comparable terms and conditions as the utilities' use of their own systems. In
addition, Order No. 888, as amended, provides for the full recovery from a
utility's departing customers of wholesale stranded costs, to the extent such
costs were prudently incurred to serve wholesale customers and would go
unrecovered if those customers used open access transmission service and moved
to another electricity supplier. Order No. 888,
12
<PAGE>
as amended, also allows customers under existing wholesale sales contracts to
seek FERC approval to modify their contracts on a case-by-case basis. Because of
the "grandfather" provisions of Orders No. 888 and 889, most of our existing
transmission contracts are not affected by Orders No. 888 and 889. To date, the
orders have not had a material impact on our operations or financial condition.
In 1999, the FERC issued Order No. 2000, which further defines the
operation of utilities' transmission systems. Order No. 2000 establishes a
general framework for all transmission-owning entities in the nation to place
their transmission facilities under the control of appropriate Retail
Transmission Organizations (RTO). Although participation is voluntary, the FERC
has made it clear that any jurisdictional entity not participating in an RTO
will be subject to further regulatory steps. Current objectives state that all
electric utilities that own, operate or control interstate transmission
facilities should participate in an RTO that will be operational no later than
December 15, 2001. On October 16, 2000, we submitted a filing with the FERC
stating that we will likely join the Southwest Power Pool's (SPP) RTO either as
a member of the SPP Independent System Operator (ISO) or as part of Entergy's
Transco by December 15, 2001. Our decision will be made once the details of the
transmission companies are finalized. The transfer of control of our
transmission facilities to an RTO has the potential to materially affect our
results of operations and financial condition.
Wholesale energy markets, including the market for wholesale electric
power, have been competitive and are becoming even more so as the number of
participants in these markets increases as a result of enactment of the Energy
Policy Act and the regulatory activities of the FERC.
Retail Electric Competition
Currently, the LPSC does not provide exclusive service territories for
electric utilities under its jurisdiction. Instead, retail service is obtained
through the long-term, nonexclusive franchises described above under "--
Franchises." The LPSC uses a "300 foot rule" for determining the supplier for
new customers. The application of this rule has led to competition with
neighboring utilities for retail customers at the borders of our service areas.
We also compete in our service area with suppliers of alternative forms of
energy, some of which may be less costly than electricity for certain
applications. We could experience some competition for electric sales to
industrial customers in the form of cogeneration or from independent power
producers. However, we believe that our rates and the quality and reliability
of our service place us in a favorable competitive position in current retail
markets, as we have ranked No. 1 in reliability among electric utility companies
in our state for the past two years, based upon annual filings in the LPSC
Reliability Order.
Legislative and Regulatory Changes and Matters
Various federal and state legislative and regulatory bodies are
considering a number of issues in addition to those discussed above that will
shape the future of the electric utility industry. Such issues include, among
others:
. the deregulation of retail electricity sales;
13
<PAGE>
. the ability of electric utilities to recover stranded costs;
. the repeal or modification of the 1935 Act;
. the unbundling of vertically integrated electric utility companies into
separate business segments or companies (i.e., generation, transmission,
distribution and retail energy service);
. the role of electric utilities, independent power producers and competitive
bidding in the construction and operation of new generating capacity; and
. the pricing of transmission service on an electric utility's transmission
system.
We are unable, at this time, to predict the outcome of these issues or their
effect on our financial position, results of operations or cash flows.
For information on certain regulatory matters and regulatory accounting
affecting us, see "--Management's Discussion and Analysis of Financial Condition
and Results of Operations--Financial Condition--Regulatory Matters" in "Item 2.
Financial Information" below.
ENVIRONMENTAL MATTERS
Environmental Quality
We are subject to numerous laws and regulations administered by federal,
state and local authorities to protect the environment. These statutory and
regulatory provisions impose various substantive requirements, the violation of
which may result in substantial fines and penalties. Environmental requirements
continue to increase as a result of new legislation, administrative actions and
judicial interpretations. Therefore, the precise future effects of existing and
potential requirements are difficult to determine. During 1999 and the first
nine months of 2000, our capital expenditures related to environmental
compliance totaled approximately $3.7 million and $0.5 million, respectively,
due largely to the installation of peaking cooling towers at one of our
generating stations in 1999. Expenditures related to environmental compliance
for the remainder of 2000 and for 2001 are estimated to total approximately $0.6
million and $1.3 million, respectively.
Air Quality
The State of Louisiana regulates emissions from each of our generating
units through regulations issued by the Air Quality Division (AQD) of the
Louisiana Department of Environmental Quality (LDEQ). In addition, the AQD
implements certain programs initially established by the federal Environmental
Protection Agency (EPA). The AQD establishes standards of performance or
requires permits for certain generating units in Louisiana. All of our
generating units are subject to these requirements.
The federal Clean Air Act Amendments of 1990 (the Act) established a
regulatory program to address the effects of acid rain and imposed restrictions
on sulfur dioxide (SO2)
14
<PAGE>
emissions from certain generating units. The Act essentially requires that
utilities, like us, must hold a regulatory "allowance" for each ton of SO2
emitted beginning in the year 2000. The EPA is required to allocate a set number
of allowances to each affected unit based on its historic emission levels. After
the initial allocation, we requested an adjustment to the allowance allocation
for Rodemacher Unit 2 because of an extended outage of the unit during one of
the years used in the EPA's calculation. Because the final allowance allocation
did not reflect the requested adjustment, we filed a petition for judicial
review of the EPA's action in May 1993 in the United States Court of Appeals for
the District of Columbia Circuit. In October 1995, the EPA signed a settlement
agreement in which it agreed to give Rodemacher Unit 2 the additional allowances
requested. In December 1996, the EPA published proposed changes to the Acid Rain
Program that would grant Rodemacher Unit 2 the additional allowances. In June
1998, the proposed changes were made final.
The Act also requires the EPA to revise nitrogen oxides (NOx) emission
limits for existing coal-fired boilers. In November 1996, the EPA finalized
rules lowering the NOx emission rate for certain boilers, including Rodemacher
Unit 2 and Dolet Hills Unit 1. Under this rule, Rodemacher Unit 2 and Dolet
Hills Unit 1 would have had to meet this new emission rate by January 1, 2000.
The rule also allows an option to "early elect," that is, achieve compliance
with a less restrictive NOx limit beginning January 1, 1997. We exercised this
option in December 1996. Early election protects us from any further reductions
in the NOx permitted emission rate until 2008. Rodemacher Unit 2 and Dolet Hills
Unit 1 were in compliance with the NOx early election limits in 1998, 1999 and
the first nine months of 2000 and are expected to continue to be in compliance
during the remainder of 2000 without undergoing significant capital
improvements. Significant future reductions in NOx emission limits may require
modification of burners or other capital improvements at either or both of these
units.
Water Quality
We have received from the EPA all National Pollutant Discharge
Elimination System (NPDES) permits required under the Clean Water Act for
discharges from our four generating stations. NPDES permits have fixed dates of
expiration and we have applied for renewal of these permits within the
applicable time periods. The Office of Water Resources of the LDEQ requires
facilities that discharge wastewater into Louisiana waters to obtain permits
from the Louisiana Pollution Discharge Elimination System (LPDES). We have
applied for and received LPDES permits for our four generating stations.
The federal Clean Water Act, which was passed in 1972, contains
provisions requiring the EPA to evaluate all bodies of water within its
jurisdiction to determine if they meet water quality standards and to establish
a program to bring noncompliant bodies of water into compliance with the
standards. Given the enormous number of bodies of water required to be
evaluated and the complexity of standards set forth in the Clean Water Act, the
EPA has not completed the requirements. In the last few years, environmental
groups have sued the EPA over the failure to address these requirements of the
Clean Water Act. In October 1999, the EPA received a federal court order to
develop and implement Total Maximum Daily Loadings (TMDLs) for all impacted
streams in Louisiana. The TMDLs will restrict the amount of specific covered
pollutants that may be discharged under revised permits that will incorporate
the limitations of TMDL. We are evaluating the potential impact of TMDL
limitations to our
15
<PAGE>
facilities. Similar court proceedings against the EPA are occurring throughout
the United States over enforcement of the federal Clean Water Act.
Solid Waste Disposal
The Solid Waste Division (SWD) of the LDEQ has adopted regulations and a
permitting system for the management and disposal of solid waste generated by
power stations. We have received all required permits from the SWD for the on-
site disposal of solid waste generated at our four generating stations.
Hazardous Waste Generation
We produce certain wastes at our four generating stations and at other
locations that are classified as hazardous. The Hazardous Waste Division of the
LDEQ regulates these wastes and has issued identification numbers to the sites
where such wastes are produced. We do not treat, store or dispose of these
wastes on-site; therefore, no permits are required. All hazardous wastes we
produce are disposed of at federally permitted hazardous waste disposal sites.
Toxics Release Inventory
The Toxics Release Inventory (TRI) is a part of the Emergency Planning
and Community Right to Know Act and is administered by the EPA. The TRI is an
annual reporting requirement for industrial facilities on about 650 substances
they release into air, water and land. The TRI ranks companies based on how much
of a particular substance they release on a state level and a parish (county)
level. On May 1, 1997, the EPA added seven new industry groups to the TRI,
including electric utility facilities. Before the 1997 additions, we were exempt
from the reporting requirements of the TRI. We submitted TRI reports on our 1998
activities before July 1, 1999. The EPA and LDEQ reported TRI data in May and
June 2000, respectively. The rankings do not result in any federal or state
penalties, but may result in adverse public perceptions of us. Management is
aware of the potential adverse effects and has taken steps to mitigate the
situation.
Electric and Magnetic Fields
The possibility that exposure to electric and magnetic fields (EMF)
emanating from electric power lines, household appliances and other electric
devices may result in adverse health effects or damage to the environment has
been a subject of current public attention. We fund research on EMFs through
various organizations. The scientific research conducted to date concerning the
effects of EMFs has not led to any definitive results, but research is
continuing. Lawsuits alleging that the presence or use of electric power
transmission and distribution lines has an adverse effect on health and/or
property values have arisen in several states against electric utilities and
others.
CUSTOMERS
No customer accounted for 10% or more of our electric operating revenues
in 1999 or the first nine months of 2000. Additional information regarding our
sales and revenues is set forth in "--Management's Discussion and Analysis of
Financial Condition and Results of Operations--Results of Operations" in
"Item 2. Financial Condition" below.
16
<PAGE>
EMPLOYEES
At September 30, 2000, we had 664 full-time employees. Employee
relations are good and we have not had any material work stoppage due to labor
disagreements.
17
<PAGE>
ITEM 2. FINANCIAL INFORMATION.
SELECTED FINANCIAL DATA
The following tables present our selected financial data. The data set
forth below should be read together with "--Management's Discussion and Analysis
of Financial Condition and Results of Operations" below and our historical
financial statements and the notes to those statements included in Annex F to
this registration statement. Our selected income statement data for the years
ended December 31, 1995, 1996, 1997, 1998 and 1999 and our selected balance
sheet data as of December 31, 1998 and 1999 are derived from audited financial
statements. Our selected income statement data for the nine months ended
September 30, 1999 and 2000 and our selected balance sheet data at September 30,
2000 have been derived from our unaudited interim financial statements, and
include, in the opinion of management, all adjustments (consisting only of
normal recurring accruals) necessary to present fairly the data for such
periods. Our financial information for periods prior to July 1, 1999 include the
results of former subsidiaries that were transferred to Cleco in connection with
the reorganization into a holding company structure.
<TABLE>
<CAPTION>
AS AND FOR THE AS AND FOR THE
NINE MONTHS ENDED YEAR ENDED
SEPTEMBER 30, DECEMBER 31,
----------------------- --------------------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AND DIVIDEND AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
Income Statement Data
---------------------
Operating Revenues $ 481,716 $ 618,855 $ 751,561 $ 515,175 $ 456,245 $ 437,121 $ 396,227
Net Income $ 49,290 $ 45,270 $ 55,636 $ 51,664 $ 50,402 $ 50,061 $ 46,651
Basic EPS $ 2.19 $ 2.01 $ 2.47 $ 2.30 $ 2.24 $ 2.23 $ 2.08
Diluted EPS $ 2.19 $ 2.01 $ 2.43 $ 2.24 $ 2.18 $ 2.16 $ 2.02
Cash dividends per $ 1.76 $ 2.63 $ 3.96 $ 1.61 $ 1.57 $ 1.53 $ 1.49
common share
Balance Sheet Data
------------------
Total Assets $1,310,646 $1,525,570 $1,418,145 $1,429,000 $1,361,044 $1,321,771 $1,266,034
Long-Term Debt, net $ 335,383 $ 360,322 $ 360,339 $ 343,042 $ 365,897 $ 340,859 $ 360,822
Redeemable Preferred Stock $ -0- $ -0- $ -0- $ 5,680 $ 6,120 $ 6,372 $ 6,610
</TABLE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis should be read in combination with
our audited and unaudited interim financial statements and the notes thereto
contained in Annex F to this registration statement.
We are an electric utility that contains LPSC jurisdictional generation,
transmission and distribution electric utility operations. We provide electric
utility services to approximately 249,000 retail and wholesale customers in 63
communities and rural areas in an approximately 14,000-square mile region in the
State of Louisiana. Effective July 1, 1999, we
18
<PAGE>
were reorganized into a holding company structure. This reorganization resulted
in the formation of Cleco as a new holding company, which became the owner of
all our outstanding common stock. In connection with the reorganization, we
transferred the shares of capital stock and member's equity of all our
subsidiaries to Cleco. Accordingly, financial statements and data in this
registration statement that pertain to the periods prior to our holding company
reorganization include amounts related to subsidiaries that are no longer our
subsidiaries.
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------------- --------------------------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Operating Revenues (IN THOUSANDS)
Base $247,369 $237,360 $306,225 $296,893 $278,412
Fuel cost recovery 214,799 151,918 202,565 190,387 177,833
Energy marketing 13,000 230,418 237,731 32,695 -
Affiliate revenues 7,781 4,259 7,816 - -
Customer credits (1,233) (5,100) (2,776) (4,800) -
-------- -------- -------- -------- --------
Total Operating Revenues $481,716 $618,855 $751,561 $515,175 $456,245
Operating Expenses
Fuel $126,437 $104,480 $146,825 $142,737 $136,009
Purchased power 94,425 52,966 65,303 53,011 44,590
Energy marketing 9,487 223,225 230,084 27,322 -
Other operations 58,192 54,217 75,856 71,066 64,618
Maintenance 24,372 23,321 29,369 30,285 23,286
Depreciation 37,162 37,345 49,285 48,369 45,890
Taxes other than income 27,786 27,425 35,870 35,420 33,422
Income taxes 25,974 24,794 27,272 26,666 27,729
Restructuring charges - - - - 1,891
Affiliate costs 6,420 3,880 6,397 - -
-------- -------- -------- -------- --------
Total Operating Expenses $410,255 $551,653 $666,261 $434,876 $377,435
-------- -------- -------- -------- --------
Operating Income $ 71,461 $ 67,202 $ 85,300 $ 80,299 $ 78,810
-------- -------- -------- -------- --------
Other income (expense), net (425) (14) (203) 862 2,295
Interest charges including amortization
of debt expense, premium and discount
and AFUDC 21,746 20,899 28,414 27,360 28,586
Preferred dividend requirements, net - 1,047 1,047 2,137 2,117
-------- -------- -------- -------- --------
Net income applicable to common stock $ 49,290 $ 45,270 $ 55,636 $ 51,664 $ 50,402
======== ======== ======== ======== ========
</TABLE>
Weather influences the demand for electricity, especially among
residential customers. Demand for electricity by commercial and industrial
customers is primarily dependent upon the strength of the economy in the service
territory and the nation and is less affected by weather. Sales to industrial
customers are also affected by the worldwide demand for wood products, since our
two largest customers are producers of such products. The following
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<PAGE>
charts compare the kilowatt-hour sales by customer class, for the years ended
December 31, 1999, 1998 and 1997 and the nine months ended September 30, 2000
and 1999.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
1999 1998 1997
-------------------------------------------------------------------------------------
MILLION PERCENT MILLION PERCENT MILLION PERCENT
KWH CHANGE KWH CHANGE KWH CHANGE
---------- ------------- ----------- ------------ ---------- -------------
<S> <C> <C> <C> <C> <C> <C>
Retail electric customers
Residential........................ 3,208 (0.7%) 3,230 13.8% 2,838 4.2%
Commercial......................... 1,597 4.4% 1,529 9.8% 1,393 4.1%
Industrial......................... 2,720 8.0% 2,518 2.1% 2,467 4.1%
Other retail....................... 574 3.4% 555 4.1% 533 1.3%
Sales for resale................... 373 (7.2%) 402 29.3% 311 6.9%
------ ----- ----- ----- ----- -----
Total sales to regular customers..... 8,472 2.9% 8,234 9.2% 7,542 4.1%
Short-term sales to other utilities.. 126 65.8% 76 (51.6%) 157 (52.4%)
Sales from marketing activities...... 5,815 467.3% 1,025 - - -
------ ----- ----- ----- ----- -----
Total electric sales....... 14,413 54.4% 9,335 21.2% 7,699 1.6%
====== ===== ===== ===== ===== =====
</TABLE>
FOR THE NINE MONTHS ENDED
SEPTEMBER 30,
--------------------------------------------------
2000 1999
----------------------------- -----------------
MILLION PERCENT MILLION
KWH Change kWh
--------------- ----------- -------------
Retail electric
customers
Residential......... 2,589 2.4% 2,529
Commercial.......... 1,290 2.9% 1,253
Industrial.......... 2,198 7.8% 2,039
Other retail........ 93 6.9% 87
Sales for resale.... 661 (4.7%) 694
----- ----- ------
Total sales to
regular customers.... 6,831 3.5% 6,602
Short-term sales to
other utilities...... 36 (70.5%) 122
Sales from marketing
activities........... 196 (96.7%) 5879
----- ----- ------
Total electric
sales...... 7,063 44.0% 12,603
===== ===== ======
During the last five years, electric sales growth to retail electric
customers averaged 5.6% and, based on current information, is expected to range
from 2% to 3% per year during the next five years. The levels of future sales
will depend upon factors such as weather conditions, customer conservation
efforts, retail marketing and business development programs, and the overall
economy of the service area. Some of the issues facing the electric utility
industry that could affect sales include deregulation, retail wheeling,
legislative and regulatory changes, retention of large industrial customers,
franchises and access to transmission systems.
Sales from energy marketing activities are primarily affected by
transmission constraints, demand versus supply, market prices and our marketing
strategies.
Changes in fuel and purchased power expenses reflect fluctuations in
generation mix, fuel costs, availability of economy power and deferral of
expenses for recovery from customers through fuel adjustment clauses in
subsequent months. The following tables show the amount and changes in fuel and
purchased power expenses for the years ended December 31, 1999, 1998 and 1997
and for the nine months ended September 30, 2000 and 1999.
20
<PAGE>
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------
1999 1998 1997
--------------------------------------------------------------------------
IN PERCENT IN PERCENT IN PERCENT
THOUSANDS CHANGE THOUSANDS CHANGE THOUSANDS CHANGE
--------- -------- --------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Fuel used for electric generation $146,825 2.9% $142,737 4.9% $136,009 17.6%
Power purchased.................. 65,303 23.2% 53,011 18.9% 44,590 (19.8%)
-------- ----- -------- ---- -------- -----
Total fuel expenses.... $212,128 8.4% $195,748 8.4% $180,599 5.4%
======== ===== ======== ==== ======== =====
Gas purchased for marketing...... $ 24,687 - - - - -
Power purchased for marketing.... $205,397 651.8% $ 27,322 - - -
</TABLE>
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------------
2000 1999
-------------------------- ------------
IN PERCENT IN
THOUSANDS CHANGE THOUSANDS
------------- ---------- -------------
Fuel used for electric generation.... $126,437 21.0% $104,480
Power purchased...................... 94,425 78.3% 52,966
-------- ----- --------
Total fuel expenses........ $220,862 40.3% $157,446
======== ===== ========
Gas purchased for marketing.......... $ 5,624 (71.3%) $ 19,619
Power purchased for marketing........ 2,107 (98.9%) 203,606
Option expense....................... $ 1,756 - -
Total marketing expenses... $ 9,487 (95.7%) $223,225
======== ===== ========
Nine Months Ended September 30, 2000 compared to Nine Months Ended September 30,
1999
Operating revenues for the nine months ended September 30, 2000, were
$137.1 million, or 22.2% less than the same period in 1999. The decrease in
operating revenues was due to a reduced level of trading activity, partially
offset by higher base, fuel and transmission revenues, along with increased
customer ancillary charges for disconnects and reconnects. Year-to-date base
revenues were higher than the same period in 1999 due to customer growth, warmer
weather, and higher large customer sales. KWh sales to residential customers
increased 2.4% compared to the same period in 1999, increasing base revenues for
the nine months ended September 30, 2000 by $2.4 million as compared to the same
period in 1999. KWh sales to industrial customers were 7.8% higher than the same
period in 1999 due to increased usage.
Fuel cost recovery revenues for the nine months ended September 30, 2000,
increased primarily from sales to residential customers, which increased $25.7
million, and sales to industrial customers, which increased $18.2 million in
relation to the same period in 1999. The increase in fuel cost recovery
revenues is related to higher kWh sales and increased natural gas prices for the
nine months ended September 30, 2000, compared to the same period in 1999.
Changes in fuel costs have historically had no effect on net income, as fuel
costs are generally recovered through fuel costs adjustment clauses that enable
us to pass on to customers substantially all changes in the cost of generating
fuel and purchased power. These adjustments are audited monthly and are
regulated by the LPSC (representing about 99% of the total fuel cost adjustment)
and the FERC. Until approval is received, the adjustments are subject to refund.
Energy marketing revenues for the nine months ended September 30, 2000,
decreased $217.4 million as compared to the same period in 1999. We have seen a
reduction in energy marketing revenues in 2000 when compared with prior years
due to a reduced level of energy trading activity. The reduced trading activity
resulted from a refinement of trading practices and from the transfer of
specific CPS generating assets to Evangeline.
21
<PAGE>
Affiliate revenues for the nine months ended September 30, 2000,
increased by $3.5 million or 82.7% compared to the same period in 1999. The
increase in affiliate revenues is primarily the result of leasing office space
to Cleco Support Group LLC (Support Group) beginning January 2000, as well as
providing supplemental line construction and line maintenance crews and selected
distribution and transmission engineering projects for Utility Construction &
Technology Solutions LLC (UtiliTech) and providing interconnection and
generation imbalance services to Evangeline. For more information see
"--Intercompany Transactions" in "Item 7. Certain Relationships and Related
Transactions" below.
Operating Revenues for the nine months ended September 30, 2000, were
decreased by a $1.2 million accrual for estimated customer credits, which was a
$3.9 million decrease from the $5.1 million accrual recognized for the same
period in 1999. Accruals for estimated customer credits may be required under
terms of an earnings review settlement reached with the LPSC in 1996. For more
information regarding the earnings review settlement, see "--Financial
Condition--Retail Rates" below.
Operating expenses decreased $141.4 million or 25.6% during the nine
months ended September 30, 2000, compared to the same period in 1999. The
decrease in operating expenses is primarily the result of a decrease in energy
marketing expenses, partially offset by increased capacity charges and higher
fuel costs. Energy marketing expenses decreased $213.7 million compared to the
same period in 1999 due to the same factors noted above for decreases in energy
marketing revenues. Offsetting the decrease in energy marketing expenses was an
increase of $63.4 million in fuel and purchased power for retail utility
operations due to the increased kWh sales and increased energy prices primarily
driven by increases in natural gas prices as compared to the first nine months
of 1999.
We purchase power from other power generators when the price of the
energy purchased is less than the cost to us of generating such energy from our
own facilities or when our generating units are unable to provide electricity to
satisfy our load. Thirty-five percent of our energy requirements during the
nine months ended September 30, 2000, were met with purchased power, compared to
30% for the corresponding period in 1999. The increase was caused by the
replacement of the CPS output with a power contract with Williams Energy and to
a lesser extent by outage for maintenance at Dolet Hills in 2000, both requiring
us to purchase more power in the third quarter of 2000 than we did in the third
quarter of 1999 to meet load requirements. The increase was also caused by
increased kWh sales in the first nine months of 2000 compared to the same period
of 1999.
Affiliate costs for the nine months ended September 30, 2000, increased
by $2.5 million or 65.5% compared to the same period in 1999. The increase in
affiliate costs is primarily due to the lease of office space to Support Group
beginning in January 2000, as well as providing supplemental line construction
and maintenance crews for UtiliTech and interconnection services to Evangeline.
For more information on these services, see "--Intercompany Transactions" in
"Item 7. Certain Relationships and Related Transactions" below. Maintenance and
depreciation expenses for the nine months ended September 30, 2000, remained
relatively flat compared to the same period in 1999.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Operating revenues for the year ended December 31, 1999, were 45.9%
greater than the same period in 1998. The increase was primarily due to
increased marketing activities. Electric marketing operation activities did not
commence until late in the second quarter of 1998
22
<PAGE>
and were still in start-up mode in the third quarter of 1998. Also contributing
to the increase was a 4.2% increase in base revenues. The increased sales were
attributable to above normal additions of commercial customers and continued
overall health of the economy in our service territory.
Approximately half of the $9.3 million increase in base revenues for the
year 1999, as compared to the same period in 1998, was due to a 2.9% increase in
sales to regular customers. The remainder of the increase was due to increased
transmission and miscellaneous revenues. Fuel cost recovery revenues collected
for the year 1999 increased $12.2 million, as increased demand for power
necessitated the purchase of more power on the wholesale market at higher prices
than in 1998.
Energy marketing revenues increased $205.0 million in 1999 as compared to
1998 due to growth and expansion in our electric marketing operation. Our
electric marketing operation commenced late in the second quarter of 1998 and
was not fully operational until 1999. The operation expanded from trading only
on the Into Entergy market in 1998 to also trading on the Cinergy market in
1999. Our electric marketing operation also started marketing natural gas in
1999.
The increase in sales to commercial and industrial customers during 1999
as compared to 1998 resulted primarily from increased economic growth in the
region served by us and in the United States generally.
Affiliate revenues for the year ended December 31, 1999, were $7.8
million greater than the same period in 1998 due to the formation of a holding
company on July 1, 1999. Prior to July 1999, all affiliates were subsidiaries
of the Company and their operations were included with those of the Company and
reflected in our income/ (expenses), net. For more information on affiliate
transactions after July 1, 1999, see Note L to the audited financial statements
included in Annex F to this registration statement.
Revenues in 1999 were decreased by a $2.8 million accrual for estimated
customer credits, a $2 million decrease from the $4.8 million accrued in 1998.
For more information see Note J to the audited financial statements included in
Annex F to this registration statement.
Operating expenses increased $231.4 million in 1999 as compared to 1998.
The increase in operating expenses was primarily the result of an increase in
energy marketing expenses. Our electric marketing operations were not fully
operational until 1999.
Total fuel expense increased $16.4 million in 1999. Total fuel expense
increased due primarily to increased demand from native load customers, which
necessitated the purchase of more power on the wholesale market at higher prices
than in 1998. During 1999, 27% of our energy requirements were met with
purchased power, up from 24% in 1998. Power purchased for marketing increased
due primarily to a full year of activity by our energy marketing operation in
1999. Natural gas marketing did not begin until 1999.
Interest expense for 1999 increased $1.1 million as compared to 1998.
The increase was due to higher interest rates on variable-rate, short-term debt
during 1999, higher interest expense on pollution control bonds due to the
refinancing of the bonds at a fixed rate, and the replacement of short-term debt
with medium-term notes in order to pre-fund the refinancing of
23
<PAGE>
medium-term notes. Other operations expense, maintenance and depreciation
expenses for the year 1999 remained relatively flat compared to the year 1998.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
Operating revenues in 1998 were reduced, compared to 1997, by a $4.8
million provision for customer rate refunds based on the 1996 LPSC settlement.
Approximately $18.4 million of the $58.9 million increase in 1998 operating
revenues was due to an increase in base revenues from a 9.2% growth in kWh sales
to regular customers. Approximately $32.7 million of the increase was due to
sales from energy marketing operations, which began in 1998.
Fuel cost recovery revenues collected in 1998 increased $12.5 million
over 1997 due to the increased demand for power, higher market prices for
purchased power and the increased use of natural gas as generating fuel instead
of coal and lignite.
The increase in sales to residential customers during 1998 as compared to
1997 resulted primarily from warmer-than-normal spring and summer seasons in
1998. Sales to residential customers were also boosted by the addition of 7,700
mostly residential customers on September 30, 1997, through the acquisition of
the business of a rural electric cooperative utility, Teche Electric
Cooperative, Inc. (Teche). Sales to commercial and industrial customers grew
from 1997 as a result of customer growth and increased economic growth in the
region served by us.
Operating expenses increased $57.4 million for the year 1998 as compared
to the same period in 1997. The increase in operating expenses was primarily
the result of an increase in energy marketing expenses. Our electric marketing
operations did not commence until late in the second quarter of 1998. Other
operations expense increased due to increases in staffing. Maintenance expenses
increased due to several unanticipated generating unit repairs due to mechanical
problems and increased right-of-way reclearing. Depreciation expense increased
primarily due to a full year of depreciation on property additions associated
with the acquisition of the Teche assets and planned additions to generation,
transmission and distribution facilities.
Total fuel expense increased $15.1 million in 1998 over 1997. The
increase was primarily a result of the increased demand for power, higher market
prices for purchased power, and the increased use of natural gas as generating
fuel instead of coal and lignite. Power marketing was in its first year of
operation in 1998. During 1998, 24% of our energy requirements were met with
purchased power, the same amount as in 1997.
Allowance for Funds Used During Construction
AFUDC represents the estimated cost of financing LPSC and FERC rate-
regulated construction work-in-progress and is not a current source of cash. A
return on and recovery of AFUDC is permitted by regulatory bodies in setting
rates charged for utility services. AFUDC for the first nine months of 2000
increased 45.9% due to increased short-term borrowings over the same period in
1999. AFUDC for 1999 decreased as a result of lower LPSC and FERC rate-
regulated construction expenditures. AFUDC for 1998 increased as a result of
higher LPSC and FERC rate-regulated construction. AFUDC accounted for 0.9% of
net income applicable to common stock in 1999, compared to 2.2% in 1998 and 0.9%
in 1997.
24
<PAGE>
Financial Condition
Liquidity and Capital Resources
Financing for construction requirements and operational needs is
dependent upon the cost and availability of external funds through capital
markets and from financial institutions. Access to funds is dependent upon
factors such as general economic conditions, regulatory authorizations and
policies and our credit rating.
At December 31, 1999 and 1998, we had $5.9 million and $68.4 million,
respectively, of short-term debt outstanding in the form of commercial paper and
bank loans. Short-term debt decreased as a result of the 1999 issuance of $50
million of medium-term notes by us. We used the proceeds from these medium term
notes to refinance $10 million in medium-term notes that matured in May 1999,
redeem $20 million of putable medium term notes in November 1999, and to pay
down short-term debt. At September 30, 2000, we had $61.8 million in short-term
debt outstanding. The increase in short-term debt as compared to December 30,
1999 was a result of $25 million in medium-term notes maturing and a normal lag
between higher-than-normal fuel costs and the recovery of those fuel costs from
customers. A $100 million revolving credit facility expired on June 15, 2000,
and a new $100 million, 364-day revolving credit facility was finalized
concurrently with the expiration. The $100 million facility supports the
issuance of commercial paper and other general corporate purposes.
Cash Generation and Cash Requirements--Cash Flows
During 1999, cash flows from operating activities generated $150.9
million, as shown in the audited Statements of Cash Flows included in Annex F to
this registration statement. Net cash provided by operating activities resulted
from net income, adjusted for noncash charges to income, and changes in working
capital. Net cash used in investing activities related to additions to property,
plant and equipment and changes in utility and nonutility investments. Net cash
used in financing activities resulted principally from the redemption of $82.4
million in commercial paper and $59.2 million in dividends paid. The outflows
were reduced by issuance of $50 million in long-term debt.
During the first nine months of 2000, cash flows from operating
activities generated $44.4 million as shown in the unaudited Interim Statement
of Cash Flows included in Annex F to this registration statement. Net cash
provided by operating activities resulted from net income, adjusted for noncash
charges to income, and changes in working capital. Net cash used in investing
activities related to additions to property, plant and equipment and changes in
utility and nonutility investments.
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<PAGE>
Cash Generation and Cash Requirements--Construction Overview
Our construction consists of assets that may be added to our rate base
with the cost, if considered prudent by the LPSC, being passed on to our
customers. Those assets earn a rate of return restricted by the LPSC and are
subject to the rate agreement described under "Retail Rates" below. Construction
consists of additions to our distribution system, improvements to our
transmission system and improvements at our generation stations.
In 1997, we acquired the assets of Teche for $22.4 million. The assets
consisted primarily of electric distribution lines and substations. The
purchase added approximately 7,700 mostly residential customers to our
distribution system.
In recent years, our construction program has consisted primarily of
enhancements to our transmission and distribution system and improvements at our
generating stations. Construction expenditures, excluding AFUDC, totaled $51.7
million in 1999, $53.9 million in 1998, excluding $40.1 million in repowering of
CPS which was subsequently transferred to Evangeline, $55.1 million in 1997,
excluding purchase of the Teche assets and $31.7 million for the first nine
months of 2000.
Construction expenditures, excluding AFUDC, for the fourth quarter of
2000 are estimated to be $22.3 million and for the five-year period ending 2004
are expected to total $225 million. About one-half of the planned construction
in the five-year period will support line extensions and substation upgrades to
accommodate new business and load growth. Some investment will be made to
rehabilitate older transmission, distribution and generation assets. We will
also continue to invest in technology to allow us to operate more efficiently.
In 1999, 100% of our construction requirements were funded internally, as
compared to 99.8% in 1998 and 100% in 1997. In the first nine months of 2000,
99% of our construction requirements were funded internally. For the five-year
period ending 2004, 99% of our construction requirements are expected to be
funded internally.
Cash Generation and Cash Requirements--Other Cash Requirements
Scheduled maturities of debt and preferred stock have totaled
approximately $25.0 million for the first nine months of 2000 and will total
approximately $154.6 million for the five-year period ending 2004. We are
currently pursuing becoming a "reporting person" under the Securities Exchange
Act of 1934 in order to file a debt securities shelf registration statement. We
expect to establish a new unsecured medium-term note program as part of this
shelf registration. The Company will use the notes to paydown commercial paper
balances and finance construction.
Retail Rates
Retail rates regulated by the LPSC accounted for approximately 66% of our
revenues in 1999 and 95.6% of our revenues in the first nine months of 2000.
The increase in the proportion of revenues affected by the rate making authority
of the LPSC is due to the decrease in energy marketing revenues, which prices
are primarily set by the wholesale market. Fuel costs and monthly fuel
adjustment billing factors are subject to audit by the LPSC. In the past, we
have sought increases in base rates to reflect the cost of service related to
plant facility
26
<PAGE>
additions and increases in operating costs. If we request an increase in our
rates, and adequate rate relief is not granted on a timely basis, our ability to
attract capital at reasonable costs to finance operations and capital
improvements might be impaired.
The LPSC elected in 1993 to review the earnings of all electric, gas,
water and telecommunications utilities it regulates to determine whether the
returns on equity of these companies were higher than returns that might be
awarded in the economic environment at the time. In 1996 the LPSC approved a
settlement of our earnings review, which provides our customers with lower
electricity rates. A base rate decrease of $3 million annually became effective
November 1, 1996, with a second decrease of an additional $2 million annually
effective January 1, 1998. The terms of this settlement were to be effective for
a five-year period. In February 1999, the period was extended three years until
2004 under an agreement with the LPSC to transfer the existing assets of CPS
from our LPSC-regulated rate base into Evangeline, which repowered the CPS
generating plant.
During the eight-year period ending September 30, 2004, an LPSC-approved
rate stabilization plan is in place. This plan allows us to retain all earnings
equating to a regulatory return on equity up to and including 12.25% on our
regulated utility operations. Any earnings which result in a return on equity
over 12.25% and up to and including 13% will be shared equally between us and
our customers. Any earnings above 13% will be fully refunded to customers. This
effectively allows us the opportunity to realize a regulatory rate of return of
up to 12.625%. As part of the rate stabilization plan, the LPSC will annually
review our revenues and return on equity. If we are found to be achieving a
regulatory return on equity above the minimum 12.25%, a refund will be made in
the form of billing credits during the month of September following the
evaluation period. Refunds of $6.1 million and $1.0 million were given in
September 1999 and September 2000 respectively, reflective of the earnings level
achieved in the previous earnings period. In October 2000, we agreed to pay an
additional $0.5 million in refund relating to the September 1999 period to be
paid to customers in September 2001. This additional refund was due to
information obtained by the LPSC while reviewing a complaint filed with the LPSC
by several line construction companies located within Louisiana. A reserve has
been established for this additional refund. For more information on this
complaint, see Note C to the unaudited interim financial statements included in
Annex F to this registration statement.
In November 1997, the LPSC issued an order in a generic docket that
promulgated new standards for the monthly Fuel Adjustment Clause (FAC) rate
filings of electric utility companies under its jurisdiction. The order adopted
new rules and procedures for the monthly FAC computation and changes in
reporting of fuel and purchased power cost. Although the order narrowed the
types of costs that can be included in the FAC, it offset this reduction with an
increase in base rates. New rate schedules that incorporate the shifting of
costs from FAC to base rates were calculated and subsequently approved by the
LPSC for implementation on January 1, 2000. The changes have not had
significant impacts to our financial position or results of operations.
Regulatory Matters
We have recorded regulatory assets and liabilities, primarily for the
effects of income taxes, as a result of past rate actions of regulators,
pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71). The effects of potential deregulation of
27
<PAGE>
the industry or possible future changes in the method of rate regulation could
require us to discontinue the application of SFAS No. 71, pursuant to SFAS No.
101, "Regulated Enterprises--Accounting for the Discontinuation of Application
of FASB Statement No. 71" (SFAS No. 101). At December 31, 1999, and September
30, 2000, we have recorded $18.7 million and $32.0 million, respectively, of
regulatory assets, net of regulatory liabilities, because of the regulatory
requirement to flow through the tax benefits of accelerated deductions to
current customers and an implied regulatory compact that future customers would
pay for additional taxes when we paid additional taxes. These differences occur
over the lives of relatively long-lived assets, up to 30 years or more. Under
the current regulatory and competitive environment, we believe that these
regulatory assets are fully recoverable. However, if in the future, as a result
of regulatory changes or increased competition, our ability to recover these
regulatory assets would not be probable, then to the extent that these
regulatory assets were determined not to be recoverable, we would be required to
write off or write down these assets.
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed of" (SFAS No. 121), establishes accounting
standards for determining if long-lived assets are impaired, and when and how
losses, if any, should be recognized. We believe that the net cash flows that
will result from the operation of our assets are currently sufficient to cover
the carrying value of the assets.
The Emerging Issues Task Force (EITF) assists the FASB in identifying
emerging issues affecting financial reporting. In 1997, the EITF reached a
consensus in Issue No. 97-4, "Deregulation of the Pricing of Electricity--Issues
Related to the Application of FASB Statements No. 71 and 101" (EITF No. 97-4).
EITF No. 97-4 specified that SFAS No. 71 should be discontinued at a date no
later than when the details of a transition plan toward the deregulation of
electric rates for all or a portion of the entity subject to such plan are
known. However, other factors could cause the discontinuation of SFAS No. 71
before that date. Additionally, EITF No. 97-4 establishes that regulatory
assets to be recovered through cash flows derived from another portion of the
entity which continues to apply SFAS No. 71 should not be written off, but
rather should continue to be considered regulatory assets of the separable
portion which will continue to apply SFAS No. 71.
Recent Accounting Standards
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133), effective for fiscal years
beginning after June 15, 1999. This statement establishes accounting and
reporting for derivative instruments, including certain derivative instruments
embedded in other contracts and for hedging activities. In June 1999, the FASB
issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB Statement No. 133" (SFAS No.
137), which changed the effective date of SFAS No. 133 to fiscal years beginning
after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, "Accounting
for Certain Derivative Instruments and Certain Hedging Activities" (SFAS No.
138), which modified certain provisions of SFAS No. 133.
We will implement the requirements of these accounting standards
effective January 1, 2001. In early 2000, we organized a cross-functional
project team for the implementation of SFAS No. 133, as amended. The team has
completed an inventory of
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<PAGE>
our financial instruments, commodity contracts and other commitments for the
purpose of identifying and assessing our derivative-related transactions.
We have entered into certain forward and option contracts for the future
purchase or sale of electricity and natural gas that meet the derivative
criteria of SFAS No. 133, as amended. We currently record changes in the fair
value (mark-to-market), due to changes in the underlying commodity prices, for
certain of these contracts in current earnings. These changes are influenced by
various market factors, including weather and the availability of regional
electric generation and transmission capacity. The cross-functional project team
has not yet determined the amount of other comprehensive income to be reflected
on statements of income and other comprehensive income. The team believes that
application of SFAS No. 133, as amended, will cause us to reflect certain
transactions in other comprehensive income based on the effectiveness of the
hedges.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The market risk inherent in our market risk sensitive instruments and
positions is the potential change arising from increases or decreases in the
short-, medium- and long-term interest rates and the commodity price of
electricity traded on the Into Entergy and Cinergy exchanges and the commodity
price of natural gas traded. Generally, our market risk sensitive instruments
and positions, such as instruments used to provide fuel to our retail utility
customers, are characterized as "other than trading" as defined by EITF No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF No. 98-10). However, we do have some positions that are
considered "trading", as defined by EITF No. 98-10, such as our positions in
energy marketing operations. Our exposure to market risk, as discussed below,
represents an estimate of possible changes in the fair value or future earnings
that would occur assuming possible future movements in the interest rates and
the commodity prices of electricity and natural gas. Management's views on
market risk are not necessarily indicative of actual results, nor do they
represent the maximum possible gains or losses. The views do represent, within
the parameters disclosed, what we estimate may happen.
Interest
We have entered into various fixed- and variable-rate debt obligations.
Please read Note E to the notes to the audited financial statements included in
Annex F to this registration statement for details regarding our debt
obligations.
Sensitivity to changes in interest rates for fixed-rate obligations is
computed by calculating the current fair market value using a net present value
model based upon a 1% change in the average interest rate applicable to such
debt. Sensitivity to changes in interest rates for variable-rate obligations is
computed by assuming a 1% change in the current interest rate applicable to such
debt.
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As of December 31, 1999, the carrying value of our long-term, fixed-rate
debt was approximately $386.2 million, with a fair market value of approximately
$380.1 million. Fair value was determined using quoted market prices. Each
1.0% change in the average interest rates applicable to such debt would result
in a change of approximately $20.2 million in the fair values of these
instruments. If these instruments are held to maturity, no change in fair value
will be realized. As of September 30, 2000, the carrying value and fair value
of our long-term, fixed-rate debt did not materially change from the values at
December 31, 1999.
As of December 31, 1999, the carrying value of our short-term, variable-
rate debt was approximately $5.9 million, which approximates the fair market
value. Each 1.0% change in the average interest rates applicable to such debt
would result in a change of approximately $60,000 in our pre-tax earnings. As of
September 30, 2000, the carrying value of our short-term, variable-rate debt was
approximately $61.7 million, which approximates the fair market value. Each
1.0% change in the average interest rates applicable to such debt would result
in a change of approximately $0.6 million in our pre-tax earnings.
We monitor our mix of fixed- and variable-rate debt obligations in light
of changing market conditions and from time to time may alter that mix by, for
example, refinancing balances outstanding under variable-rate commercial paper
program with fixed-rate debt.
Market Risk
Most of our positions are considered "other than trading" under EITF No.
98-10. However, we did have financial positions that were defined as "trading"
under EITF No. 98-10. We have in place controls to help minimize the risks
involved in marketing and trading. Such controls include a risk management
committee comprised of senior management, a risk manager and internal audit
personnel. The risk management committee receives a daily risk report
containing mark-to-market and value-at-risk (VAR) analysis. The risk management
committee has set parameters on the trading activities, such as a ceiling on the
daily VAR. At December 31, 1999, the mark-to-market for those positions was a
loss of $0.6 million. At September 30, 2000, the mark-to-market for those
positions was a gain of $0.3 million.
We utilize a VAR model to assess the market risk of our derivative
financial instruments. VAR represents the potential loss for an instrument from
adverse changes in market factors for a specified period of time and confidence
level. The VAR was estimated using historical simulation calculated on a daily
basis over a one-day period with a 99.7% confidence level and a holding period
of one day. Based on these assumptions, the total VAR for the year ended
December 31, 1999 is summarized below:
HIGH LOW AVERAGE AT DECEMBER 31, 1999
---- --- ------- --------------------
(In thousands)
$7,700 $21 $1,908 $93
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During the year 2000, we used a 95% confidence level for natural gas. The
99.7% confidence level remained for electricity positions. The difference in
confidence levels between natural gas and electricity positions is attributable
to the maturity, liquidity and greater depth of products in the natural gas
markets as compared to the immaturity and volatility of the electricity
markets. Reporting VAR using a 95% confidence level is also the industry
standard for natural gas. Based on these assumptions, the total VAR for the
nine months ended September 30, 2000 is summarized below:
HIGH LOW AVERAGE AT SEPTEMBER 30, 2000
---- --- ------- ----------------------
(In thousands)
$2,168 $18 $310 $107
ITEM 3. PROPERTIES.
All of our electric generating stations and all other electric operating
properties are located in the State of Louisiana. We consider all of our
properties to be well maintained, in good operating condition and suitable for
their intended purposes.
ELECTRIC GENERATING STATIONS
As of September 30, 2000, we either owned or had an ownership interest in
three steam electric generating stations and a gas turbine with a combined
electric generating capacity of 1,366,900 kW. For additional information
regarding our generating facilities, see "Operations--Power Generation" in "Item
1. Business" above.
ELECTRIC SUBSTATIONS AND LINES
As of September 30, 2000, we owned 86 transmission substations and 332
distribution substations. As of September 30, 2000, our transmission system
consisted of approximately 67 circuit miles of 500 kilovolt (kV) lines, 461
circuit miles of 230 kV lines, 661 circuit miles of 138 kV lines, and 21 circuit
miles of 69 kV lines. Our distribution system consisted of approximately 2,213
circuit miles of 34.5 kV lines and 12,196 circuit miles of other lines.
GENERAL PROPERTIES
We own various properties, which include a seven-story headquarters
office building, regional offices, a central warehouse, service centers,
telecommunications equipment and other facilities owned for general purposes.
TITLE
Our electric generating plants and certain other principal properties are
owned in fee. Electric transmission and distribution lines are located either
on private rights-of-way or along streets or highways by public consent.
Substantially all of our property, plant and equipment is subject to a
lien securing our obligations under an Indenture of Mortgage, which does not
impair the use of such properties in the operation of our business.
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ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All of our outstanding common stock is owned by our parent, Cleco. No
other class of our capital stock is issued and outstanding.
SECURITY OWNERSHIP OF MANAGEMENT
The table below shows the number of shares of Cleco common stock and
Cleco preferred stock beneficially owned as of September 30, 2000 by each of our
directors and named executive officers and all of our directors and named
executive officers as a group.
Shares are deemed to be "beneficially owned" by a person if such person
directly or indirectly has or shares the power to vote or to dispose of the
shares, regardless of whether such person has any economic interest in the
shares. In addition, a person is deemed to "beneficially own" any shares of
which such person has the right to acquire beneficial ownership within 60 days,
as in the case of the stock options that are set forth under the "Options
Exercisable Within 60 Days" column.
Shares of Cleco common stock listed under the "Direct" column are those
as to which each named individual has sole voting or dispositive power,
including shares held under Cleco's Savings and Investment Plan and shares
granted as restricted stock awards under Cleco's Long-Term Incentive Plan. Mr.
Darrell J. Dubroc holds 628 shares under Cleco's Savings and Investment Plan.
The other executive officers included in the amount shown for all directors and
named executive officers as a group hold 2,200 shares under Cleco's Savings and
Investment Plan.
Shares listed under the "Other" column are those as to which the named
individual shares voting and dispositive power with another person. The shares
of Cleco preferred stock beneficially owned by the individuals indicated in the
table are shares held for the respective accounts of executive officers under
Cleco's Savings and Investment Plan.
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<PAGE>
<TABLE>
<CAPTION>
AMOUNT AND NATURE
OF BENEFICIAL
AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP OF
OWNERSHIP OF CLECO COMMON STOCK CLECO PREFERRED STOCK
----------------------------------------------- ------------------------
OPTIONS
EXERCISABLE
WITHIN 60 PERCENT NUMBER OF PERCENT
DIRECT DAYS OTHER OF CLASS SHARES (1) OF CLASS
--------- ----------- ----------- -------- ------------- --------
<S> <C> <C> <C> <C> <C> <C>
Directors
Sherian G. Cadoria............. 1,000 2,500 0 * 0 *
Richard B. Crowell............. 25,447 2,500 55,992 (2) * 0 *
David M. Eppler (3)............ 21,837 0 2,880 (4) * 600 *
J. Patrick Garrett............. 18,915 4,167 0 * 0 *
F. Ben James, Jr............... 5,000 4,167 0 * 0 *
Elton R. King.................. 1,288 2,778 0 * 0 *
A. DeLoach Martin, Jr.......... 18,800 4,167 0 * 0 *
Robert T. Ratcliff............. 1,495 3,334 0 * 0 *
Edward M. Simmons.............. 5,847 3,334 1,400 (5) * 0 *
William H. Walker, Jr.......... 51,718 3,334 1,400 (6) * 0 *
Named Executive Officers
Darrell J. Dubroc.............. 6,903 (7) 0 1,646 (4) * 343 *
Thomas J. Howlin............... 6,491 0 562 (4) * 117 *
Catherine C. Powell............ 7,928 0 1,781 (4) * 371 *
Mark H. Segura................. 6,536 0 1,656 (4) * 345 *
All directors and
executive officers as a
group (18 persons, including
those listed above)........... 211,507 30,281 725,997 (8) 4.30 139,001(8) 49.48
</TABLE>
___________________
* Less than 1% of class.
(1) Represents the number of shares of preferred stock allocated under
Cleco's Savings and Investment Plan that are convertible into Cleco
common stock.
(2) Includes 55,992 shares owned by members of Mr. Crowell's family and
family trusts, for which beneficial ownership is disclaimed.
(3) Mr. Eppler is also our president and chief executive officer.
(4) Represents the number of shares of Cleco common stock into which Cleco
preferred stock held in Cleco's Savings and Investment Plan is
convertible.
(5) Includes 1,400 shares owned by Mr. Simmons' spouse and a family trust,
for which beneficial ownership is disclaimed.
(6) Includes 1,400 shares owned by a family trust, for which beneficial
ownership is disclaimed.
(7) Includes common stock allocated to Mr. Dubroc's account in Cleco's
Savings and Investment Plan over which he has voting power and investment
discretion.
(8) Cleco's Savings and Investment Plan holds Cleco preferred stock that is
convertible, at any time, into shares of Cleco common stock. 135,775
shares of Cleco preferred stock, convertible into 651,720 shares of Cleco
common stock (2.9% of such common stock), have not yet been allocated to
accounts of participants in the plan. Executive officers of Cleco serve
with other Cleco employees as the administrators of the plan and,
effective as of January 1, 1999, make voting decisions with respect to
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<PAGE>
the unallocated shares. The unallocated shares have been included only
once in calculating the beneficial ownership of all officers and
directors as a group.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth as of the dates indicated, to our
knowledge based on a review of the information indicated, certain information
with respect to each person who is the beneficial owner of more than 5% of the
outstanding shares of any class of Cleco's voting securities:
<TABLE>
<CAPTION>
AMOUNT AND NATURE
NAME AND ADDRESS OF OF BENEFICIAL
TITLE OF CLASS BENEFICIAL OWNER OWNERSHIP PERCENT OF CLASS
-------------- -------------------- ------------------ ----------------
<S> <C> <C> <C>
Preferred Stock UMB Bank, N.A.
Trustee of Cleco's Savings and
Investment Plan
1010 Grand Boulevard,
Kansas City, MO 64106 270,609(1) 93.7
Common Stock T. Rowe Price Associates, Inc.
100 E. Pratt Street
Baltimore, Maryland 21202 1,301,400(2) 5.8
</TABLE>
-----------------
(1) Based upon information contained in Cleco's records and those of Cleco's
transfer agent as of September 30, 2000. Such 270,609 shares are held by
UMB Bank, N.A., as Trustee of Cleco's Savings and Investment Plan. Such
270,609 shares are convertible under certain circumstances pursuant to
Cleco's articles of incorporation, and the governing instruments of
Cleco's Savings and Investment Plan, into 1,298,923 shares of Cleco
common stock, subject to antidilution adjustment, or approximately 5.8%
of the Cleco common stock outstanding as of September 30, 2000.
Participants in Cleco's Savings and Investment Plan have voting rights
with respect to shares of Cleco preferred stock allocated to their
accounts. The Trustee is required to vote unallocated shares in
accordance with instructions received from the administrator of Cleco's
Savings and Investment Plan. The Trustee holds 515,242 shares of Cleco
common stock. The Trustee may vote shares of Cleco common stock
allocated to a participant's account only in accordance with instructions
received from the participant. The combined holdings of the Trustee
under Cleco's Savings and Investment Plan, on an as-converted basis with
regard to the Cleco preferred stock, are 1,814,165 shares, or 8.1%, of
the outstanding shares of Cleco common stock as of September 30, 2000.
(2) As of December 31, 1999, based solely on a Schedule 13G filed with the
Securities and Exchange Commission. These securities are owned by
various individual and institutional investors for which T. Rowe Price
Associates, Inc., serves as investment adviser with power to direct
investments and/or sole power to vote the securities. For purposes of
the reporting requirements of the Securities Exchange Act of 1934, T.
Rowe Price is deemed to be a beneficial owner of such securities;
however, T. Rowe Price expressly disclaims that it is, in fact, the
beneficial owner of such securities.
34
<PAGE>
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS.
The following table sets forth certain information with respect to our
directors and executive officers as of September 30, 2000:
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
David M. Eppler 50 President, Chief Executive Officer and Director
(Chief executive officer since May 2000, president since January 1999,
director since April 1998. Chief operating officer from July 1997 to
May 2000. Executive vice president from January 1997 until January
1999. Vice president of power supply and energy transmission from 1995
to 1997. Vice president of finance and chief financial officer from
1993 to 1995.)
Mark H. Segura 41 Executive Vice President and Chief Operating Officer
(Executive vice president and chief operating officer since January
2000. Senior vice president of utility operations from April 1999 to
January 2000. Vice president of distribution services from July 1997
to April 1999. General manager of distribution services from July 1996
to July 1997. Manager of stores and transformer management from
October 1993 to July 1996.)
Thomas J. Howlin 52 Senior Vice President-Financial Services and Chief Financial Officer
(Senior vice president of finance and chief financial officer since
July 1997. Vice president and chief financial officer of TransAmerican
Natural Gas Corporation from April 1995 to March 1997.)
Catherine C. Powell 44 Senior Vice President-Employee and Corporate Services
(Senior vice president of employee and corporate services since July
1997. Vice president of employee and corporate services from July 1995
to July 1997.)
Darrell J. Dubroc 39 Vice President-Generation Services
(Vice president of generation services since July 1997. General
manager of wholesale merchant operations from July 1996 to July 1997.
Manager of regulatory affairs and business development from March 1995
to July 1996.)
</TABLE>
35
<PAGE>
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
Sherian G. Cadoria 60 Director
(President of Cadoria Speaker and Consultancy Service since 1992.
Retired in 1990 as Brigadier General of the United States Army after a
29-year military career. Director since 1993. Member of the joint
Compensation Committee for Cleco and the Company.)
Richard B. Crowell 62 Director
(Engaged in the practice of law for more than five years as a member of
the law firm of Crowell & Owens. Director since 1997. Member of the
joint Audit Committee for Cleco and the Company. Director of Whitney
Holding Corporation and Whitney National Bank.)
J. Patrick Garrett 57 Director
(Retired. President and chief executive officer of Windsor Food
Company Ltd., a privately held company engaged in the food processing
business, from 1995 until 1999. Prior to 1995, engaged in the practice
of law as a member of the law firm of Baker Botts L.L.P. Director
since 1981. Member of the joint Compensation Committee for Cleco and
the Company.)
F. Ben James, Jr. 64 Director
(President of James Investments, Inc., a company primarily engaged in
real estate development and international marketing, for more than five
years. Director since 1986. Chairman of the joint Audit Committee for
Cleco and the Company. Member of the joint Executive Committee for
Cleco and the Company.)
Elton R. King 54 Director
(Retired. Employed by BellSouth Telecommunications, Inc. from 1968
through 1999, most recently as the president of its network and carrier
services group. Director since December 1999. Member of the joint
Compensation Committee for Cleco and the Company. Director of Hibernia
Corporation and Hibernia National Bank.)
A. DeLoach Martin, Jr. 70 Director
(Chairman of Central Engineering & Supply Company, a company engaged in
the wholesale distribution of refrigeration and mill supplies, for more
than five years. Director since 1978. Chairman of the joint Executive
Committee for Cleco and the Company. Member of the joint Audit
Committee for Cleco and the Company.)
</TABLE>
36
<PAGE>
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
Robert T. Ratcliff 58 Director
(Chairman, president and chief executive officer of Ratcliff
Construction Company, Inc., a company primarily engaged in the design
and construction of industrial, commercial and governmental facilities,
since 1975. Director since 1993. Member of the joint Audit Committee
for Cleco and the Company. Director of Hibernia Corporation and
Hibernia National Bank.)
Edward M. Simmons 72 Director
(Since 1996, chairman of the board and chief executive officer of
McIlhenny Company, which makes Tabasco brand products. Prior to 1996,
president of McIlhenny Company for more than five years. Director
since 1992. Previous director of the Company from 1971 - 1981.
Chairman of the joint Compensation Committee for Cleco and the Company.
Member of the joint Executive Committee for Cleco and the Company.
Director of Pan American Life Insurance Company.)
William H. Walker, Jr. 55 Director
(President and a director of Howard, Weil, Labouisse, Friedrichs Inc.,
an investment banking firm, and has served in such positions for more
than five years. Director since 1996. Member of the joint
Compensation and Executive Committees for Cleco and the Company.
Director of Howard Weil Financial Corporation.)
</TABLE>
37
<PAGE>
ITEM 6. EXECUTIVE COMPENSATION.
The following table sets forth all compensation paid or accrued to our
chief executive officer and our four other most highly compensated executive
officers for services rendered in all capacities to us and Cleco for the fiscal
years 1999, 1998 and 1997. Mr. Gregory L. Nesbitt, who served as our chief
executive officer during those years, retired on May 1, 2000. Upon Mr.
Nesbitt's retirement, Mr. Eppler was elected to serve as our chief executive
officer.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
NAME AND OTHER ANNUAL LTIP ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS (1) COMPENSATION (2) PAYOUTS (3) COMPENSATION (4)
------------------------ ---- --------- ---------- ---------------- ----------- ----------------
<S> <C> <C> <C> <C> <C> <C>
Gregory L. Nesbitt...... 1999 $348,081 $216,248 $27,200 $367,109 $6,400
Retired Chief 1998 334,623 176,090 21,645 184,859 6,400
Executive Officer 1997 296,770 126,000 16,840 141,488 6,334
David M. Eppler......... 1999 $236,923 $131,808 $12,198 $132,165 $6,776
President and Chief 1998 205,389 90,300 8,000 64,862 6,924
Executive Officer 1997 166,478 54,000 5,837 43,687 6,836
Thomas J. Howlin........ 1999 $174,007 $ 80,459 $ 5,818 $ 0 $7,111
Senior Vice President 1998 167,424 70,690 2,417 0 5,217
--Financial Services 1997 69,454 71,500 0 0 4,085
and Chief Financial
Officer (Hired in
July 1997)
Catherine C. Powell..... 1999 $134,231 $ 66,074 $ 6,499 $ 86,223 $6,565
Senior Vice President-- 1998 128,334 48,380 5,047 44,453 6,624
Employee and Corporate 1997 111,023 33,660 4,044 29,515 6,188
Services
Mark H. Segura.......... 1999 $138,352 $ 61,318 $ 4,457 $ 51,389 $6,565
Executive Vice 1998 114,236 50,480 2,533 0 9,621
President and Chief 1997 102,692 22,799 1,137 0 8,405
Operating Officer
Darrell J. Dubroc....... 1999 $154,081 $ 65,616 $ 5,394 $ 53,921 $6,476
Vice President-- 1998 147,039 53,120 3,098 0 6,474
Generation Services 1997 118,656 36,910 1,287 0 9,964
</TABLE>
-------------
(1) The "Bonus" column includes cash awards that are payable or have been paid
to executive officers pursuant to the following:
. Cleco's annual incentive compensation program under which participants may
receive incentive compensation determined by the performance of Cleco and the
individual participants;
. merit lump-sum payments received by certain named executive officers; and
. payments received under Cleco's spot award incentive plan, which rewards
individual performance.
38
<PAGE>
(2) For 1999, 1998 and 1997, the "Other Annual Compensation" column includes
dividends paid on Cleco restricted stock awards under the Long-Term
Incentive Plan. Dividends on Cleco restricted stock are paid quarterly and
at the same rate as dividends on the Cleco common stock.
(3) Cleco restricted stock awards granted under its Long-Term Incentive Plan are
reported under the "Long-Term Incentive Plan-Awards in 1999" table below.
The number and value of the aggregate restricted stock holdings at December
31, 1999, a portion of which is included in the "LTIP Payouts" column, for
each of the named executive officers were as follows:
. Mr. Nesbitt - 16,485 shares with a value of $528,550;
. Mr. Eppler - 7,393 shares with a value of $237,038;
. Mr. Howlin - 3,526 shares with a value of $113,052;
. Ms. Powell - 3,939 shares with a value of $126,294;
. Mr. Segura - 2,701 shares with a value of $86,601; and
. Mr. Dubroc - 3,269 shares with a value of $104,812.
The "LTIP Payouts" column includes the value of Cleco restricted stock
and opportunity shares under Cleco's Long-Term Incentive Plan that vested in the
following years and the related tax gross-up amounts:
. 1999 - relating to the performance period January 1, 1996 to December 31,
1998;
. 1998 - relating to the performance period January 1, 1995 to December 31,
1997; and
. 1997 - relating to the performance period January 1, 1994 to December 31,
1996.
(4) The "All Other Compensation" column includes the following:
Amounts contributed or accrued by Cleco under its Savings and Investment Plan on
behalf of the named executive officers as follows:
1997 1998 1999
------ ------- ------
Mr. Nesbitt................. $6,334 $6,400 $6,400
Mr. Eppler.................. $6,333 $6,400 $6,400
Mr. Howlin.................. $ 0 $4,237 $6,400
Ms. Powell.................. $5,973 $6,400 $6,400
Mr. Segura.................. $4,106 $6,018 $6,400
Mr. Dubroc.................. $4,881 $6,400 $6,400
39
<PAGE>
Term life insurance premiums paid for the benefit of the named executive
officers as follows:
1997 1998 1999
------ ------ ------
Mr. Eppler................. $ 503 $ 524 $ 376
Mr. Howlin................. $ 210 $ 980 $ 711
Ms. Powell................. $ 215 $ 224 $ 165
Mr. Segura................. $ 68 $ 218 $ 165
Mr. Dubroc................. $ 71 $ 74 $ 76
Unused vacation purchased from the named executive officers as follows:
1997 1998 1999
------ ------ ------
Mr. Howlin................. $3,875 $ 0 $ 0
Mr. Segura................. $4,231 $3,385 $ 0
Mr. Dubroc................. $5,012 $ 0 $ 0
DIRECTOR COMPENSATION
Each of our directors is a director of Cleco and is not separately
compensated by us or Cleco for services on our board of directors or any
committee of our board of directors.
BOARD COMMITTEES
Our board of directors has an Executive Committee, an Audit Committee and
a Compensation Committee. The members of those committees are identified in
"Item 5. Directors and Executive Officers" above. Our board of directors has no
standing nominating committee.
SEVERANCE AGREEMENTS
Cleco has severance agreements with Mr. Eppler, Mr. Howlin, Ms. Powell,
Mr. Segura and Mr. Dubroc and other executive officers and general managers of
Cleco. Each agreement provides generally for the payment of a minimum annual
salary, participation in all Cleco benefit plans and programs applicable to
Cleco's executive officers and reimbursement of employment-related expenses
incurred during the term of employment. Under the severance agreements, the
2000 base salaries for the individuals named in the Summary Compensation Table
are as follows:
Mr. Eppler $300,000
Mr. Howlin $195,000
Ms. Powell $160,000
Mr. Segura $175,000
Mr. Dubroc $180,000
Mr. Eppler's base salary increased to $325,000 in connection with his assumption
of the position of Cleco's chief executive officer upon Mr. Nesbitt's retirement
in May 2000.
40
<PAGE>
Each severance agreement provides for an initial three-year term that
renews annually for one additional year, unless either Cleco or the executive
officer gives notice prior to renewal that such officer's term of employment
will not be extended. The agreements for Mr. Eppler, Mr. Howlin, Ms. Powell, Mr.
Segura and Mr. Dubroc include provisions governing the payment of severance
benefits in an amount equal to the executive's annual base salary if the
executive's employment is terminated (a) by Cleco for any reason, other than a
material breach by the executive, or (b) by the executive following a reduction
in base salary, other than a reduction in pay uniformly applicable to all
officers, or a significant reduction in the executive's authority, duties or
responsibilities. The executive also is entitled to continued health plan
coverage for up to 18 months after such termination, and the executive is
entitled to require Cleco to (a) purchase his or her principal residence, if it
is located within 60 miles of Cleco's Pineville office, for an amount equal to
the greater of (i) the purchase price of the residence plus the cost of capital
improvements or (ii) the fair market value of the residence, and (b) pay or
reimburse the executive for relocation costs. Lesser severance benefits are
payable to other executive officers and managers.
If a change in control, as defined in the agreement, occurs and within
three years after the change in control the executive's employment is terminated
by Cleco for reasons other than a material breach or the executive terminates
his or her employment for good reason, as defined in the agreement, then Cleco
is obligated to pay the executive, in lieu of any severance obligation otherwise
payable under the agreement, an amount equal to three times the executive's
average compensation paid during the five calendar years preceding the change in
control. In the event of a change in control, payments under the agreements for
the named executive officers, using the average compensation for the years 1995
through 1999, will be approximately as follows:
Mr. Eppler $855,400
Mr. Howlin $705,500
Ms. Powell $488,600
Mr. Segura $338,900
Mr. Dubroc $402,800
However, the severance agreements limit the amount payable upon a change
in control to an amount that will not result in the disallowance of a deduction
to Cleco under the "golden parachute" provisions of the Code or the imposition
of an excise tax on the employee under Section 4999 of the Code. Lesser change
in control benefits are provided to other executive officers and managers.
The severance agreements also generally require the executives not to
disclose confidential information relating to Cleco and, for a period of one
year after termination, not to hire Cleco officers, employees or agents, or
solicit or divert any customer or supplier of Cleco.
BENEFIT PLANS
We do not have separate benefit plans for our executive officers and
directors. All of our executive officers and directors participate in the
benefit plans of Cleco. The following discussion describes the benefit plans of
Cleco in which our executive officers and directors participate.
41
<PAGE>
Nonemployee Director Plans
Our nonemployee directors may participate in Cleco's deferred
compensation plan. Under the plan, a director may elect to defer all or part of
his or her fees. Our nonemployee directors also may participate in Cleco's
nonemployee director retirement plan under which directors with five years of
service receive, at age 65 or upon later retirement, a maximum annual benefit of
$12,000. Benefits are payable for life or a period equal to the number of years
of service as a director, whichever is shorter. Additionally, Cleco provides
our nonemployee directors with $200,000 of life insurance and permanent total
disability coverage under its group accidental death and dismemberment plan,
which covers all active, full-time employees.
Stock Option Plans
Cleco currently maintains two plans pursuant to which options to purchase
shares of common stock are outstanding. The first is the 1990 Long-Term
Incentive Plan, which was amended and restated effective April 24, 1998,
pursuant to which certain of our officers and key employees may receive
restricted stock, stock options or stock appreciation rights, among other
awards. An aggregate of 800,000 shares of Cleco common stock has been reserved
for issuance under this plan. It expired on January 1, 2000, and no additional
grants can be made under the plan. As of September 30, 2000, grants or awards
representing 537,700 shares of Cleco common stock had been made under the plan.
In April 2000, Cleco's stockholders approved the 2000 Long-Term Incentive
Compensation Plan, effective as of January 1, 2000. Under this plan, certain
officers, employees and nonemployee directors may receive restricted stock,
stock options or stock appreciation rights, among other awards. An aggregate of
800,000 shares of Cleco common stock has been reserved for issuance under this
plan. As of September 30, 2000, grants or awards representing 85,900 shares of
Cleco common stock had been made under the plan.
The following table sets forth, for each of the persons listed in the
Summary Compensation Table, the following information concerning nonqualified
stock options granted during 1999:
. the number of shares of Cleco common stock underlying options granted during
1999;
. the percent such grants represent of the total number of options granted to
Cleco employees in 1999;
. the per share exercise price and expiration date of such options; and
. the potential realizable value of each such grant of options, assuming that
the market price of Cleco common stock appreciates from the date of grant to
the end of the option term at a 5% and 10% compound annual rate.
42
<PAGE>
OPTION GRANTS IN 1999
<TABLE>
<CAPTION>
POTENTIAL REALIZABLE
VALUE AT ASSUMED
ANNUAL RATES OF
STOCK PRICE APPRECIATION
INDIVIDUAL GRANTS FOR OPTION TERM
----------------------------------- ------------------------
NUMBER OF % OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO EXERCISE
OPTION GRANTED EMPLOYEES PRICE EXPIRATION
NAME (1) IN 1999 ($/SHARE) DATE 5% ($)(2) 10% ($)(2)
----------------------- -------------- ---------- -------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Gregory L. Nesbitt..... 24,000 (3) 4.5 32.25 05/01/03 136,853.29 290,345.64
David M. Eppler........ 12,000 (4) 2.2 32.25 07/23/09 243,382.22 616,778.33
20,000 (5) 3.7 38.41 07/23/09 214,513.40 737,464.73
20,000 (6) 3.7 40.71 07/23/09 143,152.30 628,999.14
20,000 (7) 3.7 43.16 07/23/09 67,137.22 513,459.70
Thomas J. Howlin....... 6,800 (4) 1.3 32.25 07/23/09 137,916.59 349,507.72
13,333 (5) 2.5 38.41 07/23/09 143,005.36 491,630.86
13,333 (6) 2.5 40.71 07/23/09 95,432.48 419,322.27
13,334 (7) 2.5 43.16 07/23/09 44,760.38 342,323.58
Catherine C. Powell.... 4,100 (4) 0.8 32.25 07/23/09 83,155.59 210,732.60
10,000 (5) 1.9 38.41 07/23/09 107,256.70 368,732.37
10,000 (6) 1.9 40.71 07/23/09 71,576.15 314,499.57
10,000 (7) 1.9 43.16 07/23/09 33,568.61 256,729.85
Mark H. Segura......... 4,700 (4) 0.9 32.25 7/23/09 95,324.70 241,571.15
8,333 (5) 1.5 38.41 7/23/09 89,377.00 307,264.68
8,333 (6) 1.5 40.71 7/23/09 59,644.41 262,072.49
8,334 (7) 1.5 43.16 7/23/09 27,976.08 213,958.66
Darrell J. Dubroc...... 5,500 (4) 1.0 32.25 07/23/09 111,550.18 282,690.07
13,333 (5) 2.5 38.41 07/23/09 143,005.36 491,630.86
13,333 (6) 2.5 40.71 07/23/09 95,432.48 419,322.27
13,334 (7) 2.5 43.16 07/23/09 44,760.38 342,323.58
</TABLE>
---------------
(1) All options would immediately vest upon a change of control as defined in
Cleco's Long-Term Incentive Plan. A "change of control" is generally deemed
to have occurred if (a) any person or group becomes the direct or indirect
beneficial owner of 20% or more of Cleco's outstanding voting securities;
(b) the majority of Cleco's board changes, except in certain cases; (c) as a
result of a merger or consolidation, less than 80% of the surviving
corporation's outstanding voting securities are owned by former Cleco
shareholders (excluding the affiliates of any party to the transaction); (d)
Cleco transfers all or substantially all of its assets; (e) Cleco's
43
<PAGE>
shareholders approve a plan of dissolution or liquidation; or (f) certain
other significant events that Cleco would be required to report in a proxy
statement.
(2) These columns show the gains the named executive officers could realize if
the market price of Cleco common stock appreciates at a 5% or 10% compound
annual rate. These growth rates are arbitrary assumptions specified by the
SEC, not our predictions.
(3) Cleco's Long-Term Incentive Plan provides that if a person's employment with
Cleco is terminated on account of early or late retirement under Cleco's
pension plan, such person is entitled to exercise options granted under the
Long-Term Incentive Plan, in whole or in part, during the three-year period
following the date of retirement, provided such exercise occurs after the
one-year anniversary of the grant. Based on Mr. Nesbitt's retirement on May
1, 2000, the options granted to him on July 23, 1999 will be exercisable
after July 23, 2000 until May 1, 2003.
(4) These option grants vest in one-third increments per year, beginning on the
third anniversary of the date of grant, so long as the officer remains an
employee.
(5) These option grants vest on the third anniversary of the date of grant, so
long as the officer remains an employee.
(6) These option grants vest on the fourth anniversary of the date of grant, so
long as the officer remains an employee.
(7) These option grants vest on the fifth anniversary of the date of grant, so
long as the officer remains an employee.
The following table sets forth, for each of the persons listed in the
Summary Compensation Table, the following information concerning stock options
exercised during 1999:
. the number of shares of Cleco common stock acquired upon the exercise of
options during 1999;
. the aggregate dollar value realized upon the exercise of such options; and
. the total number of exercisable and unexercisable options held on December
31, 1999.
None of these persons held any in-the-money options on December 31, 1999.
44
<PAGE>
AGGREGATE OPTIONS EXERCISED IN 1999 AND YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES
SHARES UNDERLYING UNEXERCISED
ACQUIRED OPTIONS AT DECEMBER 31, 1999
ON VALUE ---------------------------------------
NAME EXERCISE REALIZED ($) EXERCISABLE UNEXERCISABLE
---- -------- ------------ --------------- ------------------
<S> <C> <C> <C> <C>
Gregory L. Nesbitt............ 2,000 33,440 0 24,000
David M. Eppler............... 2,800 36,491 0 72,000
Thomas J. Howlin.............. 0 0 0 46,800
Catherine C. Powell........... 0 0 0 34,100
Mark H. Segura................ 0 0 0 29,700
Darrell J. Dubroc............. 0 0 0 45,500
</TABLE>
Long-Term Incentive Plan
The following table sets forth, for each of the persons listed in the
Summary Compensation Table, information related to grants under Cleco's Long-
Term Incentive Plan during 1999. The amounts listed in the "Number of Shares"
column represent the performance-based restricted stock granted to the named
executive officers in 1999. The recipient of a restricted stock grant is the
record owner of the number of target shares awarded, which are issued in the
name of the recipient but held in escrow by Cleco until delivery to, or
forfeiture by, the recipient. The recipient may vote the shares covered by the
award and receive dividends, but generally may not sell, pledge or otherwise
transfer such shares until the restriction period imposed by Cleco's
Compensation Committee ends and the performance goals established by the
committee have been met. The recipient may, at the end of the restriction
period, forfeit all or a portion of the restricted shares awarded, depending
upon the performance level achieved. The restricted stock awards require a
three-year holding period following vesting before any shares may be sold.
The amounts listed in the "Number of Threshold Shares" and "Number of
Target Shares" columns, respectively, represent performance-based restricted
stock granted in 1999 that will vest under the threshold and target levels
established by Cleco's Compensation Committee. In 1999, Cleco's Long-Term
Incentive Plan was modified to incorporate strategic plan performance measures,
in addition to a comparison of Cleco's total shareholder return to that of a
peer group of utilities and energy services companies. New performance measures
include growth in net income and return on investment. To trigger an award,
comparative shareholder return (computed as the Cleco common stock price
appreciation plus dividends paid during the performance cycle) must be at or
above the preestablished performance level of the 40th percentile. The vesting
or payout schedule for the restricted stock awards, once the minimum comparative
shareholder return requirement is satisfied, is as follows:
. no awards will vest if Cleco's performance on growth in net income and return
on investment is less than 75% of plan;
. threshold performance on both factors provides a 30% award payout; and
45
<PAGE>
. target performance on both factors at 100% of plan provides 100% award
payout.
Performance awards above the threshold level and below the target level are
prorated.
The amounts under the "Number of Maximum Shares" column represent the
number of performance-based restricted stock grants that vest at the target
level set forth under the "Number of Target Shares" column plus the number of
performance-based "opportunity shares" granted to the named executive officers
in 1999 that will vest between the target and maximum levels established by
Cleco's Compensation Committee.
"Opportunity shares" awarded in connection with a restricted stock award
will not be issued until the lapse of restrictions on the related restricted
stock and do not entitle the recipient to the rights of a shareholder until the
time of issuance of the Cleco common stock representing the "opportunity
shares." "Opportunity share" awards require a three-year holding period
following vesting before any of the shares may be sold. The "opportunity shares"
vest based on performance above target levels for growth in net income and
return on investment and will be issued when the restriction period on the
related restricted stock lapses. The vesting or payout schedule for the
"opportunity shares" included in this column, based on Cleco performance on
growth in net income and return on investment, is as follows:
. no awards of "opportunity shares" vest if Cleco's performance is at or below
100% of plan for growth in net income and return on investment; and
. maximum performance provides 100% "opportunity shares" award payout, which is
equal to 100% of the number of target shares of restricted stock, at 125% of
plan for growth in net income and 130% of plan for return on investment.
Performance awards of "opportunity shares" above the target level and below the
maximum level are prorated.
46
<PAGE>
LONG-TERM INCENTIVE PLAN--AWARDS IN 1999
<TABLE>
<CAPTION>
ESTIMATED FUTURE PAYOUTS
---------------------------------------------------------
PERFORMANCE OR
OTHER PERIOD UNTIL NUMBER OF NUMBER OF NUMBER OF
NUMBER OF MATURATION OR THRESHOLD TARGET MAXIMUM
NAME SHARES PAYOUT SHARES SHARES SHARES
---- ------------- ----------------------- ---------------- ---------------- ----------------
<S> <C> <C> <C> <C> <C>
Gregory L. Nesbitt........ 6,077 1/1/99 - 12/31/01 1,824 6,077 12,154
David M. Eppler........... 3,472 1/1/99 - 12/31/01 1,042 3,472 6,944
Thomas J. Howlin.......... 2,025 1/1/99 - 12/31/01 608 2,025 4,051
Catherine C. Powell....... 1,563 1/1/99 - 12/31/01 469 1,563 3,125
Mark H. Segura............ 1,128 1/1/99 - 12/31/01 339 1,128 2,257
Darrell J. Dubroc......... 1,345 1/1/99 - 12/31/01 404 1,345 2,691
</TABLE>
RETIREMENT PLANS
Our executive officers are participants in Cleco's Savings and Investment
Plan, Cleco's Pension Plan and Cleco's Supplemental Executive Retirement Plan
(SERP), all of which are maintained by us.
Pension Plan
The Pension Plan generally covers employees of Cleco who have attained
age 21 and completed one year of service. The monthly benefit payable under the
Pension Plan at the normal retirement age of 65 is an amount determined with
reference to a participant's "compensation base" and years of service at
termination of employment. A participant's "compensation base" is calculated by
averaging compensation paid during the highest successive five completed
calendar years during the 10 years prior to termination of employment.
Compensation is determined by taking into account the salaries and bonuses
reflected in the "Salary" and "Bonus" columns of the Summary Compensation Table.
Benefits under the Pension Plan are fully vested upon the completion of five
years of service. The maximum annual benefit payable under the Pension Plan for
employees who retire in 2000 is the lesser of $135,000, a limitation imposed by
the Internal Revenue Code of 1986, as amended (Code), or 100% of "average
compensation," as defined in the Code. Payments to retired employees under the
Pension Plan are not reduced for Social Security benefits or other offsetting
amounts.
47
<PAGE>
As of December 31, 1999, the following individuals had the following
years of service credited under the Pension Plan:
Mr. Nesbitt 19 years
Mr. Eppler 18 years
Mr. Howlin 2 years
Ms. Powell 8 years
Mr. Segura 14 years
Mr. Dubroc 14 years
SERP
Effective July 1, 1992, Cleco established a SERP for the benefit of
certain participants designated by its Compensation Committee. As of September
30, 2000, the chief executive officer and the four other most highly compensated
executive officers participated in the SERP. Under the SERP, eligible
compensation is based upon the sum of the highest annual salary paid during the
five years prior to termination of employment and the average of the three
highest annual incentive compensation program awards paid to the participant
during the preceding five years. These amounts are reflected in the "Salary"
and "Bonus" columns of the Summary Compensation Table. Benefits are payable
from Cleco's general assets. The following table illustrates the combined
estimated annual benefit payable from both the Pension Plan and the SERP at age
65 to persons at specified compensation levels. Benefits are computed on a
joint and 100% survivor annuity basis.
<TABLE>
<CAPTION>
YEARS OF SERVICE AT RETIREMENT
-------------------------------------------------------------------------
Final Total Compensation 15 20 25 30 35
------------------------ -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
$125,000 $ 81,250 $ 81,250 $ 81,250 $ 81,250 $ 81,250
150,000 97,500 97,500 97,500 97,500 97,500
175,000 113,750 113,750 113,750 113,750 113,750
200,000 130,000 130,000 130,000 130,000 130,000
225,000 146,250 146,250 146,250 146,250 146,250
250,000 162,500 162,500 162,500 162,500 162,500
300,000 195,000 195,000 195,000 195,000 195,000
400,000 260,000 260,000 260,000 260,000 260,000
450,000 292,500 292,500 292,500 292,500 292,500
500,000 325,000 325,000 325,000 325,000 325,000
</TABLE>
Compensation Committee Interlocks and Insider Participation
Mr. Simmons, Ms. Cadoria, Mr. Garrett and Mr. Walker served on the joint
Compensation Committee for Cleco and the Company during 1999. Mr. Simmons
served as
48
<PAGE>
chairman of the joint committee. There are no matters relating to interlocks or
insider participation that we are required to report.
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
DIRECTOR TRANSACTIONS
Mr. Crowell is a member of the law firm of Crowell & Owens. Crowell &
Owens performed legal services for Cleco in 1999 and 2000. The amount paid to
Crowell & Owens for legal services performed in each of these years for Cleco
was less than $2,000.
Mr. Ratcliff is the chairman, president and chief executive officer of
Ratcliff Construction Company, Inc. In competitive bidding, Ratcliff
Construction Company, Inc., was awarded a site preparation contract for the
Coughlin Station Repowering Project of Cleco's wholly owned subsidiary, Cleco
Evangeline LLC. The contract amount of $518,917.01 was paid in full on March
15, 1999.
INTERCOMPANY TRANSACTIONS
Several of our affiliated companies, including Intrastate, Cleco
Generation Services LLC (Generation) and Marketing & Trading, provided services
to us during 1999 and the nine months ended September 30, 2000. Intrastate owns
natural gas pipelines and provides generating fuel transportation services for
our power stations. Beginning in January 2000, Generation provided operation
and maintenance services for our generating stations, as well as station
maintenance planning. In July 1999, Marketing & Trading began managing the
dispatch of all Cleco's generating stations, including those owned by us, the
procurement of electric power and generating station fuel, and energy marketing
services.
Other affiliates provided additional services to us during 1999 and the
nine months ended September 30, 2000. Support Group provides comprehensive
administrative and corporate support services to us and other affiliates,
including information technology, accounting, investor relations, and auditing
services. We began using these services in January 2000. UtiliTech provided
crews to perform a selected portion of our line construction and maintenance
services from January 1999 through August 2000. UtiliTech also provided
geographical facility mapping services to us from November 1998 through October
1999. UtiliTech transferred certain assets for providing these geographic
facility mapping services to us at book value in the third quarter of 1999. For
more information on this transfer, see Note K to the notes to the audited
financial statements included in Annex F to this registration statement.
We also provided selected services to affiliates during 1999 and in the
nine months ended September 30, 2000. During this period, we provided employees
to UtiliTech to supplement UtiliTech's line construction and line maintenance
crews and to perform selected distribution and transmission engineering
projects. In addition, from July 1999 through December 1999, we provided
selected administrative and corporate services to UtiliTech, Marketing & Trading
and Evangeline. Support Group began providing these services in January 2000.
We have a power interconnection agreement with Evangeline, whereby we
provide to the Evangeline generating station (i) interconnection services to our
transmission system and (ii)
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<PAGE>
generation imbalance services. We have two current contracts to engineer,
procure equipment and construct transmission related facilities at the Acadia
and Perryville power stations, which are owned by subsidiaries of Cleco
Midstream Resources, LLC. We also have Master Services Agreements in place with
all affiliates for incidental services provided throughout the year between the
parties.
Amounts charged and allocated to us for goods and services provided by
our affiliates were $3.6 million in 1999 and $12.7 million for the first nine
months of 2000. These goods and services were charged at the lower of fair
market value or fully loaded cost in order to comply with Cleco's interaffiliate
policy. Amounts charged by us for goods and services provided to our affiliates
were $7.8 million in 1999 and $7.8 million for the first nine months of 2000.
These goods and services were charged at the higher of fair market value or
fully loaded cost in order to comply with Cleco's interaffiliate policy.
On July 1, 1999, all of our subsidiaries' stock and our common stock was
dividended to Cleco as part of our reorganization into a holding company
structure. The book value of the dividend was approximately $30.6 million.
Please read Note A to the notes to the audited financial statements included in
Annex F to this registration statement for details regarding our reorganization
into a holding company structure.
ITEM 8. LEGAL PROCEEDINGS.
We and SWEPCO, each a 50% owner of Dolet Hills Unit 1, jointly own
lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982, we
and SWEPCO entered into a Lignite Mining Agreement (LMA) with DHMV, a
partnership for the mining and delivery of lignite from a portion of these
reserves (Dolet Hills Mine). The LMA expires in 2011. The price of lignite
delivered pursuant to the LMA is a base price per ton, subject to escalation
based on certain inflation indices, plus specified "pass-through" costs.
Currently, we are receiving annually a minimum delivery of 1,750,000 tons
under the LMA. Since the late 1980s, additional spot lignite deliveries have
been obtained through competitive bidding from DHMV and another lignite
supplier. In 1999, we and SWEPCO received deliveries that approximated 25% of
the annual lignite consumption at the Dolet Hills Unit 1 from the other lignite
supplier.
On April 15, 1997, we and SWEPCO filed suit against DHMV and its partners
in the United States District court for the Western District of Louisiana (the
Federal Court Suit), seeking to enforce various obligations of DHMV to us and
SWEPCO under the LMA, including provisions relating to the quality of the
delivered lignite, pricing and mine reclamation practices. On June 15, 1997,
DHMV filed an answer denying the allegations in our suit and filed a
counterclaim asserting various contract-related claims against us and SWEPCO.
We and SWEPCO have denied the allegations in the counterclaims.
As a result of the counterclaims filed by DHMV in the Federal Court Suit,
on August 13, 1997, we and SWEPCO filed a separate lawsuit against the parent
companies of DHMV, namely Jones Capital Corporation and Philipp Holzmann USA,
Inc. in the First Judicial District Court for Caddo Parish, Louisiana (State
Court Suit). The State Court Suit seeks to enforce a separate 1995 agreement by
Jones Capital Corporation and Philipp Holzmann USA,
50
<PAGE>
Inc., related to the LMA. Jones Capital Corporation and Philipp Holzmann USA,
Inc., have asked the state court to stay that proceeding until the Federal Court
Suit is resolved.
On March 1, 2000, the court in the Federal Court Suit ruled that DHMV was
not in breach of certain financial covenants under the LMA and denied our and
SWEPCO's claim to terminate the LMA on that basis. The ruling has no material
adverse effect on our operations and does not affect the other claims scheduled
for trial. We and SWEPCO have appealed the federal court's ruling to the United
States Court of Appeals for the Fifth Circuit.
The civil, nonjury trial in the Federal Court Suit was to have commenced
on May 22, 2000. However, on April 20, 2000, all parties jointly requested that
the court postpone the trial date and grant a 120-day stay of all matters before
the trial court to give the parties an opportunity to attempt to reach an
amicable resolution of the litigation. A preliminary memorandum of
understanding to settle the litigation has been executed among us, SWEPCO, and
DHMV. However, the memorandum of understanding is subject to several conditions
precedent that are not yet fulfilled, including prior authorization by the LPSC
of favorable rate recovery of the settlement by us and SWEPCO. The federal
court granted the motion, stayed the action at the trial court and postponed the
trial commencement date to October 23, 2000. At a status conference held on July
12, 2000, the court extended the stay of the proceedings and again postponed the
trial date to January 16, 2001. Settlement negotiations are ongoing during the
pendency of the stay.
Should settlement discussions be unsuccessful, we and SWEPCO will
continue aggressively to prosecute the claims against DHMV and defend against
the counterclaims that DHMV has asserted. We and SWEPCO continue to pay DHMV
for lignite delivered pursuant to the LMA. Normal day-to-day operations continue
at the Dolet Hills Mine and Dolet Hills Unit 1. Although the ultimate outcome
of this litigation or the settlement negotiations cannot be predicted at this
time, based on information currently available to us, management does not
believe that the outcome of the Federal Court Suit or any settlement in the
Federal Court Suit will have a material adverse effect on our financial position
or results of operations.
ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
There is no market for our common stock. All of our outstanding common
stock is owned by our parent, Cleco. Dividends on our common stock will be paid
when and if declared by our board of directors. Our current credit agreement
contains some restrictions on our ability to pay cash dividends on our common
stock. Any future dividends also may be restricted by any credit or loan
agreements that we may enter into from time to time.
None of our common stock is subject to outstanding options or warrants to
purchase common stock. There are no securities convertible into our common
stock. None of our common stock currently can be sold under Rule 144 under the
Securities Act of 1933. We are not currently publicly offering any of our
common stock. We are filing this registration statement with the SEC in order
to become a "reporting person" under the Securities Exchange Act of 1934 so that
we may file a debt securities shelf registration statement with the SEC.
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<PAGE>
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.
During the last three years, we have not sold any securities that were
not registered under the Securities Act of 1933, as amended. In connection with
our reorganization into a holding company structure, Cleco became the owner of
all of our outstanding common stock.
ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED.
This registration statement relates to the registration of our common
stock, all of the outstanding shares of which are owned by Cleco. We are filing
this registration statement with the SEC in order to become a "reporting person"
under the Securities Exchange Act of 1934 so that we may file a debt securities
shelf registration statement with the SEC.
Under our amended and restated articles of incorporation, we are
authorized to issue the following shares:
. 1,491,900 shares of preferred stock, par value $100.00 per share;
. 3,000,000 shares of preferred stock, par value $25.00 per share; and
. 50,000,000 shares of common stock, par value $2.00 per share.
As of September 30, 2000, there were 22,531,870 shares of common stock
issued and outstanding, all of which were owned by our parent, Cleco. There are
no shares of preferred stock issued or outstanding.
COMMON STOCK
Holders of common stock may receive dividends ratably if and when
declared by our board of directors out of funds legally available therefor. The
payment of dividends on our common stock may be limited by obligations we may
have to holders of any preferred stock. Holders of common stock are entitled to
one vote per share on matters submitted to them. Our board of directors is
divided into three classes, with the term of office of directors of one class
expiring each year. Cumulative voting of shares is prohibited, meaning that the
holders of a majority of the voting power of the shares voting for the election
of directors can elect all directors to be elected if they choose to do so. The
common stock has no preemptive rights and is not convertible, redeemable or
assessable, or entitled to the benefits of any sinking fund.
If we liquidate or dissolve our business, the holders of common stock
will share ratably in all assets available for distribution to stockholders
after creditors are paid and preferred stockholders receive their distributions.
All issued and outstanding shares of common stock are fully paid and
nonassessable. All of our outstanding common stock is owned by our parent,
Cleco.
PREFERRED STOCK
Our board of directors is allowed, without action by stockholders, to
issue one or more series of preferred stock. The board of directors can also
determine the rights, preferences,
52
<PAGE>
privileges and restrictions, including dividend rights, voting rights,
conversion rights, terms of redemption and liquidation preferences, of a series
of the preferred stock.
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Section 83 of the Business Corporation Law of the State of Louisiana
(LBCL) provides that a corporation may indemnify any person against whom an
action, suit or proceeding is brought or threatened, by reason of the fact that
he is or was a director, officer, employee or agent of the corporation or was
serving at the request of the corporation as a director, officer, employee or
agent of another business, corporation, partnership or other enterprise, against
expenses, including attorneys' fees, judgments, fines and amounts paid in
settlement actually and reasonably incurred by him in connection with any such
action, suit or proceeding if he acted in good faith and in a manner he
reasonably believed to be in or not opposed to the best interests of the
corporation and, with respect to any criminal action or proceeding, had no
reasonable cause to believe his conduct was unlawful. In the case of actions by
or in the right of the corporation, the indemnity is limited to expenses,
including attorneys' fees and amounts paid in settlement not exceeding, in the
judgment of the board of directors, the estimated expense of litigating the
action to conclusion, actually and reasonably incurred in connection with a
defense or settlement; provided that no indemnity may be made in respect of any
matter in which the person shall have been adjudged by a court of competent
jurisdiction, after exhaustion of all appeals therefrom, to be liable for
willful or intentional misconduct in performance of his duty to the corporation
unless and only to the extent that the court determines upon application that
such person is fairly and reasonably entitled to such indemnity. To the extent
a person has been successful on the merits or otherwise in defense of any
action, the statute provides that he shall be indemnified against expenses
actually and reasonably incurred by him in connection therewith. Section 83
also provides for, among other things, procedures for indemnification;
advancement of expenses; nonexclusivity of the provisions of Section 83 with
respect to indemnification and advancement of expenses; and insurance, including
self-insurance, with respect to liabilities incurred by directors, officers and
others.
Article IV of our Bylaws provides that we shall indemnify any person who
was or is, or is threatened to be made, a party to or otherwise involved in any
pending or completed action, suit, arbitration, alternate dispute resolution
mechanism, investigation, administrative hearing or other proceeding, whether
civil, criminal, administrative or investigative (any such threatened, pending
or completed proceeding being hereinafter called a Proceeding) by reason of the
fact that he is or was one of our directors, officers, employees or agents or is
or was serving at our request as a director, officer, employee or agent of
another business, foreign or nonprofit corporation, partnership, joint venture,
trust, employee benefit plan or other enterprise (whether the basis of his
involvement in such Proceeding is alleged action in an official capacity or in
any other capacity while serving as such), to the fullest extent permitted by
applicable law, from and against expenses, including attorney's fees, judgments,
fines, amounts paid or to be paid in settlement, liability and loss, ERISA
excise taxes, actually and reasonably incurred by him or on his behalf or
suffered in connection with such Proceeding or any claim, issue or matter
therein; provided, however, that, subject to certain exceptions set forth
therein, we shall indemnify any such person claiming indemnity in connection
with a Proceeding initiated by such person only if such Proceeding was
authorized by the board of directors.
The Bylaws further provide that:
53
<PAGE>
. we will from time to time pay, in advance of final disposition, all Expenses
(as defined therein) incurred by or on behalf of any person claiming
indemnity thereunder in respect of any Proceeding;
. the right to indemnification provided therein is a contract right and no
amendment, alteration or repeal of the Bylaws will restrict the
indemnification rights granted by the Bylaws as to any person claiming
indemnification with respect to acts, events and circumstances that occurred,
in whole or in part, before such amendment, alteration or repeal;
. any such indemnification may continue as to any person who has ceased to be a
director, officer, employee or agent and may inure to the benefit of the
heirs, executors and legal representative of such person; and
. the rights to indemnification and to receive advancement of Expenses
contemplated by Section 1 of Article IV of the Bylaws are not exclusive of
any other rights to which any person may at any time be otherwise entitled,
provided that such other indemnification may not apply to a person's willful
or intentional misconduct.
The Bylaws also set forth certain procedural and evidentiary standards
applicable to the enforcement of a claim thereunder.
The Bylaws also provide that we:
. may procure or maintain insurance or other similar arrangement, at our
expense, to protect ourselves and any director, officer, employee or agent of
ours or any other corporation, partnership, joint venture, trust or other
enterprise against any expense, liability or loss asserted against or
incurred by such person, whether or not we would have the power to indemnify
such person against such expense or liability; and
. shall indemnify our officers and directors to the extent they are not covered
by the insurance, whether or not such persons would otherwise be entitled to
indemnification under the Bylaws, as provided in policies covering
liabilities up to $85 million incurred by directors and officers in their
capacities as such, and has fiduciary and employee benefit liability
insurance policies covering liabilities up to $65 million incurred by our
directors, officers and certain other employees in connection with the
administration of our employee benefit plans.
Section 24(C)(4) of the LBCL provides that a corporation may eliminate or
limit the liability of a director or officer to the corporation or its
shareholders for monetary damages for breach of fiduciary duty, except for
liability:
. for any breach of the director's or officer's duty of loyalty to the
corporation or its shareholders;
. for acts or omissions not in good faith or that involve intentional
misconduct or a knowing violation of law;
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<PAGE>
. under Section 92(D) of the LBCL relating to unlawful dividends and other
unlawful distributions, payments or returns of assets; and
. for any transaction from which the director or officer derived an improper
personal benefit.
Our Articles of Incorporation include a provision consistent with Section
24(C)(4) of the LBCL. Such provision further provides that (a) if the LBCL is
subsequently amended to authorize action further eliminating or limiting a
director's or officer's liability, such liability will be eliminated or limited
to the fullest extent permitted by such law, as so amended, and (b) if such
provision limiting or eliminating liability is repealed or modified, the right
or protection of a director or officer of the Company existing at the time of
such repeal or modification will not be affected thereby.
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements attached to this registration statement as
Annex F are incorporated by reference herein.
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS.
(a) The financial statements filed as a part of this registration
statement are listed in Annex F, which is incorporated by reference
herein.
55
<PAGE>
(b) Except as otherwise indicated below, the following exhibits are filed
with this registration statement.
<TABLE>
<CAPTION>
SEC File or
Registration Registration
Exhibits Number Statement or Report Exhibit Number
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
2(a) Plan of Reorganization and Share Exchange 333-71643-01 S-4 (6/30/99) C
Agreement
*3(a) Amended and Restated Articles of Incorporation of
the Company, effective July 1, 1999
*3(b) Bylaws of the Company, effective May 1, 2000
4(a)(1) Indenture of Mortgage dated as of July 1, 1950, 1-5663 10-K (1997) 4(a)(1)
between the Company and First National Bank of
New Orleans, as Trustee
4(a)(2) First Supplemental Indenture dated as of October 1-5663 10-K (1997) 4(a)(2)
1, 1951, to Exhibit 4(a)(1)
4(a)(3) Second Supplemental Indenture dated as of June 1, 1-5663 10-K (1997) 4(a)(3)
1952, to Exhibit 4(a)(1)
4(a)(4) Third Supplemental Indenture dated as of January 1-5663 10-K (1997) 4(a)(4)
1, 1954, to Exhibit 4(a)(1)
4(a)(5) Fourth Supplemental Indenture dated as of 1-5663 10-K (1997) 4(a)(5)
November 1, 1954, to Exhibit 4(a)(1)
4(a)(6) Tenth Supplemental Indenture dated as of 1-5663 10-K (1986) 4(a)(11)
September 1, 1965, to Exhibit 4(a)(1)
4(a)(7) Eleventh Supplemental Indenture dated as of April 1-5663 10-K (1998) 4(a)(8)
1, 1969, to Exhibit 4(a)(1)
4(a)(8) Eighteenth Supplemental Indenture dated as of 1-5663 10-K (1993) 4(a)(8)
December 1, 1982, to Exhibit 4(a)(1)
4(a)(9) Nineteenth Supplemental Indenture dated as of 1-5663 10-K (1993) 4(a)(9)
January 1, 1983, to Exhibit 4(a)(1)
4(a)(10) Twenty-Sixth Supplemental Indenture dated as of 1-5663 8-K (3/90) 4(a)(27)
March 15, 1990, to Exhibit 4(a)(1)
4(b) Indenture between the Company and Bankers Trust 33-24896 S-3 (10/11/88) 4(b)
Company, as Trustee, dated as of October 1, 1988
4(b)(1) Agreement Appointing Successor Trustee dated as 333-02895 S-3 (4/26/96) 4(a)(2)
of April 1, 1996 by and among Central Louisiana
Electric Company, Inc., Bankers Trust Company and
The Bank of New York
4(f) Agreement Under Regulation S-K Item 333-71643-01 10-Q (9/99) 4(c)
601(b)(4)(iii)(A)
***4(g) $100,000,000 364-day credit agreement dated as of
June 15, 2000, among the Company, certain Banks
parties thereto, and The Bank of New York, as
administrative agent
</TABLE>
56
<PAGE>
<TABLE>
<CAPTION>
SEC File or
Registration Registration
Exhibits Number Statement or Report Exhibit Number
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
**10(a) 1990 Long-Term Incentive Compensation Plan 1-5663 1990 Proxy A
Statement (4/90)
**10(b) Participation Agreement, Annual Incentive 1-5663 10-K (1999) 10(c)
Compensation Plan
**10(c) Deferred Compensation Plan for Directors 1-5663 10-K (1992) 10(n)
**10(d)(1) Supplemental Executive Retirement Plan 1-5663 10-K (1992) 10(o)(1)
**10(d)(2) Form of Supplemental Executive Retirement Plan 1-5663 10-K (1992) 10(o)(2)
Participation Agreement between Cleco and the
following officers: Gregory L. Nesbitt, David M.
Eppler, Catherine C. Powell, Mark H. Segura,
Darrell J. Dubroc and Thomas J. Howlin
**10(e) Form of Executive Severance Agreement between 1-5663 10-K (1995) 10(f)
Cleco and the following officers: Gregory L.
Nesbitt, David M. Eppler, Catherine C. Powell,
Mark H. Segura, Darrell J. Dubroc and Thomas J.
Howlin
10(f)(1) Term Loan Agreement dated as of April 2, 1991, 1-5663 10-Q (3/91) 4(b)
among the 401(k) Savings and Investment Plan ESOP
Trust, the Company, as Guarantor, the Banks
listed therein and The Bank of New York, as Agent
10(f)(2) Assignment and Assumption Agreement, effective as 1-5663 10-Q (3/91) 4(c)
of May 6, 1991, between The Bank of New York and
the Canadian Imperial Bank of Commerce, relating
to Exhibit 10(f)(1)
10(f)(3) Assignment and Assumption Agreement dated as of 1-5663 10-K (1991) 10(y)(3)
July 3, 1991, between The Bank of New York and
Rapides Bank and Trust Company in Alexandria,
relating to Exhibit 10(f)(1)
10(f)(4) Assignment and Assumption Agreement dated as of 1-5663 10-K (1992) 10(bb)(4)
July 6, 1992, between The Bank of New York, CIBC,
Inc. and Rapides Bank and Trust Company in
Alexandria, as Assignors, the 401(k) Savings and
Investment Plan ESOP Trust, as Borrower, and the
Company, as Guarantor, relating to Exhibit
10(f)(1)
10(g) Reimbursement Agreement (The Industrial 1-5663 10-K (1997) 10(i)
Development Board of the Parish of Rapides, Inc.
(Louisiana) Adjustable Tender Pollution Control
Revenue Refunding Bonds, Series 1991) dated as of
October 15, 1997, among the Company, various
financial institutions, and Westdeutsche
Landesbank Girozentrale, New York Branch, as Agent
</TABLE>
57
<PAGE>
<TABLE>
<CAPTION>
SEC File or
Registration Registration
Exhibits Number Statement or Report Exhibit Number
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
10(h) Selling Agency Agreement between the Company and 333-02895 S-3 (12/10/96) 1
Salomon Brothers Inc., Merrill Lynch & Co., Smith
Barney Inc. and First Chicago Capital Markets,
Inc. dated as of December 12, 1996
10(i) 401(k) Savings and Investment Plan ESOP Trust 1-5663 10-K (1997) 10(m)
Agreement dated as of August 1, 1997, between UMB
Bank, N.A. and the Company
10(i)(1) First Amendment to 401(k) Savings and Investment 1-5663 10-K (1997) 10(m)(1)
Plan ESOP Trust Agreement dated as of October 1,
1997, between UMB Bank, N.A. and the Company
***10(j) 2000 Long-Term Incentive Compensation Plan
10(1) Form of Notice and Acceptance of Grant of 333-71643-01 10Q (9/99) 10(c)
Nonqualified Stock Options, awarded to Gregory L.
Nesbitt
*11 Computation of Net Income Per Common Share
*12 Computation of Earnings to Fixed Charges
***21 Subsidiaries of the Registrant
*27 Financial Data Schedule
</TABLE>
The Exhibits designated by an asterisk will be filed by amendment. The
Exhibits not so designated have been previously filed with the SEC and are
incorporated herein by reference as indicated. The Exhibits designated by two
asterisks are management contracts and compensatory plans and arrangements
required to be filed as Exhibits to this registration statement and are also
incorporated herein by reference as indicated. The Exhibits designated by three
asterisks are filed herewith.
58
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act
of 1934, the registrant has duly caused this registration statement to be signed
on its behalf by the undersigned, thereunto duly authorized, on this 15th day of
November, 2000.
CLECO UTILITY GROUP INC.
By: /s/ THOMAS J. HOWLIN
-----------------------------
Name: Thomas J. Howlin
Title: Chief Financial Officer
59
<PAGE>
ANNEX F
FINANCIAL STATEMENTS
F-1
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Audited Financial Statements
Report of Independent Public Accountants.................................................................... F-3
Balance Sheets as of December 31, 1999 and 1998............................................................. F-4
Statements of Income for the years ended December 31, 1999, 1998 and 1997................................... F-6
Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997............................... F-7
Statements of Changes in Common Shareholders' Equity for the years ended December 31, 1999, 1998 and 1997... F-8
Notes to the Audited Financial Statements................................................................... F-9
Unaudited Financial Statements
Balance Sheets as of December 31, 1999, and September 30, 2000.............................................. F-33
Statements of Income for the nine months ended September 30, 2000, and 1999................................. F-35
Statements of Cash Flows for the nine months ended September 30, 2000 and 1999.............................. F-36
Notes to the Unaudited Interim Financial Statements......................................................... F-37
</TABLE>
F-2
<PAGE>
[PricewaterhouseCoopers letterhead]
PricewaterhouseCoopers LLP
639 Loyola Avenue
Suite 1800
New Orleans LA 70113
Telephone (504) 529 2700
Facsimile (504) 529 1439
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder and Board of Directors of Cleco Utility Group, Inc.:
In our opinion, the accompanying balance sheets and the related statements of
income, cash flows and changes in common shareholder's equity present fairly, in
all material respects, the financial position of Cleco Utility Group, Inc. at
December 31, 1999 and 1998, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1999 in conformity
with accounting principles generally accepted in the United States. 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 statements in accordance with
auditing standards generally accepted in the United States, which 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 the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
New Orleans, Louisiana
January 31, 2000
F-3
<PAGE>
CLECO UTILITY GROUP INC.
BALANCE SHEETS
<TABLE>
<CAPTION>
(IN THOUSANDS)
AT DECEMBER 31,
1999 1998
---------- ----------
<S> <C>
ASSETS
Utility plant and other property, plant and equipment
Property, plant and equipment $1,539,435 $1,555,196
Accumulated depreciation (552,556) (551,705)
---------------------------------
Net property, plant and equipment 986,879 1,003,491
Construction work-in-progress 26,919 76,475
Total utility plant, net 1,013,798 1,079,966
---------------------------------
Other assets 2,358 3,500
---------------------------------
Current assets
Cash and cash equivalents 547 19,457
Accounts receivable, net
Customer accounts receivable (less allowance for
doubtful accounts of $838 in 1999 and $812 in 1998) 26,720 27,436
Other accounts receivable 13,728 22,218
Affiliates 22,624 -
Notes receivable - 930
Notes receivable - affiliates 2 -
Unbilled revenues 17,065 9,712
Fuel inventory, at average cost 10,461 9,725
Material and supplies inventory, at average cost 14,189 12,674
Other current assets 3,202 1,738
---------------------------------
Total current assets 108,538 103,890
---------------------------------
Prepayments 6,428 8,293
Regulatory assets - deferred taxes 70,834 70,932
Other deferred charges 33,839 30,975
Accumulated deferred federal and state income taxes 55,184 52,898
---------------------------------
TOTAL ASSETS $1,290,979 $1,350,454
=================================
</TABLE>
(Continued on next page)
The accompanying notes are an integral part of the financial statements.
F-4
<PAGE>
CLECO UTILITY GROUP INC.
BALANCE SHEETS
<TABLE>
<CAPTION>
(IN THOUSANDS)
AT DECEMBER 31
1999 1998
---------- ----------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Common shareholder's equity
Common stock, $2 par value, authorized 50,000,000 shares, issued 22,531,870 and
22,767,754 shares at December 31, 1999 and 1998, respectively $ 45,064 $ 45,535
Premium on capital stock 127,477 113,871
Retained earnings 234,288 271,019
Treasury stock, at cost, - 0 - and 281,930 shares at
December 31, 1999 and 1998, respectively - (5,734)
------------------------------
Total common shareholder's equity 406,829 424,691
Preferred stock
Not subject to mandatory redemption - 29,718
Preferred stock subject to mandatory redemption - 5,680
Deferred compensation related to preferred stock held by ESOP - (16,923)
Long-term debt, net 360,339 343,042
------------------------------
Total capitalization 767,168 786,208
------------------------------
Current liabilities
Short-term debt 5,989 68,416
Long-term debt due within one year 25,000 33,330
Accounts payable 56,093 61,786
Accounts payable - Affiliate 9,244 -
Customer deposits 20,326 20,120
Taxes accrued 1,321 11,942
Taxes accrued - payable to parent 24,428 -
Interest accrued 8,788 7,340
Accumulated deferred fuel 2,638 4,613
Other current liabilities 3,756 3,868
------------------------------
Total current liabilities 157,583 211,415
------------------------------
Deferred credits
Accumulated deferred federal and state income taxes 263,688 252,520
Accumulated deferred investment tax credits 25,994 27,784
Regulatory liabilities - deferred taxes 27,221 36,627
Other deferred credits 49,325 35,900
------------------------------
Total deferred credits 366,228 352,831
------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $1,290,979 $1,350,454
==============================
</TABLE>
The accompanying notes are an integral part of the financial statements.
F-5
<PAGE>
CLECO UTILITY GROUP INC.
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
FOR THE YEAR ENDED DECEMBER 31,
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Operating revenue
Retail electric operations $ 508,790 $ 487,280 $ 456,245
Energy marketing operations 237,731 32,695 -
Affiliate revenues 7,816 - -
----------------------------------------------------
Gross operating revenue 754,337 519,975 456,245
Less retail electric customer credits (2,776) (4,800) -
----------------------------------------------------
Total operating revenue 751,561 515,175 456,245
----------------------------------------------------
OPERATING EXPENSES
Fuel used for electric generation 146,825 142,737 136,009
Power purchased for utility customer 65,303 53,011 44,590
Purchases for energy marketing operations 230,084 27,322 -
Other operations 75,856 71,066 64,618
Maintenance 29,369 30,285 23,286
Depreciation 49,285 48,369 45,890
Taxes other than income taxes 35,870 35,420 33,422
Income taxes 27,272 26,666 27,729
Restructuring charges - - 1,891
Affiliate costs 6,397 - -
----------------------------------------------------
Total operating expenses 666,261 434,876 377,435
----------------------------------------------------
OPERATING INCOME 85,300 80,299 78,810
Interest income 1,238 372 427
Allowance for other funds used during construction 654 812 620
Other income (expense), net (2,095) (322) 1,248
----------------------------------------------------
INCOME BEFORE INTEREST CHARGES 85,097 81,161 81,105
----------------------------------------------------
INTEREST CHARGES
Interest on debt and other, net of amount capitalized 27,223 27,016 27,549
Allowance for borrowed funds used during construction (91) (904) (169)
Amortization of debt discount, premium and expense, net 1,282 1,248 1,206
----------------------------------------------------
Total interest charges 28,414 27,360 28,586
----------------------------------------------------
NET INCOME BEFORE PREFERRED DIVIDENDS 56,683 53,801 52,519
Preferred dividend requirements, net 1,047 2,137 2,117
----------------------------------------------------
NET INCOME APPLICABLE TO COMMON STOCK $ 55,636 $ 51,664 $ 50,402
====================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING
Basic 22,524,529 22,480,163 22,459,770
Diluted 23,254,706 23,867,458 23,864,031
EARNINGS PER AVERAGE SHARE
Basic $2.47 $2.30 $2.24
Diluted $2.43 $2.24 $2.18
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK $3.96 $1.61 $1.57
</TABLE>
The accompanying notes are an integral part of the financial statements.
F-6
<PAGE>
CLECO UTILITY GROUP INC.
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31,
1999 1998 1997
--------- -------- --------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 56,683 $ 53,801 $ 52,519
Adjustments to reconcile net income to net cash provided by operating
activities
Depreciation and amortization 50,567 50,852 47,719
Allowance for funds used during construction 745 (1,716) (789)
Amortization of investment tax credits (1,790) (1,790) (1,790)
Deferred income taxes 8,469 8,703 2,908
Deferred fuel costs (1,975) 1,648 797
Restructuring charge - - 1,285
Gain (loss) on disposition of land sales, net (130) - (224)
Changes in assets and liabilities
Accounts receivable, net 25,225 (2,231) (4,441)
Unbilled revenues (7,353) 1,378 103
Fuel, material and supplies inventories (2,582) 662 3,334
Accounts payable 5,224 4,421 2,058
Customer deposits 206 (52) 411
Taxes accrued 13,789 (269) 6,405
Interest accrued 1,448 (341) 160
Other, net 2,402 (1,682) 7,321
--------- -------- --------
Net cash provided by operating activities 150,928 113,384 117,776
--------- -------- --------
INVESTING ACTIVITIES
Additions to property, plant and equipment (51,758) (94,030) (77,525)
Allowance for funds used during construction (745) 1,716 789
Sale of utility plant 9,231 408 418
Purchase of investments (200) (480) (222)
--------- -------- --------
Net cash used in investing activities (43,472) (92,386) (76,540)
--------- -------- --------
FINANCING ACTIVITIES
Issuance of common stock 243 100 66
Repurchase of common stock (120) - (16)
Redemption of preferred stock (6,518) (522) (252)
Issuance of long-term debt 50,000 - 40,000
Retirement of long-term debt (10,639) (30,000) (15,000)
Increase (decrease) in short-term debt, net (82,427) 49,197 (30,942)
Cash in subsidiaries moved to holding company (17,384) - -
Dividends paid on common and preferred stock, net (59,521) (38,331) (37,384)
--------- -------- --------
Net cash used in financing activities (126,366) (19,556) (43,528)
--------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (18,910) 1,442 (2,292)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 19,457 18,015 20,307
--------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 547 $ 19,457 $ 18,015
========= ======== ========
Supplementary cash flow information
Interest paid (net of amount capitalized) $ 28,423 $ 28,118 $ 28,770
========= ======== ========
Income taxes paid $ 7,724 $ 20,140 $ 23,752
========= ======== ========
</TABLE>
The accompanying notes are an integral part of the financial statements.
F-7
<PAGE>
CLECO UTILITY GROUP INC.
STATEMENT OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
---------------------------------------------------------------------------
PREMIUM ON
COMMON STOCK CAPITAL RETAINED TREASURY STOCK
SHARES AMOUNT STOCK EARNINGS SHARES COST
----------- --------- ------------- ---------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
(In thousands, except share and per share amounts)
BALANCE, JANUARY 1, 1997 22,760,154 $45,520 $113,702 $240,414 307,577 $ 6,242
Redemptions of preferred stock 18
Incentive stock options exercised 2,600 5 38
Issuance of treasury stock 5 (8,528) (172)
Incentive shares forfeited 793 16
Dividend requirements, preferred
stock, net (2,118)
Cash dividends paid, common stock,
$1.57 per share (35,266)
Net income 52,519
---------- ------- -------- -------- -------- -------
Balance, December 31, 1997 22,762,754 45,525 113,763 255,549 299,842 6,086
---------- ------- -------- -------- -------- -------
Redemptions of preferred stock 10
Incentive stock options exercised 5,000 10 74
Issuance of treasury stock 24 (19,755) (401)
Incentive shares forfeited 1,987 54
Director's restricted stock award (144) (5)
Dividend requirements, preferred
stock, net (2,137)
Cash dividends paid, common stock,
$1.61 per share (36,194)
Net income 53,801
---------- ------- -------- -------- -------- -------
Balance, December 31, 1998 22,767,754 45,535 113,871 271,019 281,930 5,734
---------- ------- -------- -------- -------- -------
Redemption of preferred stock 18
Repurchase of preferred stock (62)
Incentive stock options exercised 10,800 22 217
Issuance of treasury stock 5 (41,060) (831)
Director's restricted stock award (86) (3)
Treasury shares purchased 5,900 120
Treasury shares cancelled (246,684) (493) (1,316) (3,256) (246,684) (5,020)
Dividend requirements, preferred
stock, net (1,047)
Transfer of non cash items to the
Company from Cleco Corporation 1,639
Dividend of interest in subsidiaries
and the Company to
Cleco Corporation (30,637)
Transfer of preferred ESOP shares to
Cleco Corporation, net of deferred
compensation relating to ESOP 13,105
Cash dividends paid, common stock,
$3.96 per share (58,474)
Net Income 56,683
---------- ------- -------- -------- -------- -------
Balance December 31, 1999 22,531,870 $45,064 $127,477 $234,288 0 $ 0
========== ======= ======== ======== ======== =======
</TABLE>
The accompanying notes are an integral part of the financial statements.
F-8
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
NOTE A -- HOLDING COMPANY STRUCTURE
At the Annual Meeting of Shareholders held on April 9, 1999, a resolution
was passed to reorganize the structure of Cleco Corporation into a holding
company structure. Effective July 1, 1999, Cleco Corporation changed its name
to Cleco Utility Group Inc. (the Company) and reorganized into a holding company
structure. This reorganization resulted in the creation of a holding company,
Cleco Corporation (Cleco, formerly Cleco Holding Corporation).
Under the terms of the reorganization, Cleco became the owner of all of
the Company's outstanding common stock, and holders of existing common stock and
two series of preferred stock exchanged their stock in the Company for stock in
Cleco. Shares of preferred stock in three series that did not approve the
reorganization were redeemed for $5.7 million. As a result of the share
exchange, the Company became a wholly owned subsidiary of Cleco and all
subsidiaries of the Company became subsidiaries of Cleco. As a result of the
exchange of stock and the transfer of subsidiaries, the Company issued a non-
cash dividend of approximately $30.6 million to Cleco, which represented the
book value of the investment in subsidiaries and the common stock of the
Company.
NOTE B -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
The Company provides electric service to a diversified base of
residential, commercial and industrial customers in 23 parishes (counties) of
Louisiana. The services consist primarily of generation, transmission,
distribution and customer care services.
The financial statements include the accounts of the Company and all
subsidiaries, which the Company owns directly, or indirectly, through a majority
interest, through June 30, 1999. Intercompany balances were eliminated in
consolidation. As of July 1, 1999, the Company's interest in its subsidiaries
was transferred by dividend to Cleco; therefore, the Company's statements of
income and statements of cash flows reflect the results of operations and cash
flows for the Company and its subsidiaries on a consolidated basis through June
30, 1999. The transfer was accounted for at the net book value of net assets of
its subsidiaries.
The preparation of financial statements in conformity with generally
accepted accounting principles 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 revenues and expenses during the
reporting period. Actual results could differ from those estimates.
RECLASSIFICATION
Certain reclassifications have been made to the 1997 and 1998 financial
statements to conform to the presentation used in the 1999 financial statements.
These reclassifications had no
F-9
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
effect on net income applicable to common stock, total common shareholders'
equity or cash flows.
REGULATION
The Company maintains its accounts in accordance with the Uniform System
of Accounts prescribed for electric utilities by the FERC, as adopted by the
LPSC. The Company's retail rates for residential, commercial and industrial
customers and other retail sales are regulated by the LPSC, and its rates for
transmission services and wholesale power sales are regulated by the FERC. The
Company follows Statements of Financial Accounting Statement No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulation." This Statement
allows utilities to capitalize or defer certain costs based on regulatory
approval and management's ongoing assessment that it is probable these items
will be recovered through the ratemaking process. During 1999, the LPSC
directed its staff to develop a transition to competition plan to be presented
on or before January 1, 2001. The plan under development by the LPSC staff may
affect the regulatory assets and liabilities recorded in the Company under SFAS
71 if the criteria for the application of SFAS 71 cannot continue to be met.
The Company has recorded regulatory assets and liabilities, primarily for
the effects of income taxes, as a result of past rate actions of regulators
pursuant to SFAS 71. The effects of potential deregulation of the industry or
possible future changes in the method of rate regulation of the Company could
require the Company to discontinue the application of SFAS 71 in the future,
pursuant to SFAS No. 101, "Regulated Enterprises -- Accounting for the
Discontinuation of Application of FASB Statement No. 71" (SFAS 101). At December
31, 1999, the Company had recorded $18.7 million of regulatory assets, net of
regulatory liabilities, because of the regulatory requirement to flow through
the tax benefits of accelerated deductions to current customers and an implied
regulatory compact that future customers would fund these amounts when the
Company pays the additional taxes. These differences occur over the lives of
relatively long-lived assets, up to 30 years or more. Under the current
regulatory and competitive environment, the Company believes that these
regulatory assets will be fully recoverable. However, if in the future, as a
result of regulatory changes or increased competition, the Company's ability to
recover these regulatory assets would not be probable, then to the extent that
such regulatory assets were determined not to be recoverable, the Company would
be required to write-off or write-down such assets.
PROPERTY, PLANT AND EQUIPMENT
Property, Plant and Equipment primarily consists of LPSC regulated
generation assets utilized for retail operations and electric transmission and
distribution properties. Electric utility plant is stated at the original cost
of construction, which includes certain materials, labor, payroll taxes and
benefits, administrative and general costs, and the estimated cost of funds used
during construction. The cost of repairs and minor replacements is charged as
incurred to the appropriate operating expense and clearing accounts. The cost of
improvements is capitalized. Upon retirement or disposition, the recorded cost
of depreciable plant and the cost of removal, net of salvage value, are charged
to accumulated depreciation.
F-10
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The table below discloses the amounts of plant acquisition adjustments
reported in the Company's property, plant and equipment and the associated
accumulated amortization reported in accumulated depreciation. The plant
acquisition adjustment relates primarily to the acquisition of Teche Electric
Cooperative, Inc., in 1997.
AT DECEMBER 31,
(IN THOUSANDS)
1999 1998
------------- -------------
Plant acquisition adjustment $5,377 $5,377
Less accumulated amortization (698) (446)
------ ------
Total plant acquisition adjustment $4,679 $4,931
====== ======
The provision for depreciation is computed using the straight-line method
at rates that will amortize the unrecovered cost of depreciable property over
its estimated useful life. Annual depreciation provisions expressed as a
percentage of average depreciable property were 3.28% for 1999, 3.32% for 1998
and 3.27% for 1997.
CASH EQUIVALENTS
The Company considers highly liquid, marketable securities and other
similar instruments with original maturity dates of three months or less at the
time of purchase to be cash equivalents.
INCOME TAXES
Deferred income taxes are provided at the current enacted income tax rate
on all temporary differences between tax and book basis of assets and
liabilities. The Company recognizes regulatory assets and liabilities for the
tax effect of temporary differences, which, to the extent past ratemaking
practices are continued by regulators, will be realized over the accounting
lives of the related properties. Cleco consolidated current and deferred taxes
are allocated to the Company using the separate taxpayer method as defined in
SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109).
INVESTMENT TAX CREDITS
Investment tax credits, which were deferred for financial statement
purposes, are amortized to income over the estimated service life of the
properties that gave rise to the credits.
DEBT EXPENSE, PREMIUM AND DISCOUNT
Expense, premium and discount applicable to debt securities are amortized
to income ratably over the lives of the related issues. Expense and call premium
related to refinanced Company debt are deferred and amortized over the remaining
life of the original issue.
F-11
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
REVENUES AND FUEL COSTS
UTILITY REVENUES. Revenues from sales of electricity are recognized
based upon the amount of energy delivered. The cost of fuel and purchased power
used for retail customers is currently recovered from customers through fuel
adjustment clauses, based upon fuel costs incurred in prior months. These
adjustments are subject to audit and final determination by regulators.
ENERGY MARKETING AND AFFILIATE REVENUES. Revenues are recognized at the
time products or services are provided to customers.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The capitalization of AFUDC is a utility accounting practice prescribed
by the FERC and the LPSC. AFUDC represents the estimated cost of financing
construction work-in-progress. AFUDC does not represent a current source of
cash, but 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 on a combined basis, for 1999 was
13.75% on a pretax basis (8.46% net of tax), for 1998 was 13.49% on a pretax
basis (8.30% net of tax), and for 1997 was 13.97% on a pre-tax basis (8.59% net
of tax).
RISK MANAGEMENT
The market risk inherent in the Company's market risk-sensitive
instruments and positions is the potential change arising from increases or
decreases in the short-, medium- and long-term interest rates, the commodity
price of electricity traded on the Into Entergy and the Cinergy exchanges and
the commodity price of natural gas traded. Generally, the Company's market risk-
sensitive instruments and positions are characterized as "other than trading;"
however, the Company does have positions that are considered "trading" as
defined by Emerging Issues Task Force Consensus No. 98-10 (EITF 98-10).
Positions that are considered "trading" under EITF 98-10 are marked-to-market at
the end of reporting periods. The mark-to-market gains or losses are reflected
in the income statement in the energy marketing revenue line item. The off-
setting unrealized gain or loss is recorded on the balance sheet in other
current assets or other current liabilities. Positions that are considered
"other than trading" under EITF 98-10 are accounted for under the deferral
method. Under SFAS No. 80, income or loss in such positions is deferred until
the underlying transactions have been realized
RECENT ACCOUNTING STANDARDS
SFAS No. 133, "Accounting for Derivatives Instruments and Hedging
Activities," was to be implemented during the Company's fiscal year ending
December 31, 2000. SFAS No. 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133,"
delayed the implementation of SFAS No. 133 until all fiscal years beginning
after June 15, 2000. The Company expects to adopt SFAS No. 133 for the fiscal
year beginning January 1, 2001. The effect of adopting SFAS No. 133 has not
been determined.
F-12
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
EARNINGS PER AVERAGE COMMON SHARE
Earnings per average common share (EPS) is computed using the weighted
average number of shares of common stock outstanding during the year. EPS is
reported for the years 1999, 1998 and 1997 to reflect the Company's adoption of
SFAS No. 128, "Earnings per Share."
The following table is a reconciliation of the components in the
calculation of basic and diluted earnings per share.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1999 1998 1997
----------------------------------------------------------------------------------------------------------------
INCOME SHARES PER SHARE INCOME SHARES PER SHARE INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT (NUMERATOR) (DENOMINATOR) AMOUNT (NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- --------- ----------- ------------- ---------- ----------- ------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net income $56,683 $53,801 $52,519
Less: preferred
Dividend
Requirements, net (1,047) (2,137) (2,117)
------- -------
BASIC EPS
Income available
for common
shareholders 55,636 $2.47 51,664 22,480 $2.30 50,402 22,460 $2.24
===== ===== =====
EFFECT OF DILUTIVE
SECURITIES
Stock option grants 0 7 7
Convertible ESOP
Preferred stock 856 730 1,707 1,380 1,646 1,397
--- ------- ------ ------- ------
DILUTED EPS
Income available
to common
shareholders +
assumed conversions $56,492 730 $2.43 $53,371 23,867 $2.24 $52,048 23,864 $2.18
======= === ===== ======= ====== ===== ======= ====== =====
</TABLE>
NOTE C -- JOINTLY OWNED GENERATING UNITS
Two electric generating units operated by the Company are jointly owned
with other utilities. The Company's proportionate share of operation and
maintenance expenses associated with these two units is reflected in the
financial statements.
At December 31, 1999
-----------------------------------
Rodemacher Dolet Hills
Unit #2 Unit #1
------------------ --------------
(Dollar amounts in thousands)
Percentage of ownership................ 30% 50%
Utility plant in service............... $85,372 $274,231
Accumulated depreciation............... $44,519 $111,510
Unit capability (megawatts)............ 523.0 650.0
Share of capability (megawatts)........ 156.9 325.0
F-13
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
NOTE D -- FAIR VALUE OF FINANCIAL INSTRUMENTS
The amounts reflected in the financial statements at December 31, 1999
and 1998, for cash and cash equivalents, accounts receivable, accounts payable
and short-term debt approximate fair value because of their short-term nature.
The fair value of the Company's long-term debt and nonconvertible preferred
stock is estimated based upon the quoted market price for the same or similar
issues or by a discounted present value analysis of future cash flows using
current rates obtainable by the Company for debt and preferred stock with
similar maturities. The fair value of convertible preferred stock is estimated
assuming its conversion into common stock at the market price per common share
at December 31, 1998, with proceeds from the sale of the common stock used to
repay the principal balance of the Company's loan to the Employee Stock
Ownership Plan (ESOP). The estimated fair value of energy market positions is
based upon observed market prices when available and when such market prices are
not available, management estimates market value at a discrete point in time
based on market conditions and observed volatility. These estimates are
subjective in nature and involve uncertainties. Therefore actual results may
differ from these estimates.
<TABLE>
<CAPTION>
AT DECEMBER 31,
-------------------------------------------------------------------
1999 1998
------------------------------- -----------------------------
CARRYING ESTIMATED CARRYING ESTIMATED
VALUE FAIR VALUE VALUE FAIR VALUE
-------------- -------------- ------------- -------------
<S> <C> <C> <C> <C>
(In thousands)
Financial instruments not marked-to-market
Long-term debt........................................ $386,260 $380,133 $376,698 $400,738
Preferred stock
Not subject to mandatory redemption................. - - $ 12,795 $ 28,567
Subject to mandatory redemption..................... - - $ 5,680 $ 5,143
ORIGINAL ESTIMATED CARRYING ESTIMATED
VALUE FAIR VALUE VALUE FAIR VALUE
-------------- -------------- ------------- -------------
Financial instruments marked-to-market
Energy Market Positions...............................
Assets.............................................. $ 9,209 $ 8,089 - -
Liabilities......................................... $ 4,960 $ 4,266 - -
</TABLE>
The financial instruments not marked-to-market are reported on the
Company's balance sheet at carrying value. The financial instruments marked-to-
market represent off-balance-sheet risk because, to the extent the Company has
an open position, it is exposed to the risk that fluctuating market prices may
adversely impact its financial position or results of operations upon
settlement. Original value represents the fair value of the positions at the
time originated.
NOTE E -- DEBT
The Company has a revolving credit facility totaling $100 million. This
facility provides for uncollateralized borrowings at prevailing interest rates
and is scheduled to expire on June 15, 2000. This facility also provides for
borrowings at interest rates established by competitive bid. Commitment fees are
based upon the Company's lowest secured debt ratings
F-14
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
and are currently 0.10%. Compensating balances are not maintained in connection
with the facility. In addition, the Company has an uncommitted borrowing
arrangement with a bank in the amount of $5. million. The bank is not obligated
to lend under this uncommitted arrangement, and any borrowings are made at
negotiated interest rates and are uncollateralized. No fees are paid on the
uncommitted arrangement, nor are compensating balances required.
F-15
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
Total indebtedness as of December 31, 1999 and 1998 were as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS)
AT DECEMBER 31,
-----------------------------------------------
1999 1998
---------------------- ----------------------
<S> <C> <C>
Commercial paper, net $ 5,989 $ 68,226
Short-term bank loans - 190
-------- --------
Total short-term debt $ 5,989 $ 68,416
======== ========
First mortgage bonds
Series X, 9 1/2%, due 2005 $ 60,000 $ 60,000
Pollution control revenue bonds, variable rate, due
2018 - 61,260
Pollution control revenue bonds, fixed rate of 5.875%,
Due 2029, callable after September 1, 2009 61,260 -
Long-term bank loans - 10,438
Medium-term notes
7.85%, due 2000 25,000 25,000
7.55%, due 2004, callable at 100%, 2002 15,000 15,000
7.50%, due 2004, callable at 100%, 2002 10,000 10,000
7.00%, due 2003 10,000 10,000
5.90%, due 1999 - 10,000
6.55%, due 2003 15,000 15,000
6.33%, due 2002 25,000 25,000
5.78%, due 2001 10,000 10,000
6.20%, due 2006 15,000 15,000
6.42%, due 2001 15,000 15,000
6.95%, due 2006 10,000 10,000
6.53%, due 2007 10,000 10,000
6.32%, due 2006 15,000 15,000
6.28%, due 2008, putable at 100%, 1999 - 20,000
7.50%, due 2007 15,000 15,000
7.00%, due 2007 25,000 25,000
6.52%, due 2009 50,000 -
-------- --------
Total medium-term notes 265,000 245,000
-------- --------
Gross amount of long-term debt 386,260 376,698
Less:
Amount due within one year (25,000) (33,330)
Unamortized premium and discount, net (921) (326)
-------- --------
Total long-term debt, net $360,339 $343,042
======== ========
</TABLE>
<TABLE>
<CAPTION>
(In thousands)
2000 2001 2002 2003 2004 Thereafter
------- ------- ------- ------- ------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Amounts payable under long-
term debt agreements $25,000 $25,000 $25,000 $25,000 $25,000 $261,260
======= ======= ======= ======= ======= ========
</TABLE>
The weighted average interest rate on short-term debt at December 31,
1999, was 6.42% compared to 5.26% at December 31, 1998.
F-16
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The first mortgage bonds are collateralized by the LPSC jurisdictional
property, plant and equipment within the Company. In the various parishes that
contain such property, a lien is filed with the clerk of court. Before the
Company can sell any of this property, it must get a release signed by the
trustee.
The three issues of the Company's 1991 series pollution control bonds
totaling $61.3 million were refinanced on September 2, 1999. Two new series
were issued to replace the old bonds, which were retired using the legal
defeasance method and removed from the balance sheet as permitted under SFAS No.
125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities." The new bonds were issued at a fixed rate with
a coupon of 5.875% and were discounted and sold at 98.956%, with a final
maturity of September 1, 2029, subject to optional redemption by the Company
after September 1, 2009.
The bonds are insurance-backed, thereby fixing the cost of the credit
support for the life of the bonds. In a related transaction, an interest rate
lock agreement was entered into for the notional amount of the bonds,
effectively locking the rate of the bonds at 5.663% for the 30-year period. The
Company received approximately $1.8 million from the interest rate lock
counterparty upon settlement, which will be amortized over the life of the
bonds.
NOTE F -- COMMON STOCK
Effective July 1, 1999 Cleco Utility Group Inc. reorganized to a holding
company structure. Under the terms of the reorganization, Cleco became the
owner of all of Utility Group's outstanding common stock, and the holders of
existing common and two series of preferred stock exchanged their stock in
Utility Group for stock in Cleco. As of July 1, 1999, the Company's common stock
is no longer listed on an exchange.
In association with incentive compensation plans in effect during the
two-year period ended December 31, 1998, certain officers and key employees of
the Company and its subsidiaries were awarded shares of restricted Company
common stock. The cost of the restricted stock awards, as measured by the market
value of the common stock at the time of the grant, is recorded as compensation
expense during the periods in which the restrictions lapse. As of December 31,
1999, the number of shares of restricted stock previously granted for which
restrictions had not lapsed was zero due to the reorganization.
F-17
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
Changes in incentive shares for the three-year period ended December 31,
1999, were as follows:
<TABLE>
<CAPTION>
Incentive Share
-------------------------------------------------------------
Option Price Unexercised Available for
per Share Option Shares Future Grants
----------------- ------------------ ------------------
<S> <C> <C> <C>
Balance, January 1, 1997................................... 18,400 731,851
------- --------
Options exercised.......................................... $16.780 (2,600) -
Restricted stock granted................................... - (20,904)
Restricted stock forfeited................................. - 793
Incentive stock awarded.................................... - (3,701)
------- --------
Balance, December 31, 1997................................. 15,800 708,039
Options exercised.......................................... $16.780 (5,000) -
Options granted (directors)................................ $31.875 12,503 (12,503)
Restricted stock granted................................... - (21,362)
Restricted stock forfeited................................. - 2,543
------- --------
Balance, December 31, 1998................................. 23,303 676,717
Options exercised.......................................... $16.780 (10,800) -
Options moved to holding company........................... (12,503) (676,717)
------- --------
Balance, December 31, 1999................................. - -
======= ========
</TABLE>
Had the compensation cost for the Company's stock-based compensation
plans been determined consistent with SFAS 123, the Company's net income and net
income per common share would approximate the pro forma amounts below:
<TABLE>
<CAPTION>
For the year ended December 31,
(In thousands except per share amounts)
1998 1997
-------------------------- ----------------------------
AS Pro AS Pro
Reported Forma Reported Forma
------------ ----------- ------------ -------------
<S> <C> <C> <C> <C>
SFAS 123 expense $ $ 525 $ $ 382
Estimated reduction in income
tax for SFAS 123 expense (173) (126)
------- ------- ------- -------
Net income applicable to
Common stock $51,664 $51,312 $50,402 $50,146
======= ======= ======= =======
Net income per basic common
Share $ 2.30 $ 2.28 $ 2.24 $ 2.23
======= ======= ======= =======
</TABLE>
As a result of the holding company structure reorganization, all options
on Company stock were exchanged for options on Cleco stock. All options
outstanding on the Company common stock were cancelled.
F-18
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The assumptions used to calculate the additional compensation expense are as
follows:
<TABLE>
<CAPTION>
For the year ended December 31,
-----------------------------------------------------------
1999 1998 1997
------------------ ------------------ -----------------
<S> <C> <C> <C>
Expected term (in years) 6.31 5.00 N/A
Volatility 12.94% 12.29% N/A
Expected dividend yield 5.11% 5.05% N/A
Risk-free interest rate 5.94% 5.79% N/A
Weighted average fair value (Black Scholes value) $ 2.15 $ 3.13 N/A
</TABLE>
The effects of applying SFAS 123 in this pro forma disclosure are not
necessarily indicative of future amounts. SFAS 123 does not apply to awards
prior to 1995.
NOTE G -- PREFERRED STOCK
All shares of the 4.5% Series 1955, 4.65% Series 1964, and 4.75% Series
1965 of preferred stock of the Company were redeemed at a cost of $5.7 million
in June 1999. The shareholders of these series of preferred stock voted "no" on
the formation of the holding company in May 1999. As part of the share exchange
agreement, preferred shareholders of these series had their shares redeemed.
In connection with the establishment of the ESOP, the Company sold
300,000 shares of 8.125% convertible preferred stock to the ESOP. As part of the
holding company reorganization, each share of the Company's 8.125% convertible
preferred stock was exchanged for one share of Cleco's 8.125% convertible
preferred stock. The amount of preferred stock relating to the ESOP was
transferred net of deferred compensation relating to the convertible preferred
stock held by the ESOP.
F-19
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
Information about the components of preferred stock capitalization is as
follows:
<TABLE>
<CAPTION>
(In thousands, except share amounts)
Balance Balance Balance BALANCE
Jan. 1, Dec. 31, Dec. 31, DEC. 31,
1997 Change 1997 Change 1998 Change 1999
----------- -------- ----------- -------- ----------- ------------ --------
<S> <C> <C> <C> <C> <C> <C> <C>
CUMULATIVE PREFERRED STOCK,
$100 par value
NOT SUBJECT TO MANDATORY
REDEMPTION
4.50%.................................. $ 1,029 $ 1,029 $ 1,029 $ (1,029) -
Convertible, Series of 1991,
Variable rate.......................... 29,251 (178) 29,073 (384) 28,689 (28,689) -
---------- ------- ---------- ------- ---------- -----------
$ 30,280 $ (178) $ 30,102 $ (384) $ 29,718 $ (29,718) -
========== ======= ========== ======= ========== ===========
SUBJECT TO MANDATORY REDEMPTION
4.50%, Series of 1955.................... 360 (40) 320 (40) 280 (280) -
4.65%, Series of 1964.................... 3,080 (140) 2,940 (140) 2,800 (2,800) -
4.75%, Series of 1965.................... 2,932 (72) 2,860 (260) 2,600 (2,600) -
---------- ------- ---------- ------- ---------- -----------
$ 6,372 $ (252) $ 6,120 $ (440) $ 5,680 $ (5,680) -
========== ======= ========== ======= ========== ===========
Deferred compensation related to
convertible preferred stock held
by the ESOP.............................. $ (20,751) $ 1,985 $ (18,766) $ 1,843 $ (16,923) $ (16,923) -
========== ======= ========== ======= ========== ===========
CUMULATIVE PREFERRED STOCK,
$100 par value
Number of shares
Authorized............................. 1,412,125 (2,125) 1,410,000 (4,000) 1,406,000 (1,406,000) -
Issued and outstanding................. 366,519 (4,301) 362,218 (8,240) 353,978 (353,978) -
========== ======= ========== ======= ========== ===========
CUMULATIVE PREFERRED STOCK,
$25 par value
Number of shares authorized
(None outstanding)..................... 3,000,000 3,000,000 3,000,000 (3,000,000) -
========== ========== ========== ===========
</TABLE>
NOTE H -- PENSION PLAN AND EMPLOYEE BENEFITS
Substantially all employees of the Company and employees of its
affiliates are covered by a noncontributory, 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 the Company. The
Company's policy is to fund contributions to the employee pension plan based
upon actuarial computations utilizing the projected unit credit method, subject
to the Internal Revenue Service's full funding limitation. No contributions to
the pension plan were required during the three-year period ended December 31,
1999.
The Company is the plan sponsor of the pension plan. The Company is
reimbursed by its affiliates for the service costs incurred by affiliate
employees incurred while the employees are in the employ of the affiliates.
During 1999, the service costs were immaterial.
The Company's retirees and their dependents are eligible to receive
health, dental and life insurance benefits (other benefits). The Company
recognizes the expected cost of these benefits during the periods in which the
benefits are earned.
F-20
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The employee pension plan, other benefits obligation plan assets and
funded status as determined by the actuary at December 31, 1999 and 1998 are
presented in the following table.
<TABLE>
<CAPTION>
(In thousands)
PENSION BENEFITS OTHER BENEFITS
1999 1998 1999 1998
--------------------------------------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning of year................. $132,721 $123,082 $ 16,602 $ 15,379
Service cost............................................ 4,353 3,734 661 671
Interest cost........................................... 9,198 8,326 1,099 1,062
Plan participants contributions......................... 338 311
Actuarial (gain)/loss................................... (8,728) 4,591 (1,624) 176
Expenses paid........................................... (1,254) (1,100) - -
Benefits paid........................................... (6,320) (5,912) (882) (997)
-------- -------- -------- --------
Benefit obligation at end of year....................... 129,970 132,721 16,194 16,602
-------- -------- -------- --------
Change in plan assets
Fair value of plan assets at beginning of year.......... 181,698 163,574 - -
Actual return on plan assets............................ 10,489 25,136 - -
Expense paid............................................ (1,254) (1,100) - -
Benefits paid........................................... (6,320) (5,912) - -
-------- -------- -------- --------
Fair value of plan assets at end of year................ 184,613 181,698 - -
-------- -------- -------- --------
Funded status............................................ 54,643 48,977 (16,194) (16,602)
Unrecognized net actuarial (gain)....................... (53,369) (48,421) (3,058) (1,434)
Unrecognized transition obligation/(asset).............. (5,308) (6,625) 6,673 7,186
Prior service cost...................................... 12,775 13,745 - -
-------- -------- -------- --------
Prepaid/(accrued) benefit cost.......................... $ 8,741 $ 7,676 $(12,579) $(10,850)
======== ======== ======== ========
</TABLE>
Employee pension plan assets were invested in Cleco's common stock, other
publicly traded domestic common stocks, U.S. government, federal agency and
corporate obligations, an international equity fund, commercial real estate
funds and pooled temporary investments.
Effective January 1, 1998, the Company changed the method of calculating
fair market value of assets to reflect the difference between actual and
projected appreciation for the current year ratably over five years. This change
has been reflected in the table above. Effective January 1, 1998, the Company
increased the crediting rates for each year of service but limited the maximum
number of years of service credited to 35. This change has been reflected in
the table above.
F-21
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The components of net periodic pension and other benefits cost (income)
for 1999, 1998 and 1997 are as follows, along with assumptions used:
<TABLE>
<CAPTION>
(In thousands)
PENSION BENEFITS OTHER BENEFITS
--------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
--------- --------- --------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Components of periodic benefit costs
Service cost.......................... $ 4,353 $ 3,734 $ 2,984 $ 661 $ 671 $ 601
Interest cost......................... 9,198 8,326 7,288 1,099 1,062 1,034
Expected return on plan assets........ (14,267) (12,797) (10,290)
Amortization of transition
Obligation(asset)................... (1,317) (1,318) (1,317) 513 513 513
Prior period service cost
Amortization........................ 969 969 347
Net (gain)loss........................ (142) (66) (82)
-------- -------- -------- ------ ------ ------
Net periodic benefit cost/(income).... $ (1,064) $ (1,228) $ (988) $2,273 $2,180 $2,066
======== ======== ======== ====== ====== ======
PENSION BENEFITS OTHER BENEFITS
--------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
--------------------------------------------------------------------------------
Weighted-average assumptions as of
December 31:
Discount rate....................... 7.50% 6.75% 7.00% 7.50% 6.75% 7.00%
Expected return on plan assets...... 9.50% 9.50% 9.50% N/A N/A N/A
Rate of compensation increase....... 5.00% 5.00% 5.00% N/A N/A N/A
</TABLE>
The assumed health care cost trend rate used to measure the expected cost
of other benefits was 8.5% in 1999 and 9.5% in 1997 and 1998. The initial
health care cost trend rate was reduced from 10% in 1996 to 9.5% in 1998 and to
8.5% in 1999, which resulted in an unrecognized gain. Assumed health care cost
trend rates have a significant effect on the amount reported for the health care
plans. A one-percentage point change in assumed health care cost trends rates
would have the following effects on other benefits:
<TABLE>
<CAPTION>
(In thousands)
1-PERCENTAGE POINT
---------------------------------------
INCREASE DECREASE
--------------- ------------------
<S> <C> <C>
Effect on total of service and interest cost components.................. $119 $(121)
Effect on postretirement benefit obligation.............................. $912 $(943)
</TABLE>
Substantially all employees are eligible to participate in a savings and
investment plan (401(k) Plan). The Company makes matching contributions to
401(k) Plan participants by allocating shares of Cleco's convertible preferred
stock held by the ESOP. Compensation expense related to the 401(k) Plan is based
upon the value of shares of preferred stock allocated to ESOP participants and
the amount of interest incurred by the ESOP, less dividends on unallocated
shares held by the ESOP. At December 31, 1999 and 1998, the ESOP had allocated
to employees 139,086 and 124,984 shares, respectively.
F-22
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The table below contains information about the 401(k) Plan and the ESOP:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
(In thousands)
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
401(k) Plan expense.................................................... $1,021 $1,107 $1,453
Dividend requirements to ESOP on convertible preferred stock........... $1,047 $2,341 $2,367
Interest incurred by ESOP on its indebtedness.......................... $1,296 $1,683 $1,604
Company contributions to ESOP.......................................... $ 0 $1,075 $1,235
</TABLE>
NOTE I -- INCOME TAX EXPENSE
Federal income tax expense is less than the amount computed by applying
the statutory federal rate to book income before tax as follows:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
(In thousands, except for %)
1999 1998 1997
----------------- ----------------- -----------------
AMOUNT % Amount % Amount %
-------- ------ -------- ------ -------- ------
<S> <C> <C> <C> <C> <C> <C>
Book income before tax...................................... $83,955 100.0 $80,467 100.0 $80,248 100.0
Tax at statutory rate on book income before tax............. 29,384 35.0 28,163 35.0 28,087 35.0
Increase (decrease):
Tax effect of AFUDC....................................... (261) (0.3) (601) (0.8) (276) (0.3)
Amortization of investment tax credits.................... (1,790) (2.1) (1,790) (2.2) (1,790) (2.2)
Tax effect of prior-year tax benefits not deferred........ 1,119 1.3 2,175 2.7 978 1.2
AFUDC gross up - FASB 109................................. (1,548) (1.8) (1,009) (1.3) (1,123) (1.4)
Other, net................................................ (2,550) (3.0) (2,443) (3.0) (1,522) (1.9)
------- ------- -------
Total federal income tax expense............................ 24,354 29.0 24,495 30.4 24,354 30.4
Current state income tax expense............................ 2,918 3.5 2,171 2.7 3,375 4.2
------- -------
Total federal and state income tax expense.................. $27,272 32.5 $26,666 33.1 $27,729 34.6
======= ======= ----- ------- =====
</TABLE>
F-23
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
Information about current and deferred income tax expense is as follows:
<TABLE>
<CAPTION>
(In thousands)
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Current federal income tax expense..................... $17,675 $17,582 $23,236
Deferred federal income tax expense.................... 8,469 8,703 2,908
Amortization of accumulated deferred investment tax (1,790) (1,790) (1,790)
credits.............................................. ------- ------- -------
Total federal income tax expense....................... 24,354 24,495 24,354
Current state income tax expense....................... 2,918 2,171 3,375
------- ------- -------
Total federal and state income tax expense............. $27,272 $26,666 $27,729
======= ======= =======
Deferred federal income tax expense attributable to:
Depreciation......................................... $ 8,428 $11,748 $ 2,733
Storm damages........................................ 912 492 (332)
Asset basis differences.............................. (2,717) (571) (1,707)
Employee benefits.................................... 222 (419) 321
Fuel costs........................................... 660 (612) 790
Reacquired debt...................................... (269) (249) 1,037
Other................................................ 1,233 (1,686) 66
------- ------- -------
Total deferred federal income tax expense............ $ 8,469 $ 8,703 $ 2,908
======= ======= =======
</TABLE>
The balance of accumulated deferred federal and state income tax assets
and liabilities at December 31, 1999 and 1998, was comprised of the tax effect
of the following:
<TABLE>
<CAPTION>
(In thousands)
1999 1998
------------------------- ---------------------------
ASSET LIABILITY Asset Liability
----------- ----------- ----------- -------------
<S> <C> <C> <C> <C>
Depreciation and property basis differences................. $ 6,653 $152,971 $ 6,584 $143,975
Allowance for funds used during construction................ - 42,974 - 39,270
Investment tax credits...................................... 15,979 - 17,378 -
FASB 109 adjustments........................................ 92,417 110,315 62,235 92,513
Postretirement benefits other than pension.................. 4,723 - 3,700 -
Other....................................................... 5,345 14,661 7,448 10,861
-------- -------- ------- --------
Accumulated deferred federal and state income taxes......... $125,117 $320,921 $97,345 $286,619
======== ======== ======= ========
</TABLE>
Regulatory assets recorded for deferred taxes at December 31, 1999 and
1998, were $115.9 million and $95.2 million, respectively. Regulatory
liabilities recorded for deferred taxes at December 31, 1999 and 1998, were
$97.1 million and $81.0 million, respectively. Regulatory assets and liabilities
will be realized over the accounting lives of the related properties to the
extent past ratemaking practices are continued by regulators.
NOTE J -- ACCRUAL OF ESTIMATED CUSTOMER CREDITS
The Company's reported earnings in the year ended December 31, 1999,
reflect a $2.8 million accrual for estimated customer credits that may be
required under terms of an earnings review settlement reached with the LPSC in
1996. The 1996 LPSC settlement, and a subsequent amendment, set the company's
rates until the year 2004 and also provided for annual base rate
F-24
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
tariff reductions of $3 million in 1997 and $2 million in 1998. As part of the
settlement, the Company is allowed to retain all regulated earnings up to a
12.25% return on equity and to share equally with customers as credits on their
bills all regulated earnings between 12.25% and 13% return on equity. All
regulated earnings above a 13% return on equity are credited to customers. The
amount of credits due customers, if any, is determined by the LPSC annually
based on 12-month-ending results as of September 30 of each year. The settlement
provides for such credits to be made on customers' bills the following summer.
Of the $2.8 million, $2.2 million relates to the 12-month-ended September
30, 1998, cycle, and the remaining $0.6 million relates to the estimated refund
for the 12-month-ended September 30, 1999, cycle. The adjustment for the prior
year's estimate of the refund for the 1998 cycle was due to the LPSC's final
report on the 1998 cycle. The $2.8 million was recorded as a reduction in
revenue due to the nature of the customer credits. The amount of the credit for
the cycle ending September 30, 1999, if any, has not yet been determined by the
LPSC.
NOTE K -- SIGNIFICANT NON-CASH TRANSACTIONS
On July 1, 1999, 246,684 shares of the Company's common stock held as
treasury stock, with a cost of approximately $5 million, were cancelled as a
part of the holding company restructuring.
In 1998, Utility Construction & Technology Solutions LLC (UtiliTech), an
affiliate of the Company, entered into a contract with the Company to provide
geographic information system (GIS) services required by the Company. In 1998,
the GIS assets were transferred to UtiliTech from the Company at net book value
at the date of transfer of approximately $1.6 million. During the third quarter
of 1999, UtiliTech decided to cease offering GIS services. As shown in the
Statement of Changes in Shareholder's Equity, the related GIS assets were
transferred back to the Company at net book value.
On July 1, 1999, all subsidiaries of the Company and all of the common
stock of the Company were dividended to Cleco as a part of reorganizing into a
holding company structure. The book value of the membership interest and common
stock of subsidiaries and the common stock of the Company dividended was
approximately $30.6 million.
NOTE L -- AFFILIATE TRANSACTIONS
Effective July 1, 1999, the Company entered into service agreements with
affiliates, which provide the Company access to professional services and goods.
The service and goods are charged to the Company at the lower of fair market
value or fully loaded costs in order to comply with Cleco's interaffiliate
policy. A summary of charges from each affiliate included in the Statement of
Income and Balance Sheet follows:
F-25
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
1999
(In thousands)
Statement of Balance
Income Sheet
------------ --------
<S> <C> <C>
Cleco
Other operation $ 70
Other income (expense), net 2
Cleco Marketing & Trading LLC
Other operation 1,638
Other income (expense), net 241
Cleco Evangeline LLC
Maintenance 86
CLE Intrastate Pipeline Company, Inc.
Fuel used for electric generation 1,412
Utility Construction & Technology Solutions LLC
Property, plant and equipment $690
Other operations 75
Maintenance 58
------
Total $3,582 $690
====== ====
</TABLE>
Prior to July 1, 1999, the affiliates were subsidiaries of the Company
and their operations were included with those of the Company and reflected in
other income/(expenses), net.
The Company also entered into agreements to provide goods and services to
affiliated companies. The goods and services are charged by the Company at the
higher of fully loaded cost or fair market value in order to comply with Cleco's
interaffiliate policy. Following is a reconciliation of the Company's
intercompany revenues:
(In thousands)
1999
---------------------
Cleco $ 19
Cleco Midstream Resources LLC 236
Utility Construction & Technology Solutions LLC 2,494
Cleco Support Group LLC 138
Cleco Evangeline LLC 3,841
Cleco Marketing & Trading LLC 978
CLE Intrastate Pipeline Company, Inc. 110
------
Total $7,816
======
F-26
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The Company has the following affiliate receivable and payable balances
associated with the service agreements between the Company and its affiliates:
<TABLE>
<CAPTION>
1999
Accounts Accounts
Receivable Payable
---------- --------
<S> <C> <C>
Cleco $ 7,525
Utility Construction & Technology Solutions LLC 1,676
CLE Pipeline Company, Inc. $1,352
Cleco Evangeline LLC 11,395
Cleco Midstream Resources LLC 1,405
Cleco Marketing & Trading LLC 7,892
Others 623
------- ------
$22,624 $9,244
======= ======
</TABLE>
During the period July 1, 1999 to December 31, 1999, the Company paid
cash dividends to Cleco of approximately $39.8 million.
NOTE M -- DISCLOSURES ABOUT SEGMENTS
The Company has determined that its reportable segments are based on the
Company's method of internal reporting, which disaggregates its business units
by first-tier subsidiary. The Company's reportable segments are Utility Group,
Midstream and UtiliTech. Reportable segments were determined by applying SFAS
No. 131, "Disclosures about Segments of an Enterprise and Related Information."
Each reportable segment engages in business activities from which it earns
revenues and incurs expenses. Segment managers report at least monthly to the
Company's CEO (the chief decision maker) with discrete financial information and
present quarterly discrete financial information to the Company's Board of
Directors. Budgets were prepared by each reportable segment for 2000, which were
presented to, and approved by, Company's Board of Directors.
The Other segment consists of costs within Cleco prior to the holding
company restructuring, start-up costs associated with a retail services
subsidiary, and revenue and expenses associated with an investment subsidiary.
These subsidiaries operate within Louisiana and Delaware. The financial results
of the Company's segments are presented on an accrual basis. Significant
differences among the accounting policies of the segments as compared to the
Company's financial statements principally involve the classification of
revenue and expense between operating and other. Management evaluates the
performance of its segments and allocates resources to them based on segment
profit/(loss) before income taxes and preferred stock dividends. In years 1997,
1998 and the first six months of 1999, Midstream and UtiliTech reported
profit/(loss) as other income (expense) within Utility Group. For purposes of
this footnote, gross amounts of revenue and expenses are reported on the
appropriate line. The Unallocated Items, Reclassifications & Eliminations
column reclassifies the items of revenue and expense recorded under the equity
method to other income(expense). Material intersegment transactions occur on a
regular basis.
F-27
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
The results for Midstream, UtiliTech and other subsidiaries reflect the
first six months of activity in 1999. Effective July 1, 1999, Midstream,
UtiliTech and the other subsidiaries were dividended to Cleco and ceased to be
subsidiaries of the Company.
<TABLE>
<CAPTION>
1999 UNALLOCATED ITEMS,
UTILITY RECLASSIFICATIONS &
GROUP MIDSTREAM UTILITECH OTHERS ELIMINATIONS TOTAL
----------- ---------- ---------- ------- -------------------- -----------
<S> <C> <C> <C> <C> <C> <C>
Revenues
Retail electric operations $ 508,790 $ - $ - $ - $ - $ 508,790
Energy marketing operations 237,731 - - - - 237,731
Other operations 2,080 1,326 342 (3,972) 5,757
Intersegment revenues 7,816 1,589 1,425 783 (3,797) 7,816
Customer credits (2,776) - - - - (2,776)
---------- ------- ------ ------- -------- ----------
Total operating revenue 743,745 2,080 1,326 342 (7,769) 751,561
Depreciation expense 49,285 614 133 - (747) 49,285
Interest charges 28,414 756 3 - (759) 28,414
Segment profit (loss) (1) 83,955 (306) (317) 1,095 (28,319) 54,756
Segment assets $1,418,145 - - - - $1,418,145
(1) Reconciliation of segment profit to Company profit: UNALLOCATED ITEMS
Income taxes $27,272
Preferred dividends 1,047
-------
$28,319
=======
1998
Revenues
Retail electric operations $ 487,280 - - - - $ 487,280
Energy marketing operations 32,695 $10,118 - - $(10,118) 32,695
Other operations - - $ 214 $ 865 (1,079) -
Customer credits (4,800) - - - - (4,800)
---------- ------- ------ ------- -------- ----------
Total operating revenues 515,175 10,118 214 865 (11,197) 515,175
Intersegment revenues - 3,242 297 1,443 (4,982) -
Depreciation expense 48,369 831 79 - (910) 48,369
Interest charges 27,360 792 - - (792) 27,360
Segment profit (loss) (1) 79,383 (719) (176) 1,505 (28,329) 51,664
Segment assets $1,383,648 $67,322 $3,483 $27,443 $(52,896) $1,429,000
(1) Reconciliation of segment profit to Company profit: Unallocated items
Income taxes $26,666
Preferred dividends 2,137
Other (474)
-------
$28,329
=======
</TABLE>
F-28
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
1997
Revenues
Retail electric operations $ 456,245 - - - - $ 456,245
Energy marketing operations - - - - - -
Other operations - $ 164 - $ 760 $ (924) -
Customer credits - - - - -
---------- --- ------- -------- ----------
Total Operating revenues 456,245 164 - 760 (924) 456,245
Intersegment revenues - 1,652 - 440 (2,092) -
Depreciation expense 45,890 624 - - (624) 45,890
Interest charges 28,586 440 - - (440) 28,586
Segment profit/(loss) (1) 78,938 129 - 1,158 (29,823) 50,402
Segment assets $1,383,135 $8,642 $80 $19,869 $ (5,682) $1,361,044
(1) Reconciliation of segment profit to Company profit: Unallocated items
Income taxes $27,729
Preferred dividends 2,117
Other (23)
-------
$29,823
=======
</TABLE>
NOTE O -- COMMITMENTS AND CONTINGENCIES
In recent years, the Company's construction program has consisted
primarily of enhancements to its transmission and distribution systems and
improvements at its generating stations. In 1997 the Company acquired the
assets of Teche for $22.4 million. The Company's construction expenditures,
excluding AFUDC, totaled $51.7 million in 1999 and $53.9 million in 1998,
excluding the Teche assets.
The Company construction expenditures, excluding AFUDC, for 2000 are
estimated to be $54 million and for the five-year period will support line
extensions and substation upgrades to accommodate new business and load growth.
Some investment will be made to rehabilitate older transmission, distribution
and generation assets. The Company will also continue to invest in technology
to allow it to operate more efficiently.
In 1999, 100% of the Company's construction requirements were funded
internally, as compared to 99.8% in 1998 and 100% in 1997. In 2000, 96% of
construction requirements are expected to be funded internally. For the five-
year period ending 2004, 99% of construction requirements are expected to be
funded internally.
The Company has entered into various long-term contracts for the
procurement of coal and lignite to fuel certain of its generating stations.
These contracts contain provisions for price changes, minimum purchase levels
and other financial commitments. The Company purchases, as an additional fuel
source for generation, natural gas under short-term contracts on the spot
market.
The Company and another utility filed suit against a joint venture and
its partners who mine lignite for one of the Company's jointly owned electric
generating units. The joint venture has filed counterclaims. The counterclaims
resulted in the filing of another suit by the Company
F-29
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
and the other utility against the joint venture's parent company. Management
believes the counterclaims, if successful, would not have a significant adverse
effect on the Company's financial position or results of operations. Normal day-
to-day operations continue at the mining facility and the jointly owned electric
generating unit.
The coal for one of the Company's jointly owned generating units is
transported under a long-term contract with a railroad. The railroad
experienced operating problems beginning in 1997 that resulted in reduced
volumes delivered to the unit. Throughout 1998 the delivery problems persisted,
and the coal inventory fluctuated at or below the Company's desired minimum
level. However, in 1999, the deliveries of coal by the railroad were back to
the normal schedule.
The Company has accrued for liabilities to third parties, environmental
claims, employee medical benefits, storm damages and deductibles under insurance
policies that it maintains on major properties, primarily generating stations
and transmission substations. Consistent with regulatory treatment, annual
charges to operating expense to provide a reserve for future storm damages are
based upon the average amount of noncapital, uninsured storm damages experienced
by the Company during the previous five years.
NOTE P -- MISCELLANEOUS FINANCIAL INFORMATION (UNAUDITED)
Quarterly information for the Company for 1999 and 1998 is shown in the
following table.
<TABLE>
<CAPTION>
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
----------------------------------------------------------
1999
----------------------------------------------------------
1ST 2ND 3RD 4TH
QUARTER QUARTER QUARTER QUARTER
------------ ------------ ------------ -------------
<S> <C> <C> <C> <C>
Operating revenues............................................ $121,719 $222,474 $275,810 $131,558
Operating income.............................................. $ 19,481 $ 29,519 $ 30,631 $ 5,669
Net income applicable to common stock......................... $ 8,017 $ 13,716 $ 23,537 $ 10,366
Basic net income per average common share..................... $ 0.36 $ 0.61 $ 1.04 $ 0.46
Diluted net income per average common share................... $ 0.35 $ 0.59 $ 1.04 $ 0.46
Dividends paid per common share............................... $ 0.405 $ 0.415 $ 1.817 $ 1.324
Market price per share
High........................................................ $ 35.500 $ 33.563 $ N/A $ N/A
Low......................................................... $ 28.250 $ 28.438 $ N/A $ N/A
</TABLE>
F-30
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
(In thousands, except per share amounts)
----------------------------------------------------------
1998
----------------------------------------------------------
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
------------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
Operating revenues........................................... $97,210 $128,298 $172,553 $117,114
Operating income............................................. $13,833 $ 20,946 $ 28,902 $ 16,618
Net income applicable to common stock........................ $ 6,468 $ 14,491 $ 22,320 $ 8,385
Basic net income per average common share.................... $ 0.29 $ 0.64 $ 0.99 $ 0.38
Diluted net income per average common share.................. $ 0.29 $ 0.63 $ 0.95 $ 0.37
Dividends paid per common share.............................. $ 0.395 $ 0.405 $ 0.405 $ 0.405
Market price per share
High....................................................... $34.563 $ 34.750 $ 33.875 $ 36.125
Low........................................................ $30.250 $ 29.000 $ 28.625 $ 32.875
</TABLE>
F-31
<PAGE>
UNAUDITED FINANCIAL STATEMENTS
F-32
<PAGE>
CLECO UTILITY GROUP INC.
INTERIM BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
(IN THOUSANDS)
AT SEPTEMBER AT DECEMBER
30, 2000 31, 1999
----------------------- -----------------------
<S> <C> <C>
ASSETS
Utility property, plant and equipment
Utility Property, plant and equipment $1,558,641 $1,539,435
Accumulated depreciation (585,738) (552,556)
----------------------- -----------------------
Net utility property, plant and equipment 972,903 986,879
Construction work-in-progress 34,070 26,919
----------------------- -----------------------
Total utility property, plant and equipment, net 1,006,973 1,013,798
----------------------- -----------------------
Other assets - 2,358
Current assets
Cash and cash equivalents 3,759 547
Accounts receivable 75,048 40,448
Accounts receivable - affiliate 1,864 22,624
Notes receivable- associated companies 2 2
Unbilled revenues 25,728 17,065
Fuel inventory, at average cost 7,269 10,461
Material and supplies inventory, at average cost 14,503 14,189
Accumulated deferred fuel 10,643 -
Other current assets 3,803 3,202
----------------------- -----------------------
Total current assets 142,619 108,538
----------------------- -----------------------
Prepayments 8,341 6,428
Regulatory assets - deferred taxes 70,889 70,834
Other deferred charges 33,763 33,839
Accumulated deferred federal and state income taxes 49,104 55,184
----------------------- -----------------------
TOTAL ASSETS $1,311,689 $1,290,979
======================= =======================
</TABLE>
(Continued on next page)
The accompanying notes are an integral part of the interim financial statements.
F-33
<PAGE>
CLECO UTILITY GROUP INC.
INTERIM BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
(IN THOUSANDS)
AT SEPTEMBER AT DECEMBER
30, 2000 31, 1999
------------ -----------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Common shareholder's equity
Common stock, $2 par value, authorized 50,000,000 shares,
22,531,870 outstanding at September 30, 2000 and
December 31, 1999 $ 45,064 $ 45,064
Premium on capital stock 127,312 127,477
Retained earnings 243,999 234,288
--------------------------------
Total common shareholders' equity 416,375 406,829
Long-term debt, net 335,383 360,339
--------------------------------
Total capitalization 751,758 767,168
--------------------------------
Current liabilities
Short-term debt 61,766 5,989
Long-term debt due within one year 25,000 25,000
Accounts payable 49,931 56,093
Accounts payable - Affiliate 9,857 9,244
Customer deposits 20,489 20,326
Taxes accrued 20,734 1,321
Taxes accrued - payable to parent 6,299 24,428
Interest accrued 1,633 8,788
Accumulated deferred fuel - 2,638
Other current liabilities 4,596 3,756
--------------------------------
Total current liabilities 200,305 157,583
--------------------------------
Deferred credits
Accumulated deferred federal and state income taxes 265,553 263,688
Accumulated deferred investment tax credits 24,688 25,994
Regulatory liabilities - deferred taxes 38,840 27,221
Other deferred credits 30,545 49,325
--------------------------------
Total deferred credits 359,626 366,228
--------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $1,311,689 $1,290,979
================================
</TABLE>
The accompanying notes are an integral part of the interim financial statements.
F-34
<PAGE>
CLECO UTILITY GROUP INC.
INTERIM STATEMENTS OF INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
<S> <C> <C>
2000 1999
------ ------
OPERATING REVENUES
Retail electric operations $ 462,168 $ 389,278
Energy marketing operations 13,000 230,418
Affiliate revenues 7,781 4,259
----------------------------------------
Gross operating revenue 482,949 623,955
Less: retail electric customer credits (1,233) (5,100)
----------------------------------------
Total operating revenue 481,716 618,855
----------------------------------------
OPERATING EXPENSES
Fuel used for electric generation 126,437 104,480
Power purchased for utility customers 94,425 52,966
Purchases for energy marketing operations 9,487 223,225
Other operations 58,192 54,217
Maintenance 24,372 23,320
Depreciation 37,162 37,345
Taxes other than income taxes 27,786 27,425
Federal and state income taxes 25,974 24,794
Affiliate costs 6,420 3,880
----------------------------------------
Total operating expenses 410,255 551,653
----------------------------------------
OPERATING INCOME 71,461 67,202
Allowance for other funds used during construction 656 547
Other income (expense), net (1,081) (533)
----------------------------------------
INCOME BEFORE INTEREST CHARGES 71,036 67,216
----------------------------------------
INTEREST CHARGES
Interest charges, including amortization of debt
Expenses, premium and discount 21,972 20,791
Allowance for borrowed funds used during construction (226) 108
----------------------------------------
NET INCOME BEFORE PREFERRED DIVIDENDS 49,290 46,317
Preferred dividend requirements, net - 1,047
----------------------------------------
NET INCOME APPLICABLE TO COMMON STOCK $ 49,290 $ 45,270
========================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING
Basic 22,531,870 22,522,327
Diluted 23,531,870 23,471,560
EARNINGS PER AVERAGE SHARE
Basic $2.19 $2.01
Diluted $2.19 $1.97
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK $1.76 $2.63
</TABLE>
The accompanying notes are an integral part of the interim financial statements.
F-35
<PAGE>
CLECO UTILITY GROUP INC.
INTERIM STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
(IN THOUSANDS)
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
2000 1999
-------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 49,290 $ 46,317
Adjustments to reconcile net income to net cash
Provided by operating activities
Depreciation and amortization 37,870 38,192
Allowance for funds used during construction 883 (439)
Amortization of investment tax credits (1,306) (1,343)
Deferred income taxes 7,168 (1,616)
Deferred fuel costs (13,281) (5,391)
Gain on disposition of utility plant, net - (108)
Changes in assets and liabilities
Accounts receivable, net (12,439) (34,624)
Unbilled revenues (8,663) (5,646)
Fuel inventory, materials and supplies 2,878 (8,629)
Accounts payable (4,802) 58,177
Customer deposits 163 (6)
Other deferred accounts (2,814) 4,045
Taxes accrued 1,284 36,825
Interest accrued (7,155) (5,549)
Other, net (4,607) 4,463
-------- --------
Net cash provided by operating activities 44,469 124,668
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to utility plant (31,664) (37,264)
Allowance for funds used during construction (883) 439
Proceeds from sales of utility plant 257 208
Purchase of investments - (200)
-------- --------
Net cash used in investing activities (32,290) (36,817)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock - 243
Share Exchange Agreement (165) -
Issuance of long-term debt - 50,000
Retirement of long-term debt - (10,000)
Increase (decrease) in short-term debt, net 30,777 (68,416)
Redemption of preferred stock - (6,518)
Cost of refinancing debt - (639)
Dividends paid on common and preferred stock, net (39,579) (29,676)
-------- --------
Net cash used in financing activities (8,967) (65,006)
-------- --------
NET INCREASE IN CASH AND CASH EQUIVALENTS 3,212 22,845
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 547 2,073
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 3,759 $ 24,918
======== ========
Supplementary cash flow information
Interest paid (net of amount capitalized) $ 25,344 $ 28,378
======== ========
Income taxes paid $ 23,130 $ 3,402
======== ========
</TABLE>
The accompanying notes are an integral part of the interim financial statements.
F-36
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
NOTE A -- PRESENTATION AND RECLASSIFICATION
The interim financial statements included herein are unaudited but
reflect, in management's opinion, all adjustments, consisting only of normal
recurring adjustments, that are necessary for a fair presentation of the
Company's financial position and results of operations for the interim periods
presented. The interim financial statements included herein should be read in
conjunction with the audited financial statements and notes thereto included in
this Annex F.
Certain prior-period amounts have been reclassified to conform with the
presentation shown in the current year's financial statements of the Company.
These reclassifications had no effect on net income applicable to common stock
or common shareholders' equity.
NOTE B -- LEGAL PROCEEDING: FUEL SUPPLY -- LIGNITE
The Company and Southwestern Electric Power Company (SWEPCO), each a 50%
owner of Dolet Hills Unit 1, jointly own lignite reserves in the Dolet Hills
area of northwestern Louisiana. In 1982, the Company and SWEPCO entered into
the Lignite Mining Agreement (LMA) with Dolet Hills Mining Venture (DHMV), a
partnership for the mining and delivery of lignite from a portion of these
reserves (Dolet Hills Mine). The LMA expires in 2011. The price of lignite
delivered pursuant to the LMA is a base price per ton, subject to escalation
based on certain inflation indices, plus specified "pass-through" costs.
Currently, the Company is receiving annually a minimum delivery of
1,750,000 tons under the LMA. Since the late 1980s, additional spot lignite
deliveries have been obtained through competitive bidding from DHMV and another
lignite supplier. In 1999, the Company and SWEPCO received deliveries which
approximated 25% of the annual lignite consumption at the Dolet Hills Unit 1
from the other lignite supplier.
On April 15, 1997, the Company and SWEPCO filed suit against DHMV and its
partners in the United States District Court for the Western District of
Louisiana (Federal Court Suit) seeking to enforce various obligations of DHMV to
the Company and SWEPCO under the LMA, including provisions relating to the
quality of the delivered lignite, pricing, and mine reclamation practices. On
June 15, 1997, DHMV filed an answer denying the allegations in the Federal Court
Suit and filed a counterclaim asserting various contract-related claims against
the Company and SWEPCO. The Company and SWEPCO have denied the allegations in
the counterclaims.
As a result of the counterclaims filed by DHMV in the Federal Court Suit,
on August 13, 1997, the Company and SWEPCO filed a separate lawsuit against the
parent companies of DHMV, namely, Jones Capital Corporation and Philipp Holzmann
USA, Inc., in the First Judicial District Court for Caddo Parish, Louisiana
(State Court Suit). The State Court Suit seeks to enforce a separate 1995
agreement by Jones Capital Corporation and Philipp Holzmann USA, Inc. related to
the LMA. Jones Capital Corporation and Philipp Holzmann
F-37
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
USA, Inc. have asked the state court to stay that proceeding until the Federal
Court Suit is resolved.
On March 1, 2000, the court in the Federal Court Suit ruled that DHMV was
not in breach of certain financial covenants under the LMA and denied the
Company's and SWEPCO's claim to terminate the LMA on that basis. The ruling has
no material adverse effect on the operations of the Company and does not affect
the other claims scheduled for trial. The Company and SWEPCO have appealed the
federal court's ruling to the United States Court of Appeals for the Fifth
Circuit.
The civil, non-jury trial in the Federal Court Suit was to have commenced
on May 22, 2000. However, on April 20, 2000, all parties jointly requested that
the court postpone the trial date and grant a 120-day stay of all matters before
the trial court to give the parties an opportunity to attempt to reach an
amicable resolution of the litigation. A preliminary memorandum of
understanding to settle the litigation has been executed among the Company,
SWEPCO and DHMV. The memorandum of understanding, however, is subject to
several conditions precedent that are not yet fulfilled, including prior
authorization by the Louisiana Public Service Commission (LPSC) of favorable
rate recovery of the settlement by the Company and SWEPCO. The federal court
granted the motion, stayed the action at the trial court and postponed the trial
commencement date to October 23, 2000. At a status conference held on July 12,
2000, the court extended the stay of the proceedings and again postponed the
trial date to January 16, 2001. Settlement negotiations are on-going during the
pendency of the stay.
Should settlement discussions be unsuccessful, the Company and SWEPCO
will continue aggressively to prosecute the claims against DHMV and defend
against the counterclaims that DHMV has asserted. The Company and SWEPCO
continue to pay DHMV for lignite delivered pursuant to the LMA. Normal day-to-
day operations continue at the Dolet Hills Mine and Dolet Hills Unit 1. Although
the ultimate outcome of this litigation or the settlement negotiations cannot be
predicted at this time, based on information currently available to the Company,
management does not believe that the outcome of the Federal Court Suit or any
settlement in the Federal Court Suit will have a material adverse effect on the
Company's financial position or results of operations.
NOTE C -- PROCEEDINGS BEFORE THE LPSC
Several Louisiana-based contractors providing utility line construction
services instituted a proceeding via petition with the LPSC on April 9, 1999,
alleging subsidization by the Company of a non-regulated affiliate, Cleco
Services LLC, now operating as UtiliTech. The LPSC has assigned Docket No. U-
24064 to the complaint. The complainants, LPSC staff and the Company have
conducted discovery, pre-filed testimony has been prepared and depositions
taken. On September 6, 2000, the Company and the complainants signed an
agreement to settle the dispute. The terms of the settlement did not result in
a material impact to the Company's results of operations or financial condition.
F-38
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
In connection with this proceeding, the LPSC staff has engaged the
services of an outside consultant. The outside consultant has filed testimony
on behalf of the LPSC staff identifying several possible ratemaking adjustments
to the Company's previous and future Rate Stabilization Plan filings that could
affect the Company's customer credits. On October 3, 2000, the Company and the
staff of the LPSC signed an agreement resolving all outstanding issues, which
was approved by the LPSC on November 2, 2000. The settlement will result in an
increase to the Company's customer credits of approximately $500,000, which will
be paid to customers in September 2001.
NOTE D -- DISCLOSURES ABOUT SEGMENTS
The Company has changed the structure of its internal organization, which
caused a change in the determination of reportable segments from the reportable
segments disclosed in 1999. The reorganization into a holding company structure
effective July 1, 1999 entailed the movement of all subsidiaries of the Company
to the new holding company, Cleco. The Company is a vertically integrated,
regulated electric utility operating within Louisiana and is viewed as one unit
by management. Discrete financial reports are prepared only at the company
level.
NOTE E -- PENSION PLAN
The Company is the sponsor of a defined benefit pension plan which covers
substantially all employees of the Company and its affiliates. The affiliate
companies which adopt the pension plan accrue pension expense and record a
pension liability using actuarially determined amounts without the benefit of
pension assets presently in the plan. The Company records a pension benefit
based on its actuarially determined expense, offset by the earnings of the
assets presently in the plan. If the plan required a contribution, each
affiliate would be required to contribute to the plan its prorata share of
pension liability and would begin to benefit from the earnings of its assets
contributed to the plan. During the first nine months of 2000, no
contributions were required and no contributions were made to the plan by any
participant.
NOTE F -- NEW ACCOUNTING STANDARD
Periodically, the Financial Accounting Standards Board (FASB) issues
Statements of Financial Accounting Standards (SFAS). These statements reflect
accounting, reporting and disclosure requirements the Company should follow in
the accumulation of financial data and in the presentation of financial
statements. The FASB, a nongovernmental organization, is the primary source of
generally accepted accounting principles within the United States.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133), effective for fiscal years
beginning after June 15, 1999. This statement establishes accounting and
reporting for derivative instruments, including certain derivative instruments
embedded in other contracts and for hedging activities. In June 1999, the FASB
issued SFAS No. 137, Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB Statement No. 133" (SFAS
F-39
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
No. 137), which changed the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
(SFAS No. 138), which modified certain provisions of SFAS No. 133.
We will implement the requirements of these accounting standards
effective January 1, 2001. In early 2000, we organized a cross-functional
project team for the implementation of SFAS No. 133, as amended. The team has
completed an inventory of our financial instruments, commodity contracts and
other commitments for the purpose of identifying and assessing our derivative-
related transactions.
We have entered into certain forward and option contracts for the future
purchase or sale of electricity and natural gas that meet the derivative
criteria of SFAS No. 133, as amended. We currently record changes in the fair
value (mark-to-market), due to changes in the underlying commodity prices, for
certain of these contracts in current earnings. These changes are influenced by
various market factors, including weather and the availability of regional
electric generation and transmission capacity. The cross-functional project team
has not yet determined the amount of other comprehensive income to be reflected
on statements of income and other comprehensive income. The team believes that
application of SFAS No. 133, as amended, will cause us to reflect certain
transactions in other comprehensive income based on the effectiveness of the
hedges.
NOTE G -- DEBT
A $100 million revolving credit facility expired on June 15, 2000 and a
new $100 million, 364-day revolving credit facility was finalized concurrently
with the expiration. The $100 million facility supports the issuance of
commercial paper and other general corporate purposes of the Company.
NOTE H -- AFFILIATE TRANSACTIONS
Effective July 1, 1999, the Company entered into service agreements with
affiliates, which provide the Company access to professional services and goods.
The services and goods are charged to the Company at the lower of fair market
value or fully loaded costs in order to comply with Cleco's interaffiliate
policy. A summary of charges from each affiliate included in the unaudited
interim Statement of Income and Balance Sheet follows:
F-40
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
STATEMENT OF
INCOME BALANCE SHEET
----------------- ---------------
(IN THOUSANDS)
<S> <C> <C>
Cleco
Other operation $ (20)
Deferred charges $ 895
Cleco Marketing & Trading LLC
Other operation 4,218
Accounts receivable* (36)
Deferred charges (39)
Cleco Evangeline LLC
Other operation 2
Maintenance 8
Other Income(expenses), net (77)
Property, plant and equipment (16)
Deferred charges 26
Liabilities 3
CLE Intrastate Pipeline Company, Inc.
Fuel used for electric generation 1,534
Cleco Midstream Resources
Other operation 346
Property, plant and equipment 13
Deferred charges 124
Accounts receivable 352
Fuel and materials inventory 755
Cleco Support Group LLC
Other operation 19,997
Maintenance 756
Other Income (expenses) 100
Property, plant and equipment 308
Accounts receivable 21
Fuel and materials inventory 8
Deferred charges 4,367
Cleco Generation Services LLC
Property, plant and equipment 192
Deferred charges 60
Accounts receivable 7,221
Fuel & materials inventory
Utility Construction & Technology Solutions LLC
Property, plant and equipment 1,168
Deferred charges 69
Other operations (114)
Maintenance 173
Cleco ConnecXus LLC
Property, plant and equipment 88
------- -------
Total $26,923 $15,579
======= =======
</TABLE>
*Amounts billable to our joint owners at
Rodemacher Unit 2 and Dolet Hills Unit 1
F-41
<PAGE>
CLECO UTILITY GROUP INC.
NOTES TO INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
Prior to July 1, 1999, the affiliates were subsidiaries of the Company
and their operations were included with those of the Company and reflected in
other income/(expenses), net.
The Company also entered into agreements to provide goods and services to
affiliated companies. The goods and services are charged by the Company at the
higher of fully loaded cost or fair market value in order to comply with Cleco's
interaffiliate policy. Following is a reconciliation of the Company's
intercompany revenues:
FOR THE NINE
MONTHS ENDED
SEPTEMBER 30, 2000
------------------------
(IN THOUSANDS)
Cleco Midstream Resources LLC $ 151
Utility Construction & Technology Solutions LLC 1,900
Cleco Support Group LLC 2,194
Cleco Evangeline LLC 1,519
Cleco Generation Services LLC 144
Cleco Marketing & Trading LLC 1,793
Cleco ConnecXus LLC 80
------
Total $7,781
======
The Company has the following affiliate receivable and payable balances
associated with the service agreements between the Company and its affiliates:
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 2000
---------------------------------
ACCOUNTS ACCOUNTS
RECEIVABLE PAYABLE
--------------- ---------------
<S> <C> <C>
(IN THOUSANDS)
Cleco $ 424
Utility Construction & Technology Solutions LLC 132
Cleco Evangeline LLC 62
Cleco Generation Services LLC $3,003
Cleco Midstream Resources LLC 509
Cleco Marketing & Trading LLC 866
Cleco Energy LLC 1,164
Cleco Support Group LLC 5,181
Cle Resources Inc. 365
Cleco ConnecXus 15
------ ------
Total $1,864 $9,857
====== ======
</TABLE>
During the period January 1, 2000 to September 30, 2000, the Company paid
cash dividends to Cleco of approximately $39.5 million.
F-42
