<PAGE>

                                                    EXHIBIT 13

                                              SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
                                                        FOR THE YEARS ENDED DECEMBER 31,                
                                         ---------------------------------------------------------------
                                             1998         1997      1996 (1,2)   1995 (1,2)   1994 (1,2)
                                             ----         ----      ----         ----         ----      
                                                 (In thousands, except per share amounts, ratios 
                                                             and operating statistics)
<S>                                      <C>           <C>          <C>         <C>          <C>        
FINANCIAL DATA
Statements of Income Data
   Operating revenues..................  $  515,175    $   456,245  $  437,121   $  396,227   $  381,482
   Net income..........................      53,801         52,519      52,135       48,703       45,043
   Net income applicable to common     
     stock.............................      51,664         50,402      50,061       46,651       43,017
   Basic earnings per common share.....        2.30           2.24        2.23         2.08         1.92
   Diluted earnings per common share...        2.24           2.18        2.16         2.02         1.86
   Cash dividends paid per common share        1.61           1.57        1.53         1.49         1.45
Ratio of earnings to fixed charges.....        3.80x          3.74x       3.70x        3.49x        3.35x
Ratio of earnings to combined fixed
  charges and preferred stock dividends        3.46x          3.41x       3.36x        3.17x        3.02x
Balance Sheet Data  (at end of period)                                            
  Total assets.........................  $1,429,000    $ 1,361,044  $1,321,771   $1,226,034   $1,178,191
  Long-term obligations and redeemable
    preferred stock....................  $  348,722    $   372,017  $  347,231   $  367,432   $  343,509
OPERATING STATISTICS
Electric sales -- regular system
  customers (million KWH)
  Residential..........................       3,230          2,838       2,723        2,763        2,532
  Commercial...........................       1,529          1,393       1,338        1,265        1,180
  Industrial...........................       2,518          2,467       2,369        2,227        2,030
  Other retail.........................         555            533         526          502          487
  Sales for resale.....................         402            311         291          360          210
                                         ----------     ----------   ---------    ---------    ---------
  Total sales to regular customers.....       8,234          7,542       7,247        7,117        6,439
Short-term energy sales to other
  utilities............................          76            157         330           68          174
                                         ----------     ----------   ---------    ---------    ---------
  Total electric sales.................       8,310          7,699       7,577        7,185        6,613
                                         ==========     ==========   =========    =========    =========
System peak (thousand kilowatts).......       1,627          1,560       1,500        1,473        1,310
Electric customers.....................     242,457        238,061     224,703      220,923      217,568
</TABLE>

(1)  Certain amounts for the period 1994-1996 have been reclassified to conform
     with the presentation shown in the current year's financial statements.
     These classifications had no effect on net income applicable to common
     stock or common shareholders' equity.

(2)  Earnings per average common share for the period 1994-1996 have been
     restated to reflect adoption of Statements of Financial Accounting
     Standards (SFAS) No. 128, "Earnings per Share."

                                       1
<PAGE>
                    MANAGEMENT'S DISCUSSION AND ANALYSIS OF   
                 RESULTS OF OPERATIONS AND FINANCIAL CONDITION

INDUSTRY DEVELOPMENTS/CUSTOMER CHOICE

         Forces driving increased competition in the electric utility 
industry involve complex economic, legislative and regulatory factors. These 
factors have resulted in the introduction of federal and state legislation 
and other regulatory initiatives that are likely to produce even greater 
competition at both the wholesale and retail levels in the future. The 
Louisiana Public Service Commission (LPSC) is investigating whether retail 
choice is in the best interest of Louisiana electric utility customers. The 
Company and a number of parties, including the other Louisiana electric 
utilities, certain power marketing companies and various associations 
representing industry and consumers, participated in electric industry 
restructuring testimony before the LPSC during 1997 and 1998. Also during 
1997, the Louisiana legislature deferred any action regarding restructuring 
of the electric utility industry within the State. We expect the debate 
relating to customer choice and other related issues to continue in 
legislative and regulatory bodies in 1999. At this time, we cannot predict 
whether any legislation or regulation will be enacted or adopted during 1999 
and, if enacted or adopted, what form such legislation or regulation would 
take.

         In general, Louisiana enjoys relatively low rates for electricity. 
Industry restructuring presents the possibility that rates could move closer 
to the national average, meaning possible higher prices for Louisiana's small 
consumers. With this in mind, we prepared a plan that would stabilize the 
rates of small consumers and allow retail choice no later than the year 2000, 
primarily for larger commercial and industrial class customers. In the 
meantime, we recognize the need to resolve issues to create a level playing 
field for all energy suppliers. The increasingly competitive environment 
presents the opportunity to supply electricity to new customers, as well as 
the risk of losing existing customers. We believe the Company is a reliable, 
low-cost provider of electricity and as such, is currently positioned to 
compete effectively in a restructured electric marketplace.

RESULTS OF OPERATIONS

EARNINGS

         Our 1998 earnings (net income applicable to common stock) totaled 
$51.7 million, or $2.30 per share, an increase of $1.3 million, or $0.06 per 
share compared to 1997. Earnings increased because we sold more 
kilowatt-hours to our regular customers, adding an additional $17.5 million 
in base revenues and because of efforts by our power marketing operations. 
Earnings were adversely affected by expected increases in such nonfuel 
operating expenses as depreciation and ad valorem taxes, as well as a $2 
million annual base rate reduction ordered by the LPSC, and a $4.8 million 
reserve for customer rate refunds.

         Our 1997 earnings increased $0.3 million, or $0.01 per share 
compared to 1996. The growth in earnings were primarily due to increased 
sales of electricity to our customers compared to 1996. Earnings were 
adversely affected by a $3 million annual rate reduction ordered by the LPSC. 
Earnings in 1996 increased $3.4 million, or $0.15 per share compared to 1995. 
Results for 1996 were affected by increased sales of electricity to 
commercial and industrial customers, offset by an increase in nonfuel 
operating expenses.

         Earnings for past years are not necessarily indicative of future 
earnings and results. Future earnings will be affected by weather conditions, 
our business development programs, the overall economy of the Company's 
service area, legislative and other regulatory changes and increased 
competition.

REVENUES

         Retail rates for residential, commercial and industrial customers 
and other retail sales (about 90% of revenues) are regulated by the LPSC. 
Rates for transmission and wholesale power sales are regulated by the Federal 
Energy Regulatory Commission (FERC). Retail rates consist of a base rate and 
a fuel rate. Base rates are designed to allow us to recover the cost of 
providing service and a return (profit) on utility assets. Fuel rates 
fluctuate, allowing us to recover, with no profit, the majority of changing 
costs of purchased power and fuel used to generate 

                                       2
<PAGE>

electricity. The following chart shows the amounts and changes in base 
revenues and fuel cost recovery revenues for 1998, 1997 and 1996.
<TABLE>
<CAPTION>
                                                       1998                     1997                  1996        
                                               ---------------------   --------------------   --------------------
                                                   IN       PERCENT        In      Percent        In     Percent  
                                               THOUSANDS    CHANGE      Thousands  Change     Thousands  Change   
                                               ---------    ------      ---------  -------    ---------  -------  
<S>                                            <C>          <C>         <C>        <C>        <C>        <C>      
Base (nonfuel)............................      $324,788     16.7%      $278,412      3.9%     $268,006      1.9% 
Fuel cost recovery........................       190,387      7.1%       177,833      5.2%      169,115     26.9% 
                                                --------    -----       --------    -----      --------    -----  
          Total revenues..................      $515,175     12.9%      $456,245      4.4%     $437,121     10.3% 
                                                ========    =====       ========    =====      ========    =====  
</TABLE>

         Base revenues were reduced $3 million annually beginning November 1, 
1996, and were reduced by an additional $2 million annually beginning January 
1, 1998, by the settlement of an earnings review conducted by the LPSC. Base 
revenues in 1998 were reduced further by a $4.8 million provision for 
customer rate refunds based on the same LPSC settlement. For more information 
on the results of the LPSC earnings review, see "Financial Condition - Retail 
Rates" below. About half of the $58.9 million, or 12.9% increase in 1998 
operating revenues, was due to an increase in base revenues from a 9.2% 
growth in kilowatt-hour sales to regular customers.

         Fuel cost recovery revenues collected in 1998 increased $12.6 
million due to the increased demand for power and the lack of available 
low-cost power on the wholesale market combined with the lack of available 
transmission capacity to transport energy to our electric system. The lack of 
available purchased power increased the need for additional generation by our 
natural gas units at a higher cost. Net income is not materially affected by 
changes in the cost of fuel and purchased power because most of these cost 
fluctuations are currently passed on to customers through fuel cost 
adjustments clauses. For information on changes in the fuel adjustment 
clause, see "Financial Condition -- Retail Rates" below.

         Total operating revenues for 1997 were 4.4% higher compared to 1996. 
This increase was primarily due to an increase in base revenues from a 4.1% 
growth in kilowatt-hour sales to regular customers and a corresponding 
increase in fuel cost recovery revenues.

SALES

         Weather influences the demand for electricity, especially among 
residential customers. A hot summer or a cold winter will increase 
residential customer demand for electricity. Cooler summers and warmer 
winters will reduce customer demand. 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 chart compares the kilowatt-hour sales by customer 
class for 1998, 1997 and 1996.
<TABLE>
<CAPTION>
                                                  1998                   1997                    1996
                                          ---------------------- ----------------------  ----------------------
                                            MILLION   PERCENT     Million    Percent      Million    Percent
                                             kwh      CHANGE        kwh       Change        kwh       Change
                                             ---      ------        ---       ------        ---       ------
<S>                                         <C>       <C>         <C>        <C>          <C>        <C>    
Regular customers
  Residential........................        3,230      13.8%       2,838     4.2%        2,723     (1.4)%
  Commercial.........................        1,529       9.8%       1,393     4.1%        1,338       5.8%
  Industrial.........................        2,518       2.1%       2,467     4.1%        2,369       6.4%
  Other retail.......................          555       4.1%         533     1.3%          526       4.8%
  Sales for resale...................          402      29.3%         311     6.9%          291    (19.2)%
                                           -------    ------      -------  ------       -------   -------
Total sales to regular customers.....        8,234       9.2%       7,542     4.1%        7,247       1.8%
Short-term sales to other utilities..           76    (51.6)%         157  (52.4)%          330     385.3%
                                           -------    ------      -------  ------       -------   -------
    Total electric sales.............        8,310       7.9%       7,699     1.6%        7,577       5.5%
                                           =======    ======      =======  ======       =======   =======
</TABLE>
                                       3
<PAGE>

         The increase in sales to residential customers during 1998 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 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 we serve.

         During 1997, consumption by commercial and industrial customers was 
higher than in 1996 due to customer growth and increased consumption by our 
largest industrial customer. In addition, the fall weather in 1997 was warmer 
than the fall weather in 1996, resulting in a 4.2% increase in residential 
sales.

         During the last five years, electric sales growth to regular 
customers averaged 5.8% and, based on current information, is expected to 
range from 3% to 4% per year during the next five years. The levels of future 
sales will depend upon weather conditions, customer conservation efforts, our 
retail marketing and business development programs, and the overall economy 
of the service area. 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.

         In February 1995, we agreed to purchase the assets of Teche for a 
price, including the assumption or other discharge of Teche's liabilities, of 
about $22.4 million. The members of Teche overwhelmingly approved the sale at 
their annual meeting in March 1995. One of the conditions necessary to the 
closing of the Teche acquisition was an interim power purchase agreement with 
Cajun Electric Power Cooperative, Inc. (Cajun), Teche's former wholesale 
power supplier. Cajun has been involved in bankruptcy proceedings since 1995. 
An interim agreement, acceptable to Cajun's bankruptcy trustee and the Rural 
Utilities Service, was reached in September 1997. We consummated the purchase 
on September 30, 1997.

FUEL AND PURCHASED POWER

         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 table shows the amount and changes in fuel 
and purchased power expenses for 1998, 1997 and 1996.
<TABLE>
<CAPTION>
                                                1998                       1997                      1996
                                       ------------------------   -----------------------   -----------------------
                                            IN        PERCENT         In        Percent         In        Percent
                                        THOUSANDS     CHANGE       Thousands    Change       Thousands    Change 
                                        ---------     ------       ---------    ------       ---------    ------ 
<S>                                     <C>           <C>          <C>          <C>          <C>          <C>    
Fuel used for electric generation....    $142,737       12.9%      $136,009       17.6%      $115,642        6.8%
Power purchased......................      53,011       18.9%        44,590     (19.8)%        55,609      103.2%
                                         --------       -----      --------     -------      --------      ------
          Total fuel expenses........    $195,748       11.1%      $180,599        5.4%      $171,251       26.2%
                                         ========       =====      ========     =======      ========      ======
</TABLE>

         Fuel and purchased power costs increased $14.1 million in 1998. Fuel 
costs used for electric generation increased over 1997 primarily as a result 
of the lack of available low-cost power on the wholesale market combined with 
the lack of available transmission capacity to transport energy to our 
electric system and increased kwh sales overall. Consequently, 1998 purchased 
power costs and generation fuel costs increased compared to 1997.

         Fuel and purchased power costs increased $9.3 million in 1997. Fuel 
costs used for electric generation increased over 1996 primarily as a result 
of the lack of available low-cost power on the wholesale market and the lack 
of available transmission capacity to transport energy to our electric 
system, which increased the need for additional generation output by our 

                                       4

<PAGE>

natural gas units at a higher fuel cost. This caused an increase in 
generating fuel costs and a decrease in 1997 purchased power costs compared 
to 1996.

         Coal and lignite are obtained under long-term contracts. Natural gas 
is purchased under short-term contracts on the spot market when prices are 
advantageous. Power is purchased from other utilities when the purchase price 
is less than our cost of generation and when transmission capacity is 
available to transport the energy to our system. During 1998, 24% of our 
energy requirements were met with purchased power, the same as in 1997.

         The Company is constrained as to the amount of purchased power it 
can bring into its system. Because of the location of the system, the Company 
must rely on one main supplier of electric transmission to bring purchased 
power into the Company's system. In future years, the Company may not have 
enough electric power to meet native load demand. Management plans to address 
the issue by repowering Coughlin Power Station (CPS) through a wholly-owned 
affiliate. See Notes to the Consolidated Financial Statements, Note M, 
"Repowering Project" for a further explanation of the repowering of CPS.

         We and the joint-owner of one of our electric generating units 
jointly filed suit in 1997 against a joint venture and its partners who mine 
lignite for the generating unit. The joint venture has filed counterclaims. 
The counterclaims caused us and the joint-owner to file another suit against 
the joint venture's parent company. Management believes the counterclaims, if 
successful, would not have a significant adverse effect on our financial 
position or results of operations. Normal day-to-day operations continue at 
the mining facility and the jointly-owned electric generating unit.

         One of the Company's wholly-owned subsidiaries owns and operates 
natural gas pipelines at three of our power stations where natural gas is 
used as a primary fuel. These pipelines increase our access to natural gas 
markets and lower-cost gas supplies. The Company has a base supply contract 
for approximately one-third of our natural gas requirements. These natural 
gas supply arrangements and access to the gas markets afforded by the 
pipelines are helping to maintain the competitiveness of our generating units.

         The coal for one of our jointly-owned electric generating units is 
transported under a long-term transportation contract with a railroad. The 
railroad was experiencing operating problems, which began in 1997 and 
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. In January and February of 1999, the 
deliveries of coal have increased, indicating some recovery from the 
railroad's operating problems. Coal inventory at the unit currently is above 
its desired minimum level. Based on the railroad's anticipated delivery 
schedule of future coal shipments, management does not expect that production 
at the unit will need to be curtailed due to insufficient fuel supply.

NONFUEL OPERATING EXPENSES AND INCOME TAXES

         Changes in nonfuel operating expenses (excluding restructuring 
charges) for 1998, 1997 and 1996 were as follows:
<TABLE>
<CAPTION>
                                           1998                        1997                        1996
                                 --------------------------  -------------------------   -------------------------
                                       IN         PERCENT          In        Percent        In          Percent 
                                   THOUSANDS      CHANGE       Thousands     Change      Thousands       Change  
                                   ---------      ------       ---------     ------      ---------       ------  
<S>                                <C>            <C>          <C>           <C>         <C>             <C>     
Other operation..............       $33,770        52.3%       $   (152)       (0.2)%     $  (2,994)       (4.4)%
Maintenance..................         6,999        30.0%           (203)       (0.9)%           873          3.9%
Depreciation.................         2,479         5.4%          2,449          5.6%         2,277          5.5%
Other taxes..................         1,998         6.0%          3,827         12.9%           532          1.8%
Income taxes.................        (1,063)      (3.8)%          1,575          6.0%           925          3.7%
                                     -------      ------       --------        ------     ---------        ------

                                       5
<PAGE>

          Total..............       $44,183        22.7%       $  7,496          4.0%     $   1,613          0.9%
                                    =======       ======       ========        ======     =========        ======
</TABLE>

         Total 1998 nonfuel operating expenses, excluding 1997 restructuring 
charges, increased 22.7% over 1997. For more information concerning a $1.9 
million restructuring charge incurred in 1997, see "Restructuring Charge", 
below. The increase in other operation expense was mainly due to power 
purchased by the power trading operation for resale on the wholesale market. 
Maintenance expense increased due to several unanticipated generating unit 
repairs due to mechanical problems and increased right-of-way reclearing 
relating to transmission and distribution. Depreciation expense increased 
primarily due to a full year of depreciation on property additions associated 
with the acquisition of Teche's assets and planned additions to generation, 
transmission and distribution facilities.

         Total 1997 nonfuel operating expenses, excluding restructuring 
charges, increased 4.0% over 1996. For more information concerning the $1.9 
million restructuring charge incurred in 1997, see "Restructuring Charge" 
below. Depreciation expense increased primarily due to a full year of 
depreciation on property additions associated with the Energy Control Center, 
and planned additions to generation, transmission and distribution 
facilities. Taxes other than income taxes increased primarily due to the 
expiration, in 1997, of ten-year property tax exemption on the Dolet Hills 
Power Station. Taxes other than income taxes increased primarily due to our 
share of the increased property taxes on this generating station.

         A number of parishes (counties) 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.

RESTRUCTURING CHARGE

         During 1997, we reorganized our electric production staff. The 
primary objective of this reorganization was to create a centralized power 
production maintenance workforce. Other initiatives included improving power 
production operations and providing better service to customers. As a result, 
approximately 30 employee positions were eliminated resulting in a charge to 
earnings of $1,891,000 ($1,248,000 on an after-tax basis), consisting mainly 
of voluntary severance programs offered to eligible employees.

OTHER INCOME AND INTEREST EXPENSE

         "Other income (expenses), net" decreased $1.6 million in 1998 
compared to 1997, mainly due to start up costs relating to several 
nonregulated subsidiaries, primarily Cleco Evangeline LLC, which is in the 
process of repowering an existing generating station. In 1997, "other income 
(expenses), net" increased $0.9 million as a result of increased earnings 
from nonregulated activities. Interest expense for 1998 decreased $1.2 
million, as compared to 1997. This decrease was due to lower interest rates 
during 1998 as compared to 1997.

         Interest expense for 1997 increased $0.6 million, as compared to 
1996. This increase was due to higher average outstanding balances of 
commercial paper and medium-term notes during 1997 at interest rates similar 
to 1996, which was partially offset by a decrease in interest on first 
mortgage bonds because of the redemption in 1996 of $50 million Series Y 
first mortgage bonds.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

         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 1998 increased as a 
result of higher LPSC and FERC rate regulated construction expenditures. 
AFUDC for 1997 decreased as a result of lower average LPSC and FERC 
construction work-in-progress balances compared to 1996. AFUDC accounted for 
2.2% of earnings in 1998, compared to 0.9% in 1997 and 1.5% in 1996.

                                       6

<PAGE>

EARNINGS PER SHARE

         Earnings per average common share has been computed using the 
weighted average number of shares of common stock outstanding during the 
year. Earnings per average common share are reported for the years 1998 and 
1997 and restated for 1996 to reflect adoption of SFAS No. 128, "Earnings per 
Share."

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 the Company's credit rating.

         From 1990 through 1996, we participated in a program where up to $35 
million of our receivables were sold on an ongoing basis. The amount of 
receivables that could have been sold any time depended upon seasonal 
fluctuations in the amount of eligible receivables. In December 1996, sales 
of accounts receivable were reduced to zero and the program was terminated in 
early 1997. To replace this short-term liquidity program, our committed bank 
borrowing capacity was increased by $25 million in 1997.

         The Company has an effective shelf registration statement and all 
regulatory approvals necessary to issue up to $140 million of medium-term 
notes.

         At December 31, 1998 and 1997, there was $68.2 million and $34.2 
million, respectively, of short-term debt outstanding in the form of 
commercial paper borrowings. Short-term debt increased as a result of 
increased commercial paper borrowings for interim expenditures related to a 
project to repower a generating station. The higher level of commercial paper 
outstanding relating to the generation station repowering is temporary, 
pending finalization of permanent financing for the repowering project. 
Currently, we have a $100 million revolving credit facility, which is 
scheduled to continue to June 2000 and an $80 million facility which expires 
in August 1999. The $80 million facility may be extended for another year 
prior to its scheduled expiration date, provided approvals are received from 
participating banks. Both credit facilities support the issuance of 
commercial paper. Uncommitted lines of credit with banks totaling $15 million 
are available to meet short-term working capital needs. Additionally, at 
December 31, 1998, one of our nonregulated consolidated subsidiaries held 
$13.2 million of cash and marketable securities, which are committed to 
supporting activities of affiliates.

CASH GENERATION AND CASH REQUIREMENTS

Cash Flows
----------

         During 1998, cash flows from our operating activities generated 
$113.4 million as shown in the Consolidated Statements of Cash Flows. 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 is related to additions to property, plant, and 
equipment, including the repowering of one of the Company's older power 
stations, CPS, by a wholly-owned affiliate, and changes in utility and 
nonutility investments. Net cash used in financing activities resulted 
principally from the payment of dividends to shareholders and the changes in 
short-term and long-term financing activities.

Construction Overview
---------------------

         The Company has divided its construction into two categories: LPSC 
jurisdictional and LPSC non-jurisdictional. LPSC jurisdictional construction 
consists of assets that may be added to the Company's rate base and the cost, 
if considered prudent by the LPSC, may be passed on to jurisdictional 
customers. Those assets earn a rate of return restricted by the LPSC and are 
subject to the rate agreement described under "Retail Rates". 

                                       7

<PAGE>

Such construction consists of additions to the distribution system, 
improvements to the transmission system and improvements at the generation 
stations other than CPS. LPSC non-jurisdictional construction consists of 
assets whose rate of return is largely determined by the market, not the 
LPSC. Examples of this type of construction are the repowering of CPS and 
additions to gas pipeline transmission systems.

LPSC Jusidictional Construction
-------------------------------

         In recent years, the LPSC jurisdictional construction program has 
consisted primarily of enhancements to the transmission system, distribution 
system, and improvements at the generating stations. In 1997, we acquired the 
assets of Teche for $22.4 million. LPSC non-jusidictional construction 
expenditures, excluding AFUDC, totaled $53.9 million in 1998 and $52.9 
million in 1997, excluding the Teche assets.

         LPSC Jusidictional construction expenditures, excluding AFUDC, for 
1999 are estimated to be $58.8 million and for the five-year period ending 
2003 are expected to total $252.5 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 1998, 99.8% of LPSC jurisdictional construction requirements were 
funded internally, as compared to 100% in 1997 and 96% in 1996. In 1999, 
99.9% of construction requirements are expected to be funded internally. For 
the five-year period ending 2003, 99.8% of the construction requirements are 
expected to be funded internally.

LPSC Non-Jurisdictional Construction
------------------------------------

         In the past few years, LPSC non-jurisdictional construction has 
consisted of a series of natural gas interconnections between several gas 
transmission pipelines and our generation stations that use natural gas. In 
1998, the Company started the repowering project at CPS. Additions to 
property, plant and equipment for 1998 as shown on the Consolidated 
Statements of Cash Flows include $37.1 million cash outlay for the repowering 
of CPS. See Notes to the Consolidated Financial Statements, Note M, 
"Repowering Project" for a further explanation of the repowering of CPS. LPSC 
non-jurisdictional construction expenditures totaled $40.1 during 1998 and 
$1.2 in 1997.

         LPSC non-jurisdictional construction expenditures for 1999 are 
estimated to total $123.8 million and for the five year period ending 2003 
are expected to total $319.0 million. Most of the planned construction in the 
five year period will go toward the repowering of CPS. The rest of the 
expected construction budget is slated for possible joint ventures as well as 
possible natural gas pipeline construction and acquisition.

         In 1998, 14.3% of LPSC non-jurisdictional construction requirements 
were funded internally, as compared to 100% in 1997 and 100% in 1996. In 
1999, all construction requirements are expected to be funded externally. For 
the five year period ending 2003, 7.42% of the construction requirements are 
expected to be funded internally.

Other Cash Requirements
-----------------------

         Scheduled maturities of debt and preferred stock, including $20 
million of medium-term notes which are due in 2008, but putable in November 
1999, will total about $33.3 million for 1999 and approximately $135.5 
million for the five-year period ending 2003. In 1991, we began a common 
stock repurchase program, and as part of that program, up to $23 million of 
common stock may be repurchased in the future. No shares of common stock were 
repurchased in 1998 or 1997.

         The Company has committed to provide credit support up to $10 
million for working capital and electricity or natural gas commodity 
positions for Cleco Energy LLC. Additionally, commitments for asset 
development projects will be made as they occur up to $5 million per year for 
years 1998 through 2002. Amounts not advanced 

                                       8

<PAGE>

in any year are added to the amount available for the remaining years. $2.5 
million was advanced in 1998 for the acquisition of Sabine Texican Pipeline 
Company, Inc. See the Notes to the Consolidated Financial Statements, Note K, 
"Sabine Texican Pipeline Acquisition."

RETAIL RATES

         Retail rates regulated by the LPSC account for 90% of 1998 revenues. 
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 additions and increases in 
operating costs. If we were to request an increase in our rates and adequate 
rate relief were not granted on a timely basis, our ability to attract 
capital at reasonable costs to finance our operations and capital 
improvements might be impaired.

         The LPSC elected in 1993 to review the earnings of all electric, 
gas, water and telecommunications utilities regulated by it to determine 
whether the returns on equity of these companies may be higher than returns 
that might be awarded in the current economic environment. In 1996, the LPSC 
approved a settlement of our earnings review, providing our customers with 
lower electricity rates. The first base rate decrease, of $3 million 
annually, was 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 more years until 2004 under an agreement to 
transfer the existing assets of CPS from the Company's LPSC regulated rate 
base into Cleco Evangeline LLC which will then repower the generating plant. 
See Notes to the Consolidated Financial Statements, Note M, "Repowering 
Project".

         During the eight-year period, which began November 1, 1996, a rate 
stabilization plan is in place. This plan allows the Company to retain all 
earnings equating to a regulatory return on equity up to and including 12.25% 
on its regulated utility operations. Any earnings which result in a return on 
equity over 12.25%, up to and including 13%, will be shared equally between 
ourselves and our customers, which effectively allows us the opportunity to 
realize a regulatory rate of return of up to 12.625%. Any earnings above this 
level will be refunded fully to customers.

         During the eight-year period 1997-2004, our revenues and return on 
equity will be reviewed each year by the LPSC. If the Company is found to be 
achieving a regulatory return on equity in any given year which requires a 
refund to customers, the refund will be made in the form of billing credits 
during the months of July, August and September following the evaluation 
period. Based on the terms of the settlement with the LPSC, the Company has 
decreased 1998 revenues by $4.8 million for a provision for the rate refunds.

         During the eight-year rate stabilization period, we will have the 
right to apply for a rate increase if a significant event affecting our 
earnings would justify it, such as regulatory or economic changes, major 
storm damage or other unforeseen circumstances. During the period, we will 
also be able to propose for LPSC consideration any revenue-neutral rate 
design changes we determine appropriate, such as revenue redistribution among 
customer classes that may be warranted. During the period, the LPSC may amend 
or modify any of the settlement's terms should the LPSC determine changes are 
warranted by the public interest.

         In November 1997, the LPSC issued an order in a generic docket which 
promulgated new standards for the monthly Fuel Cost Adjustment (FCA) rate 
filings of electric companies under its jurisdiction. The order adopted new 
rules and procedures for the monthly FCA computation and changes in reporting 
of fuel and purchased power costs to be implemented after final LPSC 
approval. Although the order narrows the types of costs that can be included 
in the FCA, the changes are expected to have no effect upon our financial 
position or results of operations, as costs no longer allowable in the FCA 
will be allowable as an increase in base rates under the provisions of the 
order.

INFLATION AND FUEL COSTS

         We are a capital-intensive electric utility. As such, we are 
affected by inflation since depreciation, which is based on the historical 
cost of assets, will in all likelihood not fully reflect the cost of 
replacing assets. Although the 

                                       9

<PAGE>

cost of fuel used for electric generation is a major component of total 
costs, we are not currently materially exposed to the effects of market 
fluctuations in fuel prices since most fuel costs are currently recovered 
from customers through fuel adjustment clauses.

YEAR 2000 READINESS DISCLOSURE

         The year 2000 (Y2K) problem occurs because many systems, both 
hardware and software, were designed to accept only two digits instead of 
four digits for the year in a date field. Having two digits instead of four 
digits may cause the system to read "00" as 1900 instead of 2000. This may 
cause calculations that are date sensitive to arrive at an incorrect or 
impossible solution. This may affect items such as delivery dates, interest 
calculations, pension benefit calculations, and a variety of other 
date-dependent calculations.

         The Company is aware of the issues surrounding Y2K and the problems 
that may occur and has put into action a plan to address these issues. The 
Company is aware that the Y2K problem may affect both internal information 
technology (IT) and non-IT systems. IT systems consist of software programs 
such as the operating system, spreadsheets, accounting and other programs. 
Non-IT systems refer to embedded technology such as micro controllers found 
in computers and other hardware systems. The Company has divided the IT and 
non-IT systems into two categories; mission critical and non-mission 
critical. Mission critical systems are those that would affect the health and 
safety of the public by causing a disruption in supplying electricity. 
Non-mission critical systems are those that would not cause a disruption in 
supplying electricity, but may still have a material, negative impact on the 
liquidity and financial condition of the Company. The following tables show 
the initiatives, the completion percentage of the various stages and an 
estimated completion date for the mission critical systems:
<TABLE>
<CAPTION>
                                             MISSION CRITICAL SYSTEMS

                                                                                       ESTIMATED
                        PLANNING-                                                       DATE OF
INITIATIVES             ASSESSMENT     CORRECTION        TESTING       IMPLEMENT       COMPLETION
-----------             ----------     ----------        -------       ---------       ----------
<S>                     <C>            <C>               <C>           <C>             <C>
Distribution                 100%            100%           100%           100%            N/A
Generation                   100%             82%            82%            82%         June 1999
IT Services*                 100%             91%            52%            34%        Sept. 1999
Transmission                 100%            100%           100%            20%         June 1999
</TABLE>

*IT Services includes business applications and telecommunications.

The description of the stages are:
<TABLE>
<S>                        <C>
Planning Assessment:       Develop a project plan, compile a complete list of affected systems, and prepare a
                           detailed technical plan.

Correction:                Make the required changes identified in Planning-Assessment.

Testing:                   Test all changes made in the Correction stage to insure that systems will meet the
                           compliance criteria and the systems will be accepted by user management.

Implementation:            Integrate the changed systems into a production environment and begin use.  Monitor
                           subsequent changes to other systems to ensure overall system integrity.
</TABLE>

Management considers the Company's non-mission critical systems to be Y2K 
compliant.

         Internal systems are not the only ones that may have a material 
effect on the Company. Institutions external to the Company, such as vendors 
and customers, may also impact the Company's operations if their systems are 
not Y2K compliant. Vendors could impact the Company by their inability to 
deliver goods and services required by the Company to operate. Customers 
could impact the Company by their inability to operate, reducing the sale of 
power, or their inability to pay the Company for the power consumed. The 
Company has decided to 

                                       10

<PAGE>

address this issue by identifying major vendors and customers and sending 
surveys to discover their level of Y2K compliance. Major vendors are defined 
as those that provide critical goods or services to the Company, or those 
that provide critical components to the Company (such as fuel suppliers and 
financial institutions). Major customers are identified as those customers 
that are at the greatest risk of being impacted by the Y2K problem and are 
large consumers of power (mainly industrial and commercial customers). To 
date, the surveys to the major vendors have been sent out and the requested 
responses have been received. Efforts will continue in soliciting responses 
from others, with any required contingency plans being completed by the end 
of the third quarter. The surveys to major customers are in the process of 
being reviewed and their state of readiness is being monitored. The projected 
completion date of system surveys of external parties is expected to be 
December 1999.

         The Company's cost to address its Y2K problem is currently estimated 
at $1.4 million, with approximately $0.9 million expended so far. The 
remaining $0.5 million is expected to be spent before July, 1999. The 
expenses associated with Y2K are being funded through cash flows from 
operations. Only a nominal amount of the Y2K budget is being expended on 
hardware. Most of the budget is being expended in software. The Company's 
overall IT operating budget for the year ended December 31, 1998 is 
approximately $13.4 million, however, the bulk of the Y2K expenses were 
budgeted and expended by the various departments that were affected by Y2K 
issues.

         At this point in time, management has not engaged any firm, nor does 
it plan to engage any firm, to perform an independent verification and 
validation of the Company's Y2K readiness. However, the Company's independent 
auditing firm has been engaged to review the readiness process being 
followed. Their review was completed in February and a summary of their 
findings relative to the process is expected soon, but the firm will not 
issue an opinion on Y2K readiness.

         The Company has been reporting to the LPSC on a quarterly basis 
starting in 1998. Also, monthly reports are sent to the Southwest Power Pool 
(SPP), which summarizes their member's reports and forwards them to the North 
American Electric Reliability Council (NERC). The U.S. Department of Energy 
receives its reporting from the NERC. The Company is in full compliance with 
the NERC reporting requirements, is planning to participate in the two 
planned NERC system tests, and is conforming with the NERC contingency 
planning requirements for the electrical system.

         The risks of not addressing the Y2K problem include the failure to 
bill customers, collect payments, pay invoices, operate generation 
facilities, operate substations, and order and receive critical materials. 
Each of these risks, should they materialize, could have a material, negative 
impact on the operations, liquidity and financial condition of the Company. 
It is the opinion of management that the action plan outlined above will 
adequately address the Y2K risks facing the Company and reduce them to 
manageable levels so that Y2K issues will not materially impact the Company.

         A worst case scenario would be the entire SPP grid collapsing due to 
the lack of available power. Management believes the Company is capable of 
disconnecting from the SPP grid and restarting our power generation stations. 
However, other regional grids may also collapse, which in turn could cause a 
disruption in the supply of fuel or critical parts. During a possible 
disruption, the Company would have to rely on its inventory of fuel and 
critical parts. The Company keeps approximately 30-day supply of coal at the 
two coal-fired plants, which are considered the Company's base load plants. 
If deliveries of fuel were interrupted for more than 30 days or if certain 
critical parts should fail, the Company's ability to generate power would be 
severely curtailed.

         The Company has contingency plans for mission critical systems 
against normal operating hazards such as major storms or fires. These plans 
were designed to minimize the impact to customers by providing alternatives 
and solutions to possible adverse conditions. These plans are required by 
several oversight agencies, such as the LPSC and the NERC. The existing 
contingency plans were reviewed and evaluated by the Company's staff to find 
out if they adequately addressed possible failures due to Y2K noncompliance. 
Plan amendments have been proposed but not yet finalized. The amendments are 
expected to be finalized before December, 1999.

         At present, the Company does not have a contingency plan in place to 
specifically cover the non-mission critical Y2K issues. However, management 
is continually monitoring the progress of each initiative. In the third 

                                       11

<PAGE>

quarter of 1999, management will evaluate the reasonableness of the projected 
completion dates and at that time determine if a contingency plan is 
required. As of the date of this filing, management reasonably expects the 
completion of the initiatives in a timely manner; thus, a contingency plan is 
not believed to be required.

ENVIRONMENTAL MATTERS

         We are subject to federal, state and local laws and regulations 
governing the protection of the environment. Violations of these laws and 
regulations may result in substantial fines and penalties. We have obtained 
all material environmental permits necessary for our operations and believe 
we are in substantial compliance with these permits, as well as all 
applicable environmental laws and regulations. We anticipate that existing 
environmental rules will not affect operations significantly, but some 
capital improvements may have to be made in response to new environmental 
programs expected in the next few years.

         Implementation of Phase I of the Clean Air Act will not require us 
to reduce sulfur emissions at our solid-fuel generating units, which either 
burn low-sulfur coal or utilize pollution control equipment. Installation of 
continuous emission monitoring equipment on generating units was completed in 
1996 at a cost of approximately $3 million. Although Phase II of the 
legislation, effective in 2000, involves more stringent limits on emissions, 
these requirements should not significantly affect the operation of our 
generating units. However, some capital investment may be necessary in order 
to comply with Phase II requirements. Capital expenditures for environmental 
matters were $1.0 million in 1998 and are estimated to be $1.5 million for 
1999.

REGULATORY MATTERS

         In 1996, the FERC issued rules 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. 
Providing unbundled transmission services to firm-requirements customers may 
have significant financial consequences to the utility industry. Providing 
open access for non-firm sales may have significant effects on utility 
operations. Currently, we have three wholesale full-requirements customers 
representing about 0.9% of our total kilowatt-hour sales to regular customers.

         Federal and state regulators and legislators are studying potential 
effects of deregulating the vertically integrated utility systems and 
providing retail customers a choice of supplier. At this time, it is not 
possible to predict when, if, or to what extent, retail customers will be 
able to choose their electric service suppliers. The regulatory requirement 
to serve customers and industry standards for reliability of electric supply 
have resulted in the construction of facilities sufficient, when combined 
with power purchased off-system and transmitted to the Company, to meet peak 
load conditions with a margin for reserve. With customer choice, costs 
associated with utility assets specifically dedicated to, or used by, 
departing customers, such as the Company's generating plants and power 
purchase contracts, would have to be paid by the departing customers 
(stranded costs), absorbed by remaining and new customers or written off by 
the Company.

         The Company has recorded regulatory assets and liabilities, 
primarily for the effects of income taxes, as a result of past rate actions 
of our regulators, pursuant to SFAS No. 71, "Accounting for the Effects of 
Certain Types of Regulation" (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, pursuant to SFAS No. 101, "Regulated Enterprises -- Accounting for 
the Discontinuation of Application of FASB Statement No. 71" (SFAS 101). At 
December 31, 1998, the Company had recorded $14.2 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 pay 
for additional taxes when the Company 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, the 
Company believes that these regulatory assets are 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 these regulatory assets were determined not 
to be recoverable, the Company would be required to write off or write down 
these assets.

                                       12

<PAGE>

         SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets 
and for Long-Lived Assets to be Disposed Of" (SFAS 121), establishes 
accounting standards for determining if long-lived assets are impaired, and 
when and how losses, if any, should be recognized. The Company believes that 
the net cash flows that will result from the operation of its assets are 
sufficient to cover the carrying value of the assets.

         The Emerging Issues Task Force (EITF) assists the Financial 
Accounting Standards Board (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 SFAS No. 71 and No 101." EITF 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 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.

FINANCIAL 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 and the commodity 
price of electricity traded on the Into Entergy exchange. Generally, the 
Company's market risk sensitive instruments and positions are characterized 
as "other than trading". The Company's exposure to market risk, as discussed 
below, represents an estimate of possible changes in the fair value or future 
earnings that would occur assuming possible future movements in the interest 
rates and the commodity price of electricity. Management's views on market 
risk are not necessarily indicative of actual results, nor do they represent 
the maximum possible gains or losses. The views do represent, within the 
parameters disclosed, what Management estimates may happen.

Interest
--------

         The Company has entered into various fixed and variable rate debt 
obligations. See the Notes to the Consolidated Financial Statements, Note D, 
"Debt" for details.

         As of December 31, 1998, the carrying value of the Company's 
long-term, fixed-rate debt was approximately $312 million, with a fair market 
value of approximately $336 million. Fair value was determined using quoted 
market prices. Each 0.05% change in the average interest rates applicable to 
such debt would result in a change of approximately $8 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 December 31, 1998, the carrying value of the Company's 
long-term, variable-rate debt was approximately $61.3, which approximates the 
fair market value. Each 0.5% change in the average interest rates applicable 
to such debt would result in a change of approximately $0.3 million in the 
Company's pre-tax earnings.

         As of December 31, 1998, the carrying value of the Company's 
short-term, variable-rate debt was approximately $68.4 million, which 
approximates the fair market value. Each 0.5% change in the average interest 
rates applicable to such debt would result in a change of approximately $0.3 
million in the Company's pre-tax earnings.

         The Company monitors its mix of fixed and variable rate debt 
obligations in light of changing market conditions and from time to time may 
alter that mix by, for example, refinancing balances outstanding under its 
variable rate commercial paper program with fixed rate debt.

         As of December 31, 1998, CLE Resources, Inc. (Resources), a 
wholly-owned subsidiary of the Company, held $13.2 million in cash 
equivalents in a money market account. Each 0.5% change in average interest 
rates 

                                       13

<PAGE>

applicable to such investments could result in a change of approximately $0.1 
million in the Company's pre-tax earnings.

Market Risk
-----------

         The Company uses derivative instruments to manage the commodity 
price risk associated with its power marketing operations (PMO) and its joint 
venture which markets natural gas.

         The Company's PMO enters into sales and purchases of electricity for 
delivery up to twelve months into the future. Because the market prices for 
electricity can be volatile, the PMO is exposed to risks arising from 
differences between the fixed prices in its commitments and fluctuating 
market prices. To mitigate its exposure, the PMO enters into electricity 
futures, swaps, option contracts and electricity forward agreements.

         The Company's joint venture, Cleco Energy LLC (Energy), enters into 
sales and purchases of natural gas for delivery up to five years into the 
future. Because the market prices for natural gas can be volatile, Energy is 
exposed to risks arising from differences between the fixed prices in its 
commitments and fluctuating market prices. To mitigate its exposure, Energy 
enters into natural gas futures, swaps, option contracts and natural gas 
forward agreements.

         Both trading operations utilize a value-at-risk model to assess the 
market risk of its derivative financial instruments. Value-at-risk represents 
the potential loss for an instrument from adverse changes in market factors 
for a specified period of time and confidence level. The value-at-risk was 
estimated using historical simulation calculated on a daily basis over a one 
week period with a 99.7% confidence level and a holding period of one week. 
Based on these assumptions, the total value-at-risk as of December 31, 1998, 
was not material to the Company.

NEW ACCOUNTING STANDARDS

         Periodically, the Financial Accounting Standards Board (FASB) issues 
Statements of Financial Accounting Standards (SFAS). These standards 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 
Derivatives Instruments and Hedging Activities", 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. The 
effect of adopting this Statement has not been determined.

         In October 1998, the FASB issued SFAS No. 134, "Accounting for 
Mortgage-Backed Securities Retained after the Securitization of Mortgage 
Loans Held for Sale by a Mortgage Banking Enterprise", effective for fiscal 
years beginning after December 15, 1998. This Statement is an amendment of 
FASB Statement No. 65 and required classifying certain securities as trading. 
Adoption of this Statement is not expected to affect our financial position 
or results of operations.

                                       14

<PAGE>

                DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

         This Annual Report to Shareholders includes "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All
statements other than statements of historical fact included in this Report,
including, without limitation, the statements under "Management's Discussion and
Analysis of Results of Operations and Financial Condition -- Industry
Developments/Customer Choice," "-- Results of Operations," "-- Financial
Condition -- Liquidity and Capital Resources," "-- Financial Condition --
Regulatory Matters" and Note N to the Consolidated Financial Statements contain
forward-looking statements. Located elsewhere in this Report are forward-looking
statements regarding sales growth, capital expenditures, the settlement of our
earnings review approved by the LPSC in October 1996, our shelf registration
statement, the effect of certain recent FERC regulations, future legislative and
regulatory changes affecting electric utilities, and other matters. Although we
believe the expectations reflected in such forward-looking statements are
reasonable, such forward-looking statements are based on numerous assumptions
(some of which may prove to be incorrect) and are subject to risks and
uncertainties which could cause the actual results to differ materially from our
expectations. Forward-looking statements have been and will be made in written
documents and oral presentations by management. Such statements are based on
management's beliefs as well as assumptions made by and information currently
available to management. When used in our documents or oral presentations, 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 such forward-looking statements, factors that
could cause our actual results to differ materially from those contemplated in
any forward-looking statements include, among others, the following:

         Factors affecting utility operations such as 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 environment, including effects 
     of: industry restructuring, transmission system operation or 
     administration, retail wheeling or cogeneration;

         Regulatory factors such as 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 FASB, the Securities and Exchange Commission, FERC, 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;

         Availability or cost of capital resulting from changes in the Company,
     interest rates, and securities ratings or market perceptions of the
     electric utility industry and energy-related industries;

         Employee workforce factors, including changes in key executives;

         Legal and regulatory delays and other obstacles associated with
     mergers, acquisitions, reorganizations or investments in joint ventures;

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

         Changes in federal, state or local legislature requirements, such as
     changes in tax laws or rates or environmental law and regulations.

         The Company undertakes 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.

                                            15
<PAGE>

                                                  CLECO CORPORATION

                                           CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                                             For the Years Ended December 31,
                                                                        ----------------------------------------
                                                                          1998            1997            1996
                                                                          ----            ----            ----
                                                                                     (In thousands,
                                                                          except share and per share amounts)
<S>                                                                     <C>             <C>             <C>
OPERATING REVENUES.............................................      $   515,175     $   456,245     $   437,121
Operating expenses                                                                   
  Fuel used for electric generation............................          142,737         136,009         115,642
  Power purchased..............................................           53,011          44,590          55,609
  Other operation..............................................           98,388          64,618          64,770
  Restructuring charges........................................                            1,891
  Maintenance..................................................           30,285          23,286          23,489
  Depreciation.................................................           48,369          45,890          43,441
  Taxes other than income taxes................................           35,420          33,422          29,595
  Federal and state income taxes...............................           26,666          27,729          26,154
                                                                     -----------     -----------     -----------
          Total operating expenses.............................          434,876         377,435         358,700
                                                                     -----------     -----------     -----------
OPERATING INCOME...............................................           80,299          78,810          78,421
Interest income................................................              372             427             256
Allowance for other funds used during construction.............              812             620           1,134
Other income (expenses), net...................................             (322)          1,248             333
                                                                     -----------     -----------     -----------
INCOME BEFORE INTEREST CHARGES.................................           81,161          81,105          80,144
                                                                     -----------     -----------     -----------
Interest charges
  Interest on debt and other...................................           27,016          27,549          27,492
  Allowance for borrowed funds used during construction........             (904)           (169)           (590)
  Amortization of debt discount, premium and expense, net......            1,248           1,206           1,107
                                                                     -----------     -----------     -----------
          Total interest charges...............................           27,360          28,586          28,009
                                                                     -----------     -----------     -----------
NET INCOME.....................................................           53,801          52,519          52,135
Preferred dividend requirements, net...........................            2,137           2,117           2,074
                                                                     -----------     -----------     -----------
NET INCOME APPLICABLE TO COMMON STOCK..........................      $    51,664     $    50,402     $    50,061
                                                                     ===========     ===========     ===========
AVERAGE SHARES OF COMMON STOCK OUTSTANDING
 Basic.........................................................       22,480,163      22,459,770      22,442,683
                                                                     ===========     ===========     ===========
 Diluted.......................................................       23,867,458      23,864,031      23,857,967
                                                                     ===========     ===========     ===========
EARNINGS PER AVERAGE SHARE
 Basic.........................................................            $2.30           $2.24           $2.23
                                                                     ===========     ==========      ===========
 Diluted.......................................................            $2.24           $2.18           $2.16
                                                                     ===========     ==========      ===========
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK..................            $1.61           $1.57           $1.53
                                                                     ===========     ==========      ===========

     The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>

                                                16

<PAGE>



                                                   CLECO CORPORATION

                                              CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                                          At December 31,
                                                                                      1998               1997
                                                                                  --------------   ---------------
                                                                                          (In thousands)
<S>                                                                               <C>              <C>
ASSETS                                                                             
Utility plant and other property, plant and equipment
  Property, plant and equipment.............................................      $1,565,028       $1,506,949
  Accumulated depreciation..................................................        (551,705)        (518,664)
                                                                                  ----------       ----------
  Net property, plant and equipment.........................................       1,013,323          988,285
  Construction work-in-progress.............................................          76,475           37,277
                                                                                  ----------       ----------
        Total utility plant, net............................................       1,089,798        1,025,562
                                                                                  ----------       ----------
Investments and other assets................................................           3,500            3,479
                                                                                  ----------       ----------
Current assets
  Cash and cash equivalents.................................................          19,457           18,015
  Accounts receivable, net
    Customer accounts receivable (less allowance for doubtful accounts of          
    $812 in 1998 and $684 in 1997)..........................................          27,436           28,822
      Other accounts receivable.............................................          22,218           18,601
  Notes receivable..........................................................             930              930
  Unbilled revenues.........................................................           9,712           11,090
  Fuel inventory, at average cost...........................................           9,725            8,648
  Material and supplies inventory, at average cost..........................          12,674           14,413
  Other current assets......................................................           1,738            1,894
                                                                                  ----------       ----------
  Total current assets......................................................         103,890          102,413
                                                                                  ----------       ----------
Prepayments.................................................................           8,293            8,331
                                                                                  ----------       ----------
Regulatory assets-- deferred taxes..........................................          95,199          115,285
                                                                                  ----------       ----------
Other deferred charges......................................................          30,975           29,418
                                                                                  ----------       ----------
Accumulated deferred federal and state income taxes.........................          97,345           76,556
                                                                                  ----------       ----------
        TOTAL ASSETS........................................................      $1,429,000       $1,361,044
                                                                                  ==========       ==========

CAPITALIZATION AND LIABILITIES
Common shareholders' equity
  Common stock, $2 par value, authorized 50,000,000 shares, issued              
  22,767,754 and 22,762,754 shares at December 31,1998 and 1997, respectively     $   45,535       $   45,525
  Premium on capital stock..................................................         113,871          113,763
  Retained earnings.........................................................         271,019          255,549
  Treasury stock, at cost, 281,930 and 299,842 shares at December 31, 1998 
    and 1997, respectively..................................................          (5,734)          (6,086)
                                                                                  ----------       ----------

        Total common shareholders' equity...................................         424,691          408,751
                                                                                  ----------       ----------
Preferred stock
  Not subject to mandatory redemption.......................................          29,718           30,102
  Subject to mandatory redemption...........................................           5,680            6,120
Deferred compensation related to preferred stock held by  ESOP..............         (16,923)         (18,766)
Long-term debt, net ........................................................         343,042          365,897
                                                                                  ----------       ----------
        Total capitalization................................................         786,208          792,104
                                                                                  ----------       ----------
Current liabilities                                                                
  Short-term debt ..........................................................          68,416           34,219
  Long-term debt due within one year .......................................          33,330           15,000
  Accounts payable..........................................................          61,786           53,365
  Customer deposits.........................................................          20,120           20,172
  Taxes accrued ............................................................          11,942           12,211
  Interest accrued..........................................................           7,340            7,681
  Accumulated deferred fuel.................................................           4,613            2,965
  Other current liabilities.................................................           3,868            5,102
                                                                                  ----------       ----------
        Total current liabilities...........................................         211,415          150,715
                                                                                  ----------       ----------
Deferred credits
  Accumulated deferred federal and state income taxes ......................         286,619          296,123
  Accumulated deferred investment tax credits ..............................          27,784           29,574
  Regulatory liabilities-- deferred taxes ..................................          81,074           62,468
  Other deferred credits....................................................          35,900           30,060
                                                                                  ----------       ----------
        Total deferred credits..............................................         431,377          418,225
                                                                                  ----------       ----------

        TOTAL CAPITALIZATION AND LIABILITIES................................      $1,429,000       $1,361,044
                                                                                  ==========       ==========

     The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>


                                                  17
<PAGE>


                                                   CLECO CORPORATION

                                         CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
                                                                              For the Years Ended December 31,
                                                                              --------------------------------
                                                                                1998       1997         1996
                                                                              --------    -------      -------
                                                                                        (In thousands)
<S>                                                                           <C>        <C>          <C>
OPERATING ACTIVITIES
  Net income..............................................................    $ 53,801   $ 52,519     $ 52,135
  Adjustments to reconcile net income to net cash provided
    by operating activities
      Depreciation and amortization.......................................      50,852     47,719       44,548
      Allowance for funds used during construction........................      (1,716)      (789)      (1,724)
      Amortization of investment tax credits..............................      (1,790)    (1,790)      (1,809)
      Deferred income taxes...............................................       8,703      2,908        3,818
      Deferred fuel costs.................................................       1,648        797       (1,483)
      Restructuring charge................................................                  1,285     
      Gain (loss) on disposition of land sales, net.......................                   (224)         (20)
      Changes in assets and liabilities
        Accounts receivable, net..........................................      (2,231)    (4,441)     (26,837)
        Unbilled revenues.................................................       1,378        103       (8,095)
        Fuel, material and supplies inventories...........................         662      3,334       (1,877)
        Accounts payable..................................................       4,421      2,058       (1,065)
        Customer deposits.................................................         (52)       411           36
        Taxes accrued.....................................................        (269)     6,405        3,303
        Interest accrued..................................................        (341)       160       (1,388)
      Other, net..........................................................      (1,682)     7,321        1,251
                                                                              --------   --------     --------
        Net cash provided by operating activities.........................     113,384    117,776       60,793
                                                                              --------   --------     --------
INVESTING ACTIVITIES
  Additions to property, plant and equipment..............................     (94,030)   (77,525)     (64,425)
  Allowance for funds used during construction............................       1,716        789        1,724
  Sale of utility plant...................................................         408        417          482
  Purchase of investments.................................................        (480)      (222)        (420)
  Sale of investments.....................................................                      1          807
                                                                              --------   --------     --------
        Net cash used in investing activities.............................     (92,386)   (76,540)     (61,832)
                                                                              --------   --------     --------
FINANCING ACTIVITIES
  Issuance of common stock................................................         100         66          288
  Repurchase of common stock..............................................                    (16)         (16)
  Redemption of preferred stock...........................................        (522)      (252)        (238)
  Issuance of long-term debt..............................................                 40,000       45,000
  Retirement of long-term debt............................................     (30,000)   (15,000)     (50,000)
  Increase (decrease) in short-term debt, net.............................      49,197    (30,942)      42,099
  Dividends paid on common and preferred stock, net.......................     (38,331)   (37,384)     (36,408)
                                                                              --------   --------     --------
        Net cash provided by (used in) financing activities...............     (19,556)   (43,528)         725
                                                                              --------   --------     --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS......................       1,442     (2,292)        (314)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............................      18,015     20,307       20,621
                                                                              --------   --------     --------
CASH AND CASH EQUIVALENTS AT END OF YEAR..................................    $ 19,457   $ 18,015     $ 20,307
                                                                              ========   ========     ========
Supplementary cash flow information
  Interest paid (net of amount capitalized)...............................    $ 28,118   $ 28,770     $ 29,881
                                                                              ========   ========     ========
  Income taxes paid.......................................................    $ 20,140   $ 23,752     $ 20,351
                                                                              ========   ========     ========

     The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>

                                                   18
<PAGE>



                                                   CLECO CORPORATION

                                         CONSOLIDATED STATEMENTS OF CHANGES IN
                                              COMMON SHAREHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                   For the Years Ended December 31, 1996, 1997 and 1998
                                        ----------------------------------------------------------------------------
                                                                    Premium on
                                              Common Stock            Capital     Retained           Treasury Stock
                                          Shares       Amount         Stock       Earnings         Shares       Cost
                                        ----------     ------         -----       --------         ------       ----
                                        (In thousands, except share and per share amounts)
<S>                                     <C>            <C>           <C>          <C>             <C>          <C>
BALANCE, JANUARY 1, 1996..........      22,745,014     $45,490       $113,444    $224,688         318,446      $6,459
Redemption of preferred stock.....                                         31
Incentive stock options exercised.          15,050          30            220
Issuance of treasury stock........                                          7                     (11,484)       (233)
Incentive shares forfeited........                                                                    615          16
Dividend requirements, preferred
   stock, net.....................                                                 (2,073)
Cash dividends paid, common stock,
  $1.53 per share.................                                                (34,336)
Net income........................                                                 52,135                  
                                        ----------     -------       --------    --------         -------      ------
BALANCE, DECEMBER 31, 1996........      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                     (19,755)
Issuance of treasury stock                                                 24                                    (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
                                        ==========     =======       ========    ========         =======      ======

           The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>

                                                        19
<PAGE>

                               CLECO CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRESENTATION AND REGULATION

         Cleco Corporation (the Company) provides electric service to a
diversified base of residential, commercial and industrial customers in 23
parishes (counties) of Louisiana. The Company maintains its accounts in
accordance with the Uniform System of Accounts prescribed for electric utilities
by the Federal Energy Regulatory Commission (FERC), as adopted by the Louisiana
Public Service Commission (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 consolidated financial statements include the accounts of the
Company and all subsidiaries which the Company owns directly, or indirectly,
through a majority interest. Intercompany balances are eliminated in
consolidation.

         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 1996 consolidated
financial statements to conform to the presentation used in the 1998 and 1997
consolidated financial statements. These reclassifications had no effect on net
income applicable to common stock or total common shareholders' equity.

UTILITY PLANT, OTHER PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION

         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. Other property, plant and equipment is stated the same as utility
plant except there is no estimated cost of funds used during construction, but
instead has interest capitalized during the construction period.

         The provision for depreciation is computed using the straight-line
method at rates which 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 3.32% for 1998, 3.27% for 1997
and 3.21% for 1996.

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

                                     20
<PAGE>

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.

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 which 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 debt are amortized over the remaining life of
the original issue.

REVENUES AND FUEL COSTS

         Revenues from sales of electricity are recognized based upon the amount
of energy delivered. The cost of fuel and purchased power 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.

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 1998 was 13.49%
on a pretax basis (8.30% net of tax), 13.97% on a pre-tax basis (8.59% net of
tax), for 1997, and 13.33% on a pre-tax basis (8.20% net of tax) for 1996.

DERIVATIVES

         From time to time the Company or its subsidiaries may limit or expand
their exposures to interest rate risk or electricity or generator boiler-fuel
market price risk by using hedging transactions. In each case the transactions
reflect underlying indebtedness or commodity requirements. No hedging
transactions are entered into for speculative purposes. The Company did not
engage in any interest rate hedges in 1998 and had no significant amounts of
natural gas futures transactions outstanding at December 31, 1998 and 1997.

RECENT ACCOUNTING STANDARDS

         Statements of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivatives Instruments and Hedging Activities", is required to
be implemented during the Company's fiscal year December 31, 2000. SFAS No. 134,
"Accounting for Mortgage-Backed Securities Retained after the Securitization of
Mortgage Loans Held for Sale by a Mortgage Banking Enterprise", are required to
be implemented during the Company's fiscal year ending December 31, 1999.

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 1998, 1997 and restated for 1996 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.

                                        21
<PAGE>



<TABLE>
                                                          For the year ended December 31,
                                                      (In thousands, except per share amounts)
                                    1998                                 1997                                1996
                    ------------------------------------ -----------------------------------  -----------------------------------
                       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            $53,801                              $52,519                             $52,135
Less: preferred
 dividend
 requirements, net     (2,137)                              (2,117)                             (2,074)
                       -------                             -------                             -------

BASIC EPS

Income available                                                                          
 for common                                                                                                                  
 shareholders         $51,664      22,480       $2.30      $50,402      22,460       $2.24     $50,061        22,443     $2.23
                                                =====                                =====                               =====

EFFECT OF DILUTIVE                 
  SECURITIES
Stock option                            7                                    7                                    10
grants
Convertible ESOP
  preferred stock       1,707       1,380                    1,646       1,397                   1,549         1,405
                        -----       -----                  -------      ------                 -------         -----

DILUTED EPS

Income available
to common
shareholders +                                                                                                   
assumed
conversions           $53,371      23,867       $2.24      $52,048      23,864       $2.18     $51,610         23,858    $2.16
                      =======      ======       =====      =======      ======       =====     =======         ======    =====
</TABLE>

NOTE B -- 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.

<TABLE>
<CAPTION>
                                              At December 31, 1998
                                         -------------------------------
                                         Rodemacher          Dolet Hills
                                           Unit #2             Unit #1
                                         ----------          -----------
                                          (Dollar amounts in thousands)
<S>                                        <C>                 <C>
Percentage of ownership ................        30%                  50%
Utility plant in service ...............   $85,301             $273,420
Accumulated depreciation ...............   $41,798             $103,895
Unit capability (thousand kilowatts) ...     523.0                650.0
Share of capability (thousand kilowatts)     156.9                325.0
</TABLE>

NOTE C -- FAIR VALUE OF FINANCIAL INSTRUMENTs

         The amounts reflected in the financial statements at December 31, 1998
and 1997 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 investments at December 31, 1998 and 1997 is estimated based
on quoted market prices for these or similar investments. 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 and 1997, 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).

                                      22
<PAGE>

<TABLE>
<CAPTION>
                                                    At December 31,
                                        -------------------------------------------
                                               1998                 1997
                                        --------------------  ---------------------
                                        CARRYING  ESTIMATED   Carrying   Estimated
                                         VALUE    FAIR VALUE    Value    Fair Value
                                        --------  ----------  --------   ----------
                                                      (In thousands)
<S>                                     <C>        <C>        <C>        <C>
Investments .........................   $  1,287   $  1,287   $    807   $    807
Long-term debt ......................   $376,698   $400,738   $381,260   $395,183
Preferred stock
  Not subject to mandatory redemption   $ 12,795   $ 28,567   $ 11,336   $ 24,248
  Subject to mandatory redemption ...   $  5,680   $  5,143   $  6,120   $  5,058
</TABLE>

NOTE D -- DEBT

         The Company has revolving credit facilities totaling $180 million. A
$100 million facility, which is scheduled to continue to June 15, 2000, and an
$80 million facility, which is scheduled to expire on August 28, 1999, provide
for uncollaterialized borrowings at prevailing interest rates. Both facilities
provide for borrowings at interest rates established by competitive bid.
Commitment fees are based upon the Company's lowest secured debt ratings and are
currently 0.10% on the $100 million facility and 0.085% on the $80 million
facility. Compensating balances are not maintained in connection with either
revolving credit facility. In addition various uncommitted borrowing
arrangements with banks total $15 million. The banks are not obligated to lend
under these uncommitted arrangements, and any borrowings are made at negotiated
interest rates and are uncollaterialized. No fees are paid on any of the
uncommitted arrangements, nor are compensating balances required. The weighted
average interest rate on short-term debt was 5.26% at December 31, 1998 and
5.97% at December 31, 1997.

         Total indebtedness for the two year periods ended December 31, 1998
were as follows:

<TABLE>
<CAPTION>
                                                                                  At December 31
                                                                              ----------------------
                                                                                1998          1997
                                                                              --------      --------
                                                                                  (In thousands)
<S>                                                                           <C>           <C>
Commercial paper, net                                                         $ 68,226      $ 34,219
Bank Loans                                                                         190    
                                                                              --------      --------
          Total short-term debt                                               $ 68,416      $ 34,219
                                                                              ========      ========
First mortgage bonds
  Series X, 9 1/2%, due 2005                                                  $ 60,000      $ 60,000
Pollution control revenue bonds, variable rate, due 2018                        61,260        61,260
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
  6.90%, due 1998                                                                             15,000
  5.90%, due 1999                                                               10,000        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        20,000
  7.50%, due 2007                                                               15,000        15,000
  7.00%, due 2007                                                               25,000        25,000
                                                                              --------      --------
          Total long-term debt                                                $376,698      $381,260
Amount due within one year                                                     (33,330)      (15,000)
Unamortized premium and discount, net                                             (326)         (363)
                                                                              --------      --------
          Total long-term debt, net.                                          $343,042      $365,897
                                                                              ========      ========
</TABLE>

<TABLE>
<CAPTION>
                                               1999       2000       2001      2002        2003   THEREAFTER
                                              -------    -------    -------   -------    -------  ----------
                                                                     (In thousands)
<S>                                           <C>        <C>        <C>       <C>        <C>       <C>
Amounts payable under long-term debt
  agreements............................      $33,330    $25,748    $25,693   $25,748    $25,000   $241,179
                                              =======    =======    =======   =======    =======   ========
</TABLE>

                                                 23
<PAGE>

         The first mortgage bonds are the only debt that is secured specifically
with the LPSC jurisdictional property, plant and equipment of 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 mortgage holder.

NOTE E -- COMMON STOCK

         In association with incentive compensation plans in effect during the
three-year period ended December 31, 1998, certain officers and key employees
were awarded shares of restricted 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. Had the Company accounted for the value of these awards
after 1995 using an estimate of their "fair value," including the effects of
historical volatility of the market price, rather than their "intrinsic value,"
additional compensation expense of $55,369, $57,512 and $104,272 would have been
recorded for the years 1998, 1997, and 1996 respectively.

         The Company makes no charge to expense with respect to the granting of
options. At December 31, 1998, all options were exercisable. The number of
shares of restricted stock previously granted for which restrictions had not
lapsed totaled 85,450 shares.

         Changes in incentive shares for the three-year period ended 
December 31, 1998, 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, 1996................................                             34,200           746,245
                                                                                    -------           -------

Options exercised.......................................              $14.75         (1,250)
                                                                      $16.78        (13,800)
Options lapsed..........................................              $14.75           (750)
Restricted stock granted................................                                              (12,751)
Restricted stock forfeited..............................                                                  615
Incentive stock awarded.................................                                               (2,258)
                                                                                    -------           -------

Balance, December 31, 1996..............................                             18,400           731,851
                                                                                    -------           -------

Options exercised.......................................              $16.78         (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.......................................              $16.78         (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
                                                                                    =======           =======
</TABLE>

                                       24
<PAGE>

          The assumptions used to calculate the additional compensation expense
are as follows:

<TABLE>
<S>                                                   <C>
                  Expected term:                        5.0 years
                  Volatility:                         12.29%
                  Expected dividend yield:             5.05%
                  Risk free interest rate:             5.79%
                  Weighted average fair value:       $3.1280 (Black-Scholes value)
</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 for Fiscal 1998 would approximate the pro forma amounts
below:

<TABLE>
<CAPTION>
                                                              (In thousands, except per share amounts)
                                                                           December 31, 1998
                                                                          As               Pro
                                                                       Reported           Forma
                                                                       --------           -----
                  <S>                                                   <C>              <C>
                  SFAS 123 Charge                                       $     0          $   525
                  Net income                                             51,664           51,139
                  Net income per Common Share (basic)                   $  2.30          $  2.28
</TABLE>

          The effects of applying SFAS 123 in this pro forma disclosure are not
indicative of future amounts. SFAS 123 does not apply to awards prior to 1995,
and the Company anticipates making awards in the future under its stock-based
compensation plans.

          The following table summarizes information about employee and director
stock options outstanding at December 31, 1998:

<TABLE>
<CAPTION>
                                                   Options Outstanding                         Options Exercisable
                                    --------------------------------------------------   ---------------------------------
                                                          Weighted        Weighted                          Weighted
                                                          Average          Average                           Average
Range of                                Number            Exercise        Remaining         Number          Exercise
Exercise Price                        Outstanding          Price         Contr. Life      Exercisable         Price
--------------                      ----------------    -------------   --------------   --------------   --------------
<S>                                     <C>                <C>              <C>               <C>              <C>
$31.88                                  12,503             $31.88           9.325              0                -
</TABLE>

         Various debt agreements contain covenants which restrict the amount of
retained earnings that may be distributed as dividends to common shareholders.
The most restrictive covenant requires that common shareholders' equity be not
less than 35% of total capitalization, including short-term debt. At December
31, 1998, approximately $111.3 million of retained earnings was not restricted.

NOTE F -- SUPPLEMENTARY PROFIT AND LOSS INFORMATION

<TABLE>
<CAPTION>
                                                                         For the years ended December  31,
                                                                       ------------------------------------
                                                                        1998           1997           1996
                                                                        ----           ----           ----
                                                                                  (In thousands)
<S>                                                                    <C>            <C>            <C>
Operating revenue derived from one customer...................         $35,612        $36,260        $33,359
                                                                       =======        =======        =======

                                             25
<PAGE>

Other taxes included in the consolidated income statements....         $35,420        $33,422        $29,595
Other taxes capitalized to plant..............................           1,351          1,325          1,049
                                                                       -------        -------        -------
Total other taxes.............................................         $36,771        $34,747        $30,644
                                                                       =======        =======        =======
Other taxes consist of:
  Parish and municipal property...............................         $21,215        $21,436        $16,302
  State and municipal franchise...............................          10,984         10,204         10,434
  Other.......................................................           4,572          3,107          3,908
                                                                       -------        -------        -------
Total other taxes.............................................         $36,771        $34,747        $30,644
                                                                       =======        =======        =======
</TABLE>

NOTE G -- PREFERRED STOCK

         In connection with the establishment of the ESOP, the Company sold
300,000 shares of 8.125% convertible preferred stock to the ESOP. Each share of
preferred stock is convertible into 4.8 shares of common stock. The amount of
total capitalization reflected in the consolidated financial statements has been
reduced by an amount of deferred compensation expense related to the shares of
convertible preferred stock which have not yet been allocated to ESOP
participants. The amount shown in the consolidated financial statements for
preferred dividend requirements in 1998, 1997 and 1996 has been reduced by
$521,000, $587,000 and $658,000, respectively, to reflect the benefit of the
income tax deduction for dividend requirements on unallocated shares held by the
ESOP.

         Upon involuntary liquidation, preferred shareholders are entitled to
receive par value for shares held before any distribution is made to common
shareholders. Upon voluntary liquidation, preferred shareholders are entitled to
receive the redemption price per share applicable at the time such liquidation
occurs plus any accrued dividends.

         Information about the components of preferred stock capitalization is
as follows:

<TABLE>
<CAPTION>
                                       Balance             Balance               Balance               BALANCE
                                       Jan. 1,             Dec. 31,              Dec. 31,              DEC. 31,
                                        1996      Change     1996       Change     1997      Change      1998
                                        ----      ------     ----       ------     ----      ------      ----
                                                         (In thousands, except share amounts)
<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...............         29,490   $ (239)     29,251   $ (178)        29,073   $ (384)     28,689
                                      ---------   ------   ---------   ------      ---------   ------   ---------
                                      $  30,519   $ (239)    $30,280   $ (178)     $  30,102   $ (384)  $  29,718
                                      =========   ======   =========   ======      =========   ======   =========

SUBJECT TO MANDATORY
  REDEMPTION
  4.50%, Series of 1955.........      $     400   $  (40)   $     360  $  (40)     $     320   $  (40)  $     280
  4.65%, Series of 1964.........          3,220     (140)       3,080     (140)        2,940   $ (140)      2,800
  4.75%, Series of 1965                   2,990      (58)       2,932      (72)        2,860   $ (260)      2,600
                                      ---------   ------    ---------   -------    ---------   ------   ---------
                                      $   6,610   $ (238)   $   6,372   $ (252)    $   6,120   $ (440)  $   5,680
                                      =========   =======   =========   =======    =========   ======   =========
Deferred compensation related to
  convertible preferred stock held
  by the ESOP...................      $ (22,595)  $ 1,844   $ (20,751)  $ 1,985    $ (18,766)  $1,843   $ (16,923)
                                      =========   =======   =========   =======    =========   ======   ========= 

CUMULATIVE PREFERRED STOCK,
  $100 par value
  Number of Shares
    Authorized..................      1,414,100    (1,975)  1,412,125    (2,125)   1,410,000   (4,000)  1,406,000
    Issued and Outstanding......        371,287    (4,768)    366,519    (4,301)     362,218   (8,240)    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>

                                       26
<PAGE>

         Preferred stock, other than the convertible preferred stock held by the
ESOP, is redeemable at the Company's option, subject to 30 days' prior written
notice to holders. Preferred stock subject to mandatory redemption is redeemable
annually through sinking funds or purchase funds at prices of not more than $100
per share until all shares have been redeemed. The convertible preferred stock
is redeemable at any time at the Company's option. If the Company were to elect
to redeem the convertible preferred shares, shareholders may elect to receive
the optional redemption price or convert the preferred shares into common stock.
The redemption provisions for the various series of preferred stock are shown in
the following table.

<TABLE>
<CAPTION>
                                                 Optional Redemption            Mandatory Redemption
                                              -------------------------  ---------------------------------
                                                       Price                Number of          Price
                                                      per Share          Shares Annually     per Share
                                                      ---------          ---------------     ---------
<S>                                                     <C>                   <C>              <C>
SERIES
4.50%.....................................              $101
4.50%, Series of 1955.....................              $102                    400            $100
4.65%, Series of 1964.....................              $102                  1,400*           $100
4.75%, Series of 1965.....................              $100                  1,300*           $100
Convertible, Series of 1991
  Through March 31, 1999..................           $102.4375
  Thereafter..............................        $101.625 to $100
</TABLE>

* THE COMPANY IS REQUIRED TO OFFER HOLDERS OF THE SERIES OF 1964 THE OPPORTUNITY
  TO REDEEM 1,400 SHARES EACH YEAR AND HOLDERS OF THE SERIES OF 1965 THE
  OPPORTUNITY TO REDEEM 1,300 SHARES EACH YEAR. ONLY SHARES ACTUALLY TENDERED,
  IF ANY, ARE REQUIRED TO BE REDEEMED.

NOTE H -- PENSION PLAN AND EMPLOYEE BENEFITS

         Substantially all employees 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, 1998.

         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.

         The employee pension plan's and other benefits' obligation, plan assets
and funded status as determined by the actuary at December 31, 1998 and 1997 are
presented in the following table.

                                         27
<PAGE>

<TABLE>
<CAPTION>

                                                                              (In thousands)
                                                            PENSION BENEFITS                    OTHER BENEFITS
                                                     -------------------------------   ---------------------------------
                                                         1998             1997             1998              1997
                                                     --------------   --------------   --------------  -----------------
<S>                                                  <C>              <C>              <C>             <C>
Change in benefit obligation
    Benefit obligation at beginning of year.......     $123,082         $ 97,724         $ 15,379        $ 13,341
    Service cost..................................        3,734            2,984              671             601
    Interest cost.................................        8,326            7,288            1,062           1,034
    Plan participants contributions...............                                            311
    Amendments....................................                        10,504
    Actuarial loss................................        4,591           10,991              176           1,246
    Expenses paid.................................       (1,100)          (1,111)       
    Benefits paid.................................       (5,912)          (5,298)            (997)           (843)
                                                     ----------       ----------       ----------      ----------
    Benefit obligation at end of year.............      132,721          123,082           16,602          15,379
                                                     ----------       ----------       ----------      ----------

Change in plan assets
    Fair value of plan assets at beginning of year      163,574          138,672        
    Actual return on plan assets..................       25,136           31,311
    Expense paid..................................       (1,100)          (1,111)
    Benefits paid.................................       (5,912)          (5,298)                       
                                                     ----------       ----------
    Fair value of plan assets at end of year......      181,698          163,574                        
                                                     ----------       ----------

Funded status.....................................       48,977           40,492          (16,602)        (15,379)
    Unrecognized net actuarial (gain).............      (48,421)         (40,815)          (1,434)         (1,676)
    Unrecognized transition obligation/(asset)....       (6,625)          (7,943)           7,186           7,700
    Prior service cost............................       13,745           14,714                       
                                                     ----------       ----------       ----------      ----------
    Prepaid / (accrued) benefit cost..............    $   7,676        $   6,448         $(10,850)      $  (9,355)
                                                     ----------       ----------       ----------      ----------
                                                     ----------       ----------       ----------      ----------
</TABLE>

         Employee pension plan assets are invested in the Company'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.

         The components of net periodic pension  and other  benefits  
cost/(income) for 1998, 1997 and 1996 are as follows, along with assumptions 
used:

<TABLE>
<CAPTION>

                                                            (In thousands)
                                          PENSION BENEFITS                      OTHER BENEFITS
                                 -----------------------------------   ----------------------------------
                                   1998         1997        1996         1998        1997         1996
                                 ----------   ----------  ----------   ----------  ----------   ---------
<S>                              <C>          <C>         <C>          <C>         <C>          <C>
Components of periodic benefit
costs
   Service cost...............   $  3,734     $  2,984     $ 3,010       $  671     $   601       $  596
   Interest cost .............      8,326        7,288       6,768        1,062       1,034          934
   Expected return on plan assets (12,797)     (10,290)     (9,572)                              

    Amortization of transition

</TABLE>
                                       28
<PAGE>


<TABLE>

<S>                              <C>          <C>         <C>          <C>         <C>          <C>
      obligation/(asset)......     (1,318)      (1,317)     (1,317)         513         513          513
    Prior period service cost    
      amortization............        969          347         280                               
    Net (gain)/loss...........       (142)                                  (66)        (82)    
                                 ----------   ----------  ----------   ----------  ----------   ---------
    Net periodic benefit          
      cost/(income)...........    $(1,228)    $    (988)  $   (831)      $2,180      $2,066        2,043
                                 ----------   ----------  ----------   ----------  ----------   ---------
                                 ----------   ----------  ----------   ----------  ----------   ---------

</TABLE>

<TABLE>
<CAPTION>

                                          PENSION BENEFITS                      OTHER BENEFITS
                                 -----------------------------------   ----------------------------------
                                   1998         1997        1996         1998        1997         1996
                                 ----------   ----------  ----------   ----------  ----------   ---------
<S>                              <C>          <C>         <C>          <C>         <C>          <C>
Weighted-average assumptions as 
  of December 31
    Discount rate.....................  6.75%        7.00%       7.50%   6.75%       7.00%        7.50%
    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 benefits was 9.5% in 1997 and 1998, declining to 5.5% by 2008 and 
remaining at 5.5% thereafter. The initial health care cost trend rate was 
reduced from 10% in 1996 to 9.5% in 1997 and 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-PERCENT POINT
                                                                     ---------------------------
                                                                      INCREASE        DECREASE
                                                                     ------------   ------------
<S>                                                                  <C>            <C>
Effect on total of service and interest cost components..........        $125          $(126)
Effect on postretirement benefit obligation......................        $935          $(981)

</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 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, 1998 and 1997, the 
ESOP had allocated to employees 124,984 and 109,668 shares, respectively.

         The table below contains information about the 401(k) Plan and the 
ESOP:

<TABLE>
                                                                               For the years ended December 31,
                                                                             --------------------------------------
                                                                                1998         1997         1996
                                                                                ----         ----         ----
                                                                                        (In thousands)
<S>                                                                             <C>          <C>          <C>
401(k) Plan expense....................................................         $1,107       $1,453       $1,490
                                                                                ------       ------       ------
Dividend requirements to ESOP on convertible preferred stock...........         $2,341       $2,367       $2,378
                                                                                ------       ------       ------
Interest incurred by ESOP on its indebtedness..........................         $1,683       $1,604       $1,746
                                                                                ------       ------       ------
Company contributions to ESOP..........................................         $1,075       $1,235       $1,239
                                                                                ------       ------       ------
</TABLE>


                                       29

<PAGE>

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 years ended December 31,
                                              -----------------------------------------------------------------
                                                     1998                  1997                   1996
                                                     ----                  ----                   ----
                                               AMOUNT       %        Amount        %       Amount      %
                                               ------       -        ------        -       ------      -  
                                                                (In thousands, except for %)

<S>                                            <C>        <C>       <C>         <C>        <C>        <C>
Book income before tax...................      $80,467    100.0     $80,248     100.0      $78,289    100.0
Tax at statutory  rate on book income before
tax......................................       28,163     35.0     $28,087      35.0      $27,401     35.0
Increase (decrease):                                                                                  
  Tax effect of AFUDC....................         (601)    (0.8)       (276)     (0.3)        (185)    (0.2)
  Amortization of investment tax credits.       (1,790)    (2.2)     (1,790)     (2.2)      (1,809)    (2.3)
  Tax effect of prior-year  tax benefits not
    deferred.............................        2,175      2.7         978       1.2           921     1.1
  Other, net.............................       (3,452)    (4.3)     (2,645)     (3.3)      (3,296)    (4.2)
                                              --------   ------    --------    ------     --------   ------
Total federal income tax expense.........       24,495     30.4      24,354      30.4       23,032     29.4
                                              --------   ------    --------    ------     --------   ------
Current state income tax expense.........        2,171      2.7       3,375       4.2        3,122      4.0
                                              --------   ------    --------    ------     --------   ------
Total federal and state income tax expense     $26,666     33.1     $27,729      34.6      $26,154     33.4
                                              --------   ------    --------    ------     --------   ------
                                              --------   ------    --------    ------     --------   ------
</TABLE>

Information about current and deferred income tax expense is as follows:

<TABLE>
<CAPTION>

                                                             1998          1997       1996
                                                             -----         ----       ----
                                                                      (In thousands)
<S>                                                          <C>         <C>         <C>
Current federal income tax expense....................        $17,582    $23,236     $21,023
Deferred federal income tax expense...................          8,703      2,908       3,818
Amortization of accumulated deferred investment tax credits    (1,790)    (1,790)     (1,809)
                                                             --------   --------    --------
Total federal income tax expense......................         24,495     24,354      23,032
Current state income tax expense......................          2,171      3,375       3,122
                                                             --------   --------    --------
Total federal and state income tax expense............        $26,666    $27,729     $26,154
                                                             --------   --------    --------
                                                             --------   --------    --------
Deferred federal income tax expense attributable to:                                 
  Depreciation........................................         11,748    $ 2,733      $4,834
  Storm damages.......................................            492       (332)         70
  Asset basis differences.............................           (571)    (1,707)        425
  Employee benefits...................................           (419)       321        (504)
  Fuel costs..........................................           (612)       790        (481)
  Reacquired debt.....................................           (249)     1,037        (238)
  Other...............................................         (1,686)        66        (288)
                                                             --------   --------    --------
  Total deferred federal income tax expense...........       $  8,703    $ 2,908      $3,818
                                                             --------   --------    --------
                                                             --------   --------    --------
</TABLE>

         The balance of accumulated deferred federal and state income tax 
assets and liabilities at December 31, 1998 and 1997 was comprised of the tax 
effect of the following:

<TABLE>
<CAPTION>

                                                                               1998            1997
                                                                             ---------         ----
                                                                    ASSET      LIABILITY  Asset     Liability
                                                                    -----      ---------  -----     ----------
                                                                                  (In thousands)
<S>                                                                 <C>        <C>        <C>       <C>
Depreciation and property basis differences...................      $  6,584   $143,975   $  6,978   $132,491
Allowance for funds used during construction..................                   39,270                40,608
Investment tax credits........................................        17,378                18,498
FASB 109 adjustments..........................................        62,235     92,513     42,614    112,562
Postretirement benefits other than pension....................         3,700                 3,266
Other.........................................................         7,448     10,861      5,200     10,462
                                                                    --------   --------   --------   --------
Accumulated deferred federal and state income taxes...........       $97,345   $286,619    $76,556   $296,123
                                                                    --------   --------   --------   --------
                                                                    --------   --------   --------   --------

</TABLE>

         Regulatory assets recorded for deferred taxes at December 31, 1998 and
1997 were $95.2 million and $115.3 million, respectively. Regulatory liabilities
recorded for deferred taxes at December 31, 1998 and 1997 were $81.0 million and
$62.5 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.

                                       30
<PAGE>

NOTE J -- DISCLOSURES ABOUT SEGMENTS

         The Company has determined that its reportable segment is based on 
the Company's method of internal reporting, which disaggregates its business 
units by regulatory jusidiction. The Company's reportable segment is LPSC 
Jusidictional Utility. This segment contains the revenues, expense and assets 
over which the LPSC may have material effect based upon state statues. The 
effects include rate-making powers, determination of depreciable lives, 
determination of pass through cost of fuel through the fuel cost adjustment 
clauses, and determination of prudent capital expenditures.

         The financial results of the Company's segment is presented on an 
accrual basis. Significant differences among the accounting policies of the 
segments as compared to the Company's consolidated 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. Material intersegment transactions occur 
on a regular basis.



















                                       31
<PAGE>

         The table below presents information about the reported operating
results and net assets of the Company's reportable segments.

                                           For the Year Ended December 31, 1998
                                           -------------------------------------
                                                      (In thousands)
<TABLE>
<CAPTION>                                                                        LPSC
                                                                             JUSIDICTIONAL        ALL
                                                                                UTILITY          OTHER           TOTAL
                                                                                -------          ------          -----
<S>                                                                         <C>                <C>            <C>
Operating revenues from external customers..............................      $   515,175         $11,197     $   526,372

Operating intersegment revenues.........................................                0         $ 4,982     $     4,982
                                                                                                             
Interest expense........................................................      $    27,360         $   792     $    28,152
                                                                                                             
Depreciation expense....................................................      $    48,369         $   910     $    49,279
                                                                                                             
Segment profit (loss)...................................................      $    79,383         $   610     $    79,993

Segment assets..........................................................      $ 1,383,648         $98,248     $ 1,481,896


Reconciliation between segment amount and consolidated amounts

OPERATING REVENUES
Total  operating revenues for all segments..............................         $531,354
Reclassification and elimination of other income/expense................          (16,179)
                                                                             ------------ 
    Total consolidated operating revenues...............................         $515,175
                                                                             ============

PROFIT OR LOSS
Total profit or loss on reportable segments.............................         $ 79,383
Other profit or loss....................................................              610
Intersegment profit included in other income............................              474
Unallocated items
    Income taxes........................................................          (26,666)
    Preferred dividend requirements, net................................           (2,137)
                                                                             ------------ 
    Net income to common................................................         $ 51,664
                                                                             ============

ASSETS
Total assets for reportable segments....................................       $1,383,648
Other assets............................................................           98,248
Assets eliminated in consolidation......................................          (52,896)
                                                                             ------------ 
    Total consolidated assets...........................................       $1,429,000
                                                                             ============

<CAPTION>

                                                                                SEGMENT                      CONSOLIDATION
OTHER SIGNIFICANT ITEMS                                                          TOTALS       ADJUSTMENTS       TOTALS
                                                                                 ------       -----------       ------
<S>                                                                            <C>            <C>            <C>             
Depreciation expense....................................................          $49,279           $(910)        $48,369
Interest expense........................................................          $28,152           $(792)        $27,360

</TABLE>
          The reconciling item of assets eliminated in consolidation
          consists of certain receivables due to associated companies that
          are eliminated for the purpose of consolidated reporting.  All
          other adjustments are immaterial.


                                      32



<PAGE>


                                           For the Year Ended December 31, 1997
                                           ------------------------------------
                                                      (In thousands)
<TABLE>
<CAPTION>
                                                                                 LPSC
                                                                             JUSIDICTIONAL       ALL
                                                                                UTILITY          OTHER           TOTAL
                                                                                -------          -----           -----
<S>                                                                          <C>                <C>           <C>
Operating revenues from external customers..............................     $    456,245       $     924     $   457,169
                                                                                                              
Operating intersegment revenues.........................................     $          0       $   2,092     $      2,092
                                                                                                              
Interest expense........................................................     $     28,586       $     440     $    29,026
                                                                                                              
Depreciation expense....................................................     $     45,890       $     624     $    46,514
                                                                                                              
Segment profit (loss)...................................................     $     78,938       $   1,287     $    80,225
                                                                                                              
Segment assets..........................................................     $  1,338,135       $  28,511     $ 1,366,646


Reconciliation between segment amount and consolidated amounts

OPERATING REVENUES
Total operating revenues for all segments...............................         $459,261
Reclassification and elimination of other income/expense................           (3,016)
                                                                             ------------
    Total consolidated operating revenues...............................         $456,245
                                                                             ============

PROFIT OR LOSS
Total profit or loss on reportable segments.............................        $  78,938
Other profit or loss....................................................            1,287
Intersegment profit included in other income............................               23
Unallocated items
    Income taxes........................................................          (27,729)
    Preferred dividend requirements, net................................           (2,117)
                                                                             ------------
    Net income to common................................................         $ 50,402
                                                                             ============

ASSETS
Total assets for reportable segments....................................       $1,338,135
Other assets............................................................           28,511
Assets eliminated in consolidation......................................           (5,602)
                                                                             ------------
    Total consolidated assets...........................................       $1,361,044
                                                                             ============
<CAPTION>
                                                                                SEGMENT                      CONSOLIDATION
OTHER SIGNIFICANT ITEMS                                                          TOTALS       ADJUSTMENTS       TOTALS
                                                                                 ------       -----------       ------
<S>                                                                            <C>           <C>             <C>     
Depreciation expense....................................................          $46,514           $(624)        $45,890
Interest expense........................................................          $29,026           $(440)        $28,586

</TABLE>

          The reconciling item of assets eliminated in consolidation
          consists of certain receivables due to associated companies that
          are eliminated for the purpose of consolidated reporting.  All
          other adjustments are immaterial.

                                      33

<PAGE>


                                           For the Year Ended December 31, 1996
                                           ------------------------------------
                                                      (In thousands)
<TABLE>
<CAPTION>
                                                                                 LPSC
                                                                             JUSIDICTIONAL       ALL
                                                                                UTILITY          OTHER           TOTAL
                                                                                -------          -----           ------
<S>                                                                         <C>                <C>          <C>
Operating revenues from external customers..............................     $    437,121       $     992    $   438,113

Operating intersegment revenues.........................................     $          0       $      19    $        19
                                                                             

Interest expense........................................................     $     28,009       $      11    $    28,020
 
Depreciation expense....................................................     $     43,441       $       0    $    43,441

Segment profit (loss)...................................................     $     77,402       $     887    $     8,289

Segment assets..........................................................     $  1,297,033       $  25,415    $ 1,322,448

Reconciliation between segment amount and consolidated amounts

OPERATING REVENUES
Total operating revenues for all segments...............................         $438,132
Reclassification and elimination of other income/expense................           (1,011)
                                                                             ------------
    Total consolidated operating revenues...............................         $437,121
                                                                             ============

PROFIT OR LOSS
Total profit or loss on reportable segments.............................        $  77,402
Other profit or loss....................................................              887
Intersegment profit included in other income............................                0
Unallocated items
    Income taxes........................................................          (26,154)
    Preferred dividend requirements, net................................           (2,074)
                                                                             ------------
    Net income to common................................................        $  50,061
                                                                             ============

ASSETS
Total assets for reportable segments....................................       $1,297,033
Other assets............................................................           25,415
Assets eliminated in consolidation......................................             (677)
                                                                             ------------
    Total consolidated assets...........................................       $1,321,771
                                                                             ============
<CAPTION>
                                                                                SEGMENT                      CONSOLIDATION
OTHER SIGNIFICANT ITEMS                                                          TOTALS       ADJUSTMENTS       TOTALS
                                                                                 ------       -----------       ------
<S>                                                                             <C>          <C>             <C>
Depreciation expense....................................................          $43,441            $  0         $43,441
Interest expense........................................................          $28,020            $(11)        $28,009

</TABLE>

          The reconciling item of assets eliminated in consolidation
          consists of certain receivables due to associated companies that
          are eliminated for the purpose of consolidated reporting.  All
          other adjustments are immaterial.

                                      34

<PAGE>

NOTE K -- SABINE TEXICAN PIPELINE ACQUISITION

         On August 1, 1998, Cleco Energy, LLC (Energy) a joint venture 
between the Company and Covenant Energy Corporation of Houston, purchased all 
of the capital stock of Sabine Texican Pipeline Company (Sabine) of Lufkin, 
Texas . Sabine is an energy company engaged in the exploration, production, 
gathering, marketing and transmission of natural gas. Energy paid the sole 
shareholder of Sabine $2.5 million and gave him a 13% equity interest in 
Energy. Sabine has approximately $24.3 million in assets, $7 million in 
current liabilities and $7.1 million in long-term debt. The acquisition added 
415 miles of gathering and transmission pipeline in Texas and Louisiana, 
serving wholesale customers as well as oil and gas producing properties in 
West Texas. After the acquisition of Sabine, the Company has a 44.37% equity 
interest and a 51% voting interest in Energy. The acquisition was recorded 
under the purchase method as required under Accounting Principals Board 
Opinion No. 16 (APB 16), "Business Combinations". The disclosures set forth 
in APB 16 are immaterial and are not presented.

NOTE L -- ACCRUAL OF ESTIMATED CUSTOMER CREDITS

         The Company's results for the year ended December 31, 1998, reflect 
an accrual of estimated customer credits which may be required under the 
terms of an earnings review settlement reached with the LPSC in 1996. The 
accrual for estimated customer credits was $4.8 million. The settlement set 
the Company's rates for a period of five years, and also provided for annual 
base rate tariff reductions of $3 million in 1997 and an additional $2 
million in 1998. The period was extended to eight years, to 2004, as a part 
of an agreement with the LPSC to transfer assets at Coughlin Power Station 
(CPS) to an affiliate, Cleco Evangeline LLC (Cleco Evangeline). The transfer 
is a part of the repowering of CPS, described in Note M, below. 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 a 12.25% and 13% return on equity. 
This gives the Company an effective regulated equity return allowance on the 
LPSC jurisdictional operations of up to 12.625%. All such earnings above 13% 
return on equity are credited to customers. The amount of credits due 
customers, if any, is determined by the LPSC annually based on the Company's 
12 month results ending as of September 30 of each year. The amount of the 
credit has not yet been determined by the LPSC. Under the settlement, such 
credits are to be made on customers' bills the following summer.

NOTE M -- REPOWERING PROJECT

         In July 1998, the Company's Board of Directors approved the 
construction of a 750-megawatt repowering project (Project) to be implemented 
at the site of its existing CPS. The Project will use three new natural 
gas-fueled combustion turbine generators and three related heat recovery 
system generators to repower two existing units at CPS.

         It is anticipated that the Project's generation capacity and energy 
will be available to the Company at competitive market rates and also to the 
regional wholesale market at competitive market rates. The degree to which 
the output of CPS will be sold and delivered to the Company and to 
unaffiliated purchasers, as well as the terms and conditions of such sales, 
remains to be determined in now ongoing commercial negotiations and in 
related regulatory proceedings before the LPSC and FERC.

         One of the Company's subsidiaries, Cleco Evangeline, will own and 
operate the Project. The total cost of the Project is expected to be $250 
million and is scheduled to be completed by June 1, 2000. As of December 31, 
1998, the Company has spent approximately $37.1 million on the Project, which 
is currently being funded through the Company's commercial paper program. 
Permanent financing for the Project has not yet been determined and is 
expected to be finalized during 1999. Implementation of the Project is 
subject to approval by the LPSC and FERC. In February 1999, the LPSC did 
approve the transfer of the existing CPS assets out of LPSC regulated rate 
base into Cleco Evangeline. The actual transfer is expected to occur in the 
fourth quarter of 1999. In return for the approval of the asset transfer, the 
Company agreed to extend the terms of its 1996 rate settlement with the LPSC 
for an additional three years, to the year 2004. The agreement also requires 
the Company to hold harmless its ratepayers from negative impacts resulting 
from the removal of the generating assets from the rate base. In return, 

                                       35

<PAGE>

the Company is authorized to transfer the assets at their net book value of 
approximately $10 million. Approvals from the LPSC and FERC are expected to 
be obtained in 1999.

NOTE N -- COMMITMENTS AND CONTINGENCIES

         Construction expenditures for 1999 are estimated to be $182.6 
million, excluding AFUDC, and for the five-year period ending 2003 are 
expected to total $571.5 million, excluding AFUDC. Scheduled maturities of 
debt and preferred stock, including $20 million of medium-term notes which 
are due in 2008, but putable in November 1999, will total approximately $33.3 
million for 1999 and approximately $135.5 million for the five-year period 
ending 2003.

         The Company has entered into various long-term contracts for the 
procurement of coal and lignite to fuel certain of our 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 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 Company's 
electric generating unit.

         The coal for one of the Company's jointly-owned electric generating 
units is transported under a long-term transportation contract with a 
railroad. The railroad is overcoming operating problems, which began in 1997 
and resulted in reduced volumes delivered to the unit. Coal inventory at the 
unit is currently above the Company's desired minimum level. Based on the 
railroad's anticipated delivery schedule of future coal shipments, management 
anticipates the inventory to remain at or above desired levels.

         The Company has accrued for liabilities to third parties, 
environmental claims, employee medical benefits, storm damages and 
deductibles under insurance policies which 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.

         The Company has committed to provide credit support up to $10 
million for working capital and electricity or natural gas commodity 
positions for Energy. Additionally, commitments for asset development 
projects will be made as they occur up to $5 million per year for years 1998 
through 2002. Amounts not advanced in any year are added to the amount 
available for the remaining years. $2.5 million was advanced in 1998 for the 
acquisition of Sabine . See the Notes to the Consolidated Financial 
Statements, Note K, "Sabine Texican Pipeline Acquisition".

         SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets 
and for Long-Lived Assets to be Disposed Of" (SFAS 121), establishes 
accounting standards for determining if long-lived assets are impaired, and 
when and how losses, if any, should be recognized. The Company believes that 
the net cash flows that will result from the operation of its assets are 
sufficient to cover the carrying value of the assets.

         The Company has recorded regulatory assets and liabilities, 
primarily for the effects of income taxes, as a result of past rate actions 
of our regulators, pursuant to SFAS No. 71, "Accounting for the Effects of 
Certain Types of Regulation" (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, 1998, the Company recorded $14.2 million of 
regulatory assets, net of regulatory liabilities, because of the regulatory 
requirement to flow through the tax benefits of 

                                       36

<PAGE>

accelerated deductions to current customers and an implied regulatory compact 
that future customers would pay when the Company paid 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, 
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 such regulatory assets were determined not to be recoverable, we 
would be required to write off or write down such assets.

NOTE O -- MISCELLANEOUS FINANCIAL INFORMATION (UNAUDITED)

         Quarterly information for 1998 and 1997 is shown in the following 
table.

<TABLE>
<CAPTION>
                                                                                            1998
                                                                      ----------------------------------------------
                                                                        1ST          2ND          3RD          4TH
                                                                      QUARTER      QUARTER      QUARTER      QUARTER
                                                                      -------      -------      -------      -------
                                                                         (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<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 9/16      $34 3/4      $33 7/8      $36 1/8
  Low........................................................         $30 1/4          $29      $28 5/8      $32 7/8
<CAPTION>
                                                                                           1997
                                                                   ----------------------------------------------------
                                                                       1st          2nd          3rd          4th
                                                                     Quarter      Quarter      Quarter      Quarter
                                                                     -------      -------      -------      -------
                                                                        (In thousands, except per share amounts)
<S>                                                                  <C>          <C>          <C>          <C>    
Operating revenues...........................................        $97,668      $105,324      $138,099    $115,154
Operating income.............................................        $14,798       $18,459       $28,624     $16,929
Net income applicable to common stock........................         $7,002       $10,744       $22,360     $10,296
Basic net income per average common share....................          $0.31         $0.48         $1.00       $0.45
Diluted net income per average common share..................          $0.31         $0.47         $0.95       $0.45
Dividends paid per common share..............................         $0.385        $0.395        $0.395      $0.395
Market price per share
  High.......................................................            $28       $28 1/8       $28 7/16    $33 1/8
  Low........................................................            $26       $24 3/4      $25 13/16   $25 9/16
</TABLE>

     The Company's common stock is listed for trading on the New York and 
Pacific stock exchanges under the ticker symbol "CNL." The Company's 
preferred stock is not listed on any stock exchange. On December 31, 1998, 
the Company had 10,476 common and 168 preferred shareholders, as determined 
from the records of the transfer agent.

     On January 22, 1999, the Company's Board of Directors declared a 
quarterly dividend of 40.5 cents per share payable February 15, 1999, to 
common shareholders of record on February 1, 1999. Preferred dividends were 
also declared, payable March 1, 1999, to preferred shareholders of record on 
February 15, 1999.

                                       37

<PAGE>

                      REPORT OF INDEPENDENT ACCOUNTANTS




To the Board of Directors and
Shareholders of Cleco Corporation

In our opinion, the accompanying consolidated balance sheets and the 
related consolidated statements of income and common shareholder's equity 
and of cash flows present fairly, in all material respects, the 
financial position of Cleco Corporation ("the Company") and its 
subsidiaries at December 31, 1998 and 1997, and the results of their 
operations and their cash flows for each of the three years in the period 
ended December 31, 1998, in conformity with generally accepted 
accounting principles.  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 generally accepted auditing 
standards 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 27, 1999


                                       38

<PAGE>



                                   GLOSSARY


ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
An amount recorded by the Company to represent the costs of those funds used to
finance the Company's construction projects.

DEFERRED TAXES
Amounts representing adjustments to current income taxes which will increase or
decrease income taxes to be paid in future periods. These result from timing
differences between generally accepted accounting principles or regulatory
guidelines and income tax regulations.

DEREGULATION
The removal of regulatory restrictions on the electric utility industry, thus
allowing electric utilities to compete for electric customers at current market
prices.

DERIVATIVE
A complex financial instrument whose value is based on an underlying benchmark,
such as a commodity, a security, an index or an interest rate.

FEDERAL ENERGY REGULATORY COMMISSION (FERC)
A federal regulatory body composed of five appointed members. This body sets and
monitors the Company's rates for wholesale sales of electricity,
interconnections with other utilities, and transmission service, as well as
regulates the Company's short-term borrowing.

GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP)
Rules and guidelines for recording and summarizing transactions, and for the
preparation of financial statements. These rules and guidelines are set by
various accounting authoritative bodies.

KILOWATT-HOUR (KWH)
A measure of electric consumption or generation equivalent to the use of 
1,000 watts of power over a period of one hour.

LOUISIANA PUBLIC SERVICE COMMISSION (LPSC)
A state regulatory body composed of five elected members. This body sets and
monitors the Company's rates for retail electric service, the installation of
new generating capacity, and the Company's issuance of stock securities and
long-term debt.

MEGAWATT (MW)
A measure of electric consumption or generation equivalent to the use of
1,000,000 watts of power.

OPEN TRANSMISSION ACCESS
As a FERC-regulated electric utility, the Company must open its transmission
system to third parties under the same terms and conditions as the Company's use
of its own transmission system.

REGULATORY ASSET
An item of value, created by a regulatory agency, recoverable from the Company's
customers at some point in the future.

REGULATORY LIABILITY
An obligation of the Company, created by a regulatory agency, payable to the
Company's customers at some point in the future.

RETAIL CUSTOMER
An end-user of electricity.

STRANDED COSTS
In an environment where customers may choose their electric supplier, fixed
costs are those associated with utility assets specifically dedicated to, or
used by, departing customers who choose a new electric supplier. If the fixed
costs are not recoverable from the departing customers, then the Company will
have to write off these costs or charge the remaining customers of the Company.

                                       39

<PAGE>

WHOLESALE CUSTOMER
Another investor owned electric utility, municipality, cooperative, power broker
or marketer or the like that purchases electricity from the Company for resale.


                                       40

<PAGE>

  BOARD OF DIRECTORS/OFFICERS

BOARD OF DIRECTORS*

SHERIAN G. CADORIA
Brigadier General, U.S. Army 
(Retired); President, Cadoria 
Speaker and Consultancy 
Service, Pineville, 
Louisiana. Member of the 
Compensation Committee.
AGE 58; ELECTED 1993.

RICHARD B. CROWELL
Partner, Crowell & Owens, 
Attorneys at Law, Alexandria, 
Louisiana.  Member of the 
Audit Committee
AGE 60; ELECTED 1997.

DAVID M. EPPLER
Executive Vice President and 
Chief Operating Officer, 
Cleco Corporation.
AGE 48; ELECTED 1998.

J. PATRICK GARRETT
President and Chief Executive 
Officer, Windsor Food 
Company, Ltd, Houston, Texas. 
Member of the Compensation 
Committee.
AGE 55; ELECTED 1981.

F. BEN JAMES, JR.
President, James Investments, 
Inc. (real estate development 
and international marketing), 
Ruston, Louisiana. Chairman 
of the Audit Committee and 
member of the Executive 
Committee.
AGE 62; ELECTED 1986.

A. DELOACH MARTIN, JR.
Chairman, Central Engineering 
& Supply Company (wholesale 
distributor of industrial 
supplies), Dallas, Texas. 
Chairman of the Executive 
Committee and member of the 
Audit Committee.
AGE 69; ELECTED 1978.

GREGORY L. NESBITT
President and Chief Executive 
Officer, Cleco Corporation, 
Pineville, Louisiana. Member 
of the Executive Committee.
AGE 60; ELECTED 1988.

ROBERT T. RATCLIFF
Chairman, President and Chief 
Executive Officer, Ratcliff 
Construction Company, Inc., 
Alexandria, Louisiana. Member 
of the Audit Committee.
AGE 56; ELECTED 1993.

EDWARD M. SIMMONS
Chairman and Chief Executive 
Officer, McIlhenney Company 
(Tabasco Brand Products), 
Avery Island, Louisiana. 
Chairman of the Compensation 
Committee and member of the 
Executive Committee.
AGE 70; ELECTED 1992.

WILLIAM H. WALKER, JR.
President, Howard, Weil, 
Labouisse, Friedrichs Inc. 
(investment banking firm), 
New Orleans, Louisiana. 
Member of the Executive 
Committee and Compensation 
Committee.
AGE 53; ELECTED 1996.



OFFICERS*

GREGORY L. NESBITT
President and Chief Executive 
Officer.
AGE 60; JOINED CLECO IN 1980.

DAVID M. EPPLER
Executive Vice President and 
Chief Operating Officer.
AGE 48; JOINED CLECO IN 1981.

THOMAS J. HOWLIN
Senior Vice President, 
Finance and Chief Financial 
Officer.
AGE 50; JOINED CLECO IN 1997.

CATHERINE C. POWELL
Senior Vice President, 
Employee and Corporate 
Services.
AGE 43; JOINED CLECO IN 1991.

DARRELL J. DUBROC
Vice President, Generation 
Services.
AGE 37; JOINED CLECO IN 1985.

JEFFREY W. HALL
Vice President, Retail Energy 
Services.
AGE 47; JOINED CLECO IN 1981.

MARK H. SEGURA
Vice President, Distribution 
Services.
AGE 40; JOINED CLECO IN 1984.

ROBERT A. PULASKI
Controller.
AGE 41; JOINED CLECO IN 1981.

MICHAEL P. PRUDHOMME
Secretary-Treasurer.
AGE 55; JOINED CLECO IN 1967.

CARLA D. BOOTHE
Assistant Corporate Secretary.
AGE 34; JOINED CLECO IN 1996.

* Ages as of December 31, 1998