UNITED STATES
                   SECURITIES AND EXCHANGE COMMISSION
                         WASHINGTON, D.C. 20549

                                FORM 10-K
(Mark One)
  X     Annual  Report  Pursuant to Section 13 or 15(d) of the Securities
        Exchange Act of 1934 
        For the fiscal year ended December 31, 1998
                                   OR
        Transition  Report  Pursuant  to  Section  13  or  15(d)  of  the
        Securities Exchange Act of 1934 
        For the transition period _____ to _____
        
        Commission File Number 1-8180

                            TECO ENERGY, INC.
         (Exact name of registrant as specified in its charter)

                 FLORIDA                         59-2052286
     (State or other jurisdiction of          (I.R.S. Employer
     incorporation or organization)       Identification Number)

               TECO Plaza
         702 N. Franklin Street
             Tampa, Florida                        33602
(Address of principal executive offices)        (Zip Code)

Registrant's telephone number, including area code:  (813) 228-4111

Securities registered pursuant to Section 12(b) of the Act:

                                         Name of each exchange on
           Title of each class                which registered    
      Common Stock, $1.00 par value       New York Stock Exchange
      Common Stock Purchase Rights        New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate  by check mark whether the registrant (1) has filed all reports
required  to  be filed by Section 13 or 15(d) of the Securities Exchange
Act  of  1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
                        YES     X        NO      

Indicate  by  check  mark if disclosure of delinquent filers pursuant to
Item  405  of  Regulation  S-K  is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information  statements  incorporated  by  reference in Part III of this
Form 10-K or any amendments to this Form 10-K.   X   

The  aggregate market value of the voting stock held by nonaffiliates of
the registrant as of February 28, 1999 was $2,861,810,975.

The  number of shares of the registrant's common stock outstanding as of
February 28, 1999 was 131,956,702.

                   DOCUMENTS INCORPORATED BY REFERENCE

Portions  of  the Definitive Proxy Statement relating to the 1999 Annual
Meeting  of Shareholders of the registrant are incorporated by reference
into Part III.


                                PART I
Item 1.   BUSINESS.

TECO ENERGY

     TECO  Energy,  Inc.  (TECO Energy) was incorporated in Florida in
1981,  as  part  of  a  restructuring  in  which  it became the parent
corporation of Tampa Electric Company.
     TECO  Energy  currently owns no operating assets but holds all of
the  common  stock of Tampa Electric and the other subsidiaries listed
below.  TECO  Energy  is  a public utility holding company exempt from
registration under the Public Utility Holding Company Act of 1935.
     In  June  1997,  TECO  Energy  acquired  Lykes  Energy, Inc. (the
Peoples  companies). As part of this acquisition, Lykes' regulated gas
distribution  utility  was  merged into Tampa Electric Company and now
operates as the Peoples Gas System division of Tampa Electric Company.

     TECO Energy's significant business segments are identified below:

     --   Tampa  Electric  Company,  a  Florida  corporation  and TECO
Energy's  largest subsidiary, provides retail electric service to more
than  537,000  customers  in  West  Central  Florida with a net system
generating  capability  of 3,615 megawatts (MWS) (Tampa Electric). The
Peoples  Gas  System  division  (PGS)  is  engaged  in  the  purchase,
distribution and marketing of natural gas for residential, commercial,
industrial  and  electric  power  generation customers in the State of
Florida. With 240,000 customers, PGS has operations in Florida's major
metropolitan  areas.  Annual natural gas throughput (the amount of gas
delivered  to  its customers including transportation only service) in
1998 was 912 million therms.

     --   TECO  Transport  Corporation  (TECO  Transport),  a  Florida
corporation, owns no operating assets but owns all of the common stock
of  four  subsidiaries  which  transport,  store and transfer coal and
other dry bulk commodities.

     --   TECO  Coal  Corporation (TECO Coal), a Kentucky corporation,
owns  no  operating  assets  but  owns all of the common stock of five
subsidiaries  that  own mineral rights, and own/or operate surface and
underground  mines  and  coal  processing  and  loading  facilities in
Kentucky and Tennessee.

     --   TECO  Power  Services  Corporation  (TECO Power Services), a
F l o rida  corporation,  has  subsidiaries  that  have  interests  in
i n dependent  power  projects  in  Florida  and  Guatemala,  and  has
i n v e stments  in  unconsolidated  affiliates  that  participate  in
independent power projects in other parts of the U.S. and the world.

     TECO  Energy's other diversified businesses include the following
corporations identified below:

     --   TECO  Coalbed  Methane,  Inc.  (TECO  Coalbed  Methane),  an
Alabama  corporation,  participates  in  the production of natural gas
from coalbeds located in Alabama's Black Warrior Basin.





                                   2


     --   Peoples  Gas  Company  (PGC),  a  Florida corporation, sells
liquefied  petroleum  gas,  or  propane,  to  almost 55,000 customers,
primarily within peninsular Florida. 

     --   TECO  Gas  Services,  Inc.  (TECO  Gas  Services), a Florida
corporation,  markets  natural  gas to large commercial and industrial
customers.

     --   TeCom  Inc. (TeCom), a Florida corporation, markets advanced
energy management, automation and control systems.

     --   B o sek,  Gibson  and  Associates,  Inc.  (BGA),  a  Florida
corporation,  provides  engineering  and  energy services to customers
primarily in Florida and California.

     For  financial  information  regarding  TECO Energy's significant
business segments, see Note K, Segment Information on pages 77 and 78.

     TECO  Energy  and its subsidiaries had 5,470 employees as of Dec.
31, 1998.

TAMPA ELECTRIC--Electric Operations

     Tampa  Electric  Company  was incorporated in Florida in 1899 and
was reincorporated in 1949. Tampa Electric Company is a public utility
operating  within  the  state  of  Florida. Through its Tampa Electric
division,  it  is  engaged  in the generation, purchase, transmission,
distribution  and sale of electric energy. The retail territory served
comprises an area of about 2,000 square miles in West Central Florida,
including  Hillsborough  County  and parts of Polk, Pasco and Pinellas
Counties,  and  has  an  estimated population of over one million. The
principal  communities  served are Tampa, Winter Haven, Plant City and
Dade  City.  In addition, Tampa Electric engages in wholesale sales to
utilities  and  other  resellers of electricity. It has three electric
generating  stations in or near Tampa, one electric generating station
in  southwestern  Polk  County,  Florida  and  two electric generating
stations  (one of which is on long-term standby) located near Sebring,
a city located in Highlands County in South Central Florida.
     Tampa  Electric had 2,833 employees as of Dec. 31, 1998, of which
1,089  were represented by the International Brotherhood of Electrical
Workers  (IBEW)  and  334  by  the  Office  and Professional Employees
International Union.
     In  1998,  approximately  46  percent  of  Tampa Electric's total
operating  revenue was derived from residential sales, 27 percent from
commercial  sales, 9 percent from industrial sales and 18 percent from
other sales including bulk power sales for resale. 













                                   3


     The  sources of operating revenue for the years indicated were as
follows:

(millions)                        1998       1997        1996 

Residential                   $  563.2   $  532.3    $  539.7 
Commercial                       335.2      326.7       321.3 
Industrial-Phosphate              59.3       61.3        59.6 
Industrial-Other                  53.4       51.5        43.3 
Other retail sales  
  of electricity                  86.9       85.0        83.5 
Sales for resale                  89.6       94.3        93.3 
Deferred revenues                 38.3       30.5       (34.2)
Other                              8.7        7.6         6.4 
                              $1,234.6   $1,189.2    $1,112.9 

     No  significant  part  of  Tampa Electric's business is dependent
upon a single customer or a few customers, the loss of any one or more
of  whom  would have a significantly adverse effect on Tampa Electric,
except  for IMC-Agrico (IMCA), a large phosphate producer representing
less  than  3  percent  of  Tampa  Electric's  1998 base revenues. See
further discussion of IMCA on page 46.
     Tampa  Electric's business is not a seasonal one, but winter peak
loads   are  experienced  due  to  fewer  daylight  hours  and  colder
temperatures,  and summer peak loads are experienced due to use of air
conditioning and other cooling equipment.

Regulation

     The  retail  operations  of  Tampa  Electric are regulated by the
Florida  Public Service Commission (FPSC), which has jurisdiction over
retail  rates,  the  quality  of  service,  issuances  of  securities,
planning,  siting  and  construction  of  facilities,  accounting  and
depreciation practices and other matters.
     In  general,  the  FPSC's  pricing objective is to set rates at a
level  that  allows  the  utility  to  collect total revenues (revenue
requirements)  equal  to  its  cost  of providing service, including a
reasonable return on invested capital.
     The  costs  of  owning,  operating  and  maintaining  the utility
system,  other  than  fuel,  purchased power, conservation and certain
environmental  costs,  are  recovered  through base rates. These costs
include operation and maintenance expenses, depreciation and taxes, as
well  as  a  return  on Tampa Electric's investment in assets used and
useful  in  providing electric service (rate base). The rate of return
on  rate  base,  which  is  intended  to  approximate Tampa Electric's
weighted  cost  of  capital, primarily includes its costs for debt and
preferred  stock,  deferred  income  taxes  at a zero cost rate and an
allowed  return  on  common equity. Base prices are determined in FPSC
price  setting  hearings  which  occur  at  irregular intervals at the
initiative  of  Tampa  Electric,  the  FPSC  or other parties. See the
discussion  of the FPSC-approved agreements covering 1995 through 1999
on pages 43 through 44.
     Fuel,  conservation,  certain environmental and certain purchased
p o w e r  costs  are  recovered  through  levelized  monthly  charges
established  pursuant  to the FPSC's fuel adjustment and cost recovery
clauses.  These  charges, which are reset annually in an FPSC hearing,
are  based  on  estimated  costs  of  fuel,  environmental compliance,
conservation programs and purchased power and estimated customer usage

                                   4


for  a  specific recovery period, with a true-up adjustment to reflect
the variance of actual costs from the projected charges.
     The  FPSC  may  disallow  recovery of any costs that it considers
imprudently incurred.
     Tampa  Electric  is  also  subject  to  regulation by the Federal
Energy  Regulatory  Commission  (FERC)  in  various respects including
wholesale power sales, certain wholesale power purchases, transmission
services and accounting and depreciation practices.
     Federal, state and local environmental laws and regulations cover
air  quality,  water  quality,  land  use, power plant, substation and
transmission  line siting, noise and aesthetics, solid waste and other
environmental matters. See Environmental Matters on pages 8 and 9.
     TECO  Transport,  TECO Coal and TECO Power Services  subsidiaries
sell  transportation  services,  coal,  and  generating  capacity  and
energy,  respectively, to Tampa Electric in addition to third parties.
The  transactions  between Tampa Electric and these affiliates and the
prices  paid  by  Tampa Electric are subject to regulation by the FPSC
and FERC, and any charges deemed to be imprudently incurred may not be
allowed  to  be recovered from Tampa Electric's customers. See Utility
Regulation  on pages 43 through 47. Except for transportation services
performed  by  TECO  Transport  under  the  U.S. bulk cargo preference
p r ogram,  the  prices  charged  by  TECO  Transport  and  TECO  Coal
subsidiaries  to  third-party  customers are not subject to regulatory
oversight. See also TECO Power Services on pages 15 through 18.

Competition

     Tampa  Electric  s retail electric business is substantially free
from  direct competition with other electric utilities, municipalities
and  public  agencies.  At  the  present  time,  the principal form of
competition  at  the  retail level consists of natural gas and propane
for residences and businesses and the self-generation option available
to  larger  users  of  electric  energy. Such users may seek to expand
their options through various initiatives including legislative and/or
regulatory  changes that would permit competition at the retail level.
Tampa  Electric  intends to take all appropriate actions to retain and
expand  its  retail  business,  including managing costs and providing
high-quality service to retail customers. 
     In  1998,  the  FPSC  approved  a  tariff for Tampa Electric that
should assist in reducing the loss of existing at-risk load and assist
in  the  acquisition  of  new  load. The Commercial/Industrial Service
Rider  included  in  this  tariff  is  a  load  retention, or economic
development  contract,  that  provides  for  flexible  pricing to meet
competitive  alternatives  available  to  existing  or  potential  new
customers.
     There  is  presently  active  competition  in the wholesale power
markets  in Florida, and this is increasing largely as a result of the
Energy  Policy  Act  of 1992 and related federal initiatives. This Act
removed  for  independent  power producers certain regulatory barriers
and   required  utilities  to  transmit  power  from  such  producers,
utilities  and  others  to wholesale customers as more fully described
below.
     In April 1996, the FERC issued its Final Rule on Open Access Non-
discriminatory  Transmission,  Stranded  Costs,  Open Access Same-time
Information  System (OASIS) and Standards of Conduct. These rules work
together  to  open  access  for  wholesale power flows on transmission
systems.  Utilities  owning  transmission  facilities (including Tampa
Electric)  are  required to provide services to wholesale transmission

                                   5


customers comparable to those they provide to themselves on comparable
terms  and  conditions  including price. Among other things, the rules
require  transmission  services  to  be unbundled from power sales and
owners  of  transmission  systems must take transmission service under
their own transmission tariffs.
     Transmission  system  owners  are  also  required to implement an
OASIS  system  providing,  via  the  Internet,  access to transmission
service  information  (including  price and availability), and to rely
exclusively  on  their  own  OASIS  system  for  such  information for
purposes  of  their  own  wholesale  power transactions. To facilitate
compliance,  owners must implement Standards of Conduct to ensure that
personnel  involved  in  marketing  wholesale  power  are functionally
separated   from  personnel  involved  in  transmission  services  and
reliability  functions. Tampa Electric, together with other utilities,
has  implemented an OASIS system and believes it is in compliance with
the Standards of Conduct.
     In  addition  to  these  transmission developments at the federal
level,  there  have  been initiatives at the state level to facilitate
the  construction  of  merchant  power  plants,  i.e.  plants built on
speculation  with  a  portion  or all of their capacity not subject to
purchase  agreements.  Tampa  Electric  has opposed these efforts. See
Wholesale Power Market on pages 46 and 47 for a further description of
proposed projects and the issues involved.

Fuel

     About 97 percent of Tampa Electric's generation for 1998 was from
its coal-fired units. About the same level is anticipated for 1999.
     Tampa  Electric's average delivered fuel cost per million BTU and
average delivered cost per ton of coal burned have been as follows:

Average cost
 per million BTU:         1998    1997    1996    1995    1994

Coal                    $ 1.99  $ 1.97  $ 2.01  $ 2.15  $ 2.22
Oil                     $ 3.14  $ 3.76  $ 3.68  $ 2.76  $ 2.49
Composite               $ 2.03  $ 2.01  $ 2.05  $ 2.16  $ 2.22
Average cost per ton 
 of coal burned         $44.44  $44.50  $46.71  $50.97  $53.39

     Tampa  Electric's  generating  stations  burn  fuels  as follows:
Gannon  Station  burns  low-sulfur  coal;  Big  Bend  Station  burns a
combination  of  low-sulfur  coal and coal of a somewhat higher sulfur
content;  Polk  Power Station burns high-sulfur coal which is gasified
subject  to  sulfur removal prior to combustion; Hookers Point Station
burns  low-sulfur oil; Phillips Station burns oil of a somewhat higher
sulfur content; and Dinner Lake Station, which was placed on long-term
reserve standby in March 1994, burned natural gas and oil. 
     Coal.  Tampa Electric used approximately 7.9 million tons of coal
during  1998 and estimates that its coal consumption will be about 8.1
m i llion  tons  for  1999.  During  1998,  Tampa  Electric  purchased
approximately  41  percent  of its coal under long-term contracts with
six  suppliers, including TECO Coal, and 59 percent of its coal in the
spot  market  or  under intermediate-term purchase agreements. About 9
percent  of  Tampa  Electric's 1998 coal requirements were supplied by
TECO  Coal.  During  December 1998, the average delivered cost of coal
(including  transportation)  was  $41.37 per ton, or $1.78 per million
BTU.  Tampa Electric expects to obtain approximately 31 percent of its

                                   6


coal   requirements  in  1999  under  long-term  contracts  with  five
suppliers,  including  TECO  Coal, and the remaining 69 percent in the
spot  market  or  under  intermediate-term  purchase agreements. Tampa
Electric  estimates that about 7 percent of its 1999 coal requirements
will  be  supplied  by  TECO  Coal.  Tampa  Electric's  long-term coal
contracts  provide  for revisions in the base price to reflect changes
in  a  wide  range  of cost factors and for suspension or reduction of
deliveries  if environmental regulations should prevent Tampa Electric
from  burning the coal supplied, provided that a good faith effort has
been  made  to  continue burning such coal. For information concerning
transportation  services  and sales of coal by affiliated companies to
Tampa Electric, see TECO Transport on pages 13 and 14 and TECO Coal on
pages 14 and 15.
     In  1998,  about  66  percent of Tampa Electric's coal supply was
deep-mined,   approximately  32  percent  was  surface-mined  and  the
remainder    was  a  processed oil by-product known as petroleum coke.
Federal  surface-mining laws and regulations have not had any material
adverse  impact  on  Tampa  Electric's  coal  supply or results of its
operations.  Tampa Electric, however, cannot predict the effect on the
market  price  of  coal  of  any  future  mining laws and regulations.
Although  there  are  reserves  of  surface-mineable coal dedicated by
suppliers  to  Tampa Electric's account, high-quality coal reserves in
Kentucky that can be economically surface-mined are being depleted and
in the future more coal will be deep-mined. This trend is not expected
to result in any significant additional costs to Tampa Electric.
     Oil.  Tampa  Electric had supply agreements through Dec. 31, 1998
for  No. 2 fuel oil and No. 6 fuel oil for its Polk, Hookers Point and
Phillips  stations,  and  its  four combustion turbine units at prices
based on Gulf Coast Cargo spot prices. Contracts for the supply of No.
2  and  No.  6  fuel  oil  through  Dec.  31,  1999 are expected to be
finalized in early 1999. The price for No. 2 fuel oil deliveries taken
in  December 1998 was $16.17 per barrel, or $2.79 per million BTU. The
price  for No. 6 fuel oil deliveries taken in December 1998 was $14.42
per barrel, or $2.28 per million BTU.

Franchises

     Tampa  Electric  holds franchises and other rights that, together
with  its  charter  powers,  give it the right to carry  on its retail
business  in  the localities it serves. The franchises are irrevocable
and  are  not  subject  to  amendment  without  the  consent  of Tampa
Electric, although, in certain events, they are subject to forfeiture.
     Florida municipalities are prohibited from granting any franchise
for  a  term  exceeding  30  years. If a franchise is not renewed by a
municipality,  the  franchisee  has the statutory right to require the
municipality  to purchase any and all property used in connection with
the  franchise at a valuation to be fixed by arbitration. In addition,
all  of  the  municipalities except for the cities of Tampa and Winter
Haven  have  reserved  the right to purchase Tampa Electric's property
used  in  the  exercise  of  its  franchise,  if  the franchise is not
renewed.
     Tampa  Electric  has  franchise  agreements  with 13 incorporated
municipalities  within  its retail service area. These agreements have
various expiration dates ranging from December 2005 to September 2021.
Tampa  Electric  has no reason to believe that any of these franchises
will not be renewed.
     Franchise  fees  payable  by  Tampa Electric, which totaled $20.9
million  in  1998,  are  calculated using a formula based primarily on

                                   7


electric revenues. 
     Utility  operations  in  Hillsborough,  Pasco,  Pinellas and Polk
Counties  outside of incorporated municipalities are conducted in each
case  under one or more permits to use county rights-of-way granted by
the  county  commissioners  of such counties. There is no law limiting
the  time for which such permits may be granted by counties. There are
no  fixed  expiration  dates  for the Hillsborough County and Pinellas
County  agreements.  The  agreements  covering  electric operations in
Pasco and Polk counties expire in 2033 and 2005.

Environmental Matters

     Tampa  Electric's  operations  are  subject  to county, state and
f e deral   environmental   regulations.   The   Hillsborough   County
Environmental  Protection  Commission  and  the  Florida Environmental
Regulation  Commission  are responsible for promulgating environmental
regulations  and  coordinating  most  of  the environmental regulation
functions  performed  by  the various departments of state government.
T h e   Florida  Department  of  Environmental  Protection  (FDEP)  is
responsible  for  the  administration  and  enforcement  of  the state
regulations.  The  U.S.  Environmental  Protection Agency (EPA) is the
primary federal agency with environmental responsibility.
     Tampa  Electric  believes  that it has all required environmental
permits.  In  addition,    monitoring  programs are in place to assure
compliance with permit conditions. 
     Tampa  Electric  has been identified as a potentially responsible
party  (PRP)  for  certain  superfund  sites. While the total costs of
remediation  at  these sites may be significant, Tampa Electric shares
potential  liability  with  other PRPs, many of which have substantial
assets.  Accordingly,  Tampa  Electric  expects  that its liability in
connection with these sites will not be significant. The environmental
remediation costs associated with these sites are not expected to have
a material impact on customer prices.
     The  U.S.  Environmental Protection Agency (EPA) has commenced an
investigation  of  coal-fired electric power generators under the 1990
C l ean  Air  Act  Amendments  (CAAA)  to  determine  compliance  with
e n v ironmental  permitting  requirements  associated  with  repairs,
m a intenance,  modifications  and  operations  changes  made  to  the
facilities  over  the  years. The EPA's focus is on whether new source
p e r formance  standards  should  be  applied  to  the  changes  and,
accordingly,  whether  the  best  available  control technology was or
should  have  been  used.  Tampa  Electric  is one of several electric
utilities  that  have  been  visited  by  EPA personnel and received a
comprehensive request for information pursuant to Section 114 of EPA's
Clean  Air  Act  regulations. Tampa Electric is furnishing appropriate
information.  It  believes  that it has built, maintained and operated
its  facilities  in  compliance with relevant environmental permitting
requirements.  The  timing  of completion and the outcome of the EPA s
investigation are uncertain.
     Expenditures.  During  the  five years ended Dec. 31, 1998, Tampa
E l e c tric  spent  $172.1  million  on  capital  additions  to  meet
environmental  requirements,  including  $108.2  million  for the Polk
Power  Station  project.  Environmental  expenditures are estimated at
$9.9 million for 1999 and $8.8 million in total for 2000 through 2003.
These  totals  exclude  amounts  required  to comply with the CAAA, as
discussed in the following paragraphs.
     Tampa Electric is complying with the Phase I emission limitations
imposed  by  the  CAAA  which  became  effective Jan. 1, 1995 by using

                                   8


b l e nds  of  lower-sulfur  coal,  controlling  stack  emissions  and
purchasing emission allowances. 
     In 1998, Tampa Electric decided to add a flue gas desulfurization
(FGD)  system,  or "scrubber," in order to comply with Phase II of the
CAAA.  The  $83-million  scrubber  will  reduce  the  amount of sulfur
dioxide  emitted  by  Tampa  Electric's Big Bend Units One and Two and
will  allow significant fuel savings at other Tampa Electric units. As
a  result of this project, all of the units at Big Bend Station, Tampa
Electric's  largest generating station, will be equipped with scrubber
technology.  Tampa  Electric  spent  approximately $16 million on this
project  in  1998  and  estimates capital expenditures related to this
scrubber to be $61 million in 1999 and $6 million thereafter. 
     The  FPSC  approved  the  FGD  system  as the most cost effective
a l t e rnative  for  Tampa  Electric  to  meet  its  CAAA  compliance
requirements  and the recovery of prudently incurred costs through the
environmental  cost  recovery  clause.  Cost  recovery will not begin,
however,  until  the  FGD  system is in service and Tampa Electric has
applied for such recovery specifying the costs actually incurred.
     Tampa  Electric  may  petition  the  FPSC for recovery of certain
other  environmental compliance costs on a current basis pursuant to a
statutory  environmental  cost  recovery  procedure used in connection
with the above described FGD system.
     In  1998,  Tampa Electric recovered $5.4 million of environmental
compliance costs through the environmental cost recovery clause. These
were  costs incurred by Tampa Electric after April 1993 to comply with
environmental  regulations  that were not included in the then current
base  rates.  In  addition,  Tampa  Electric may recover environmental
compliance  costs through base rates. Under the October 1996 agreement
with the FPSC, the earliest any new prices could be in effect to cover
such costs is in the year 2000.

PEOPLES GAS SYSTEM--Gas Operations

     Peoples  Gas  System,  Inc.  and West Florida Natural Gas Company
were  acquired  by  TECO  Energy  in  June 1997 and now operate as the
Peoples  Gas System division of Tampa Electric Company. PGS is engaged
in  the  purchase,  distribution  and  marketing  of  natural  gas for
residential,  commercial,  industrial  and  electric  power generation
customers in the State of Florida.
     PGS  has  no gas reserves, but relies on two interstate pipelines
to deliver gas to it for sale or other delivery to customers connected
to its distribution system. PGS does not engage in the exploration for
or  production  of  natural gas. Currently, PGS operates a natural gas
distribution  system  that serves approximately 240,000 customers. The
system  includes  approximately  7,300  miles  of mains and over 4,800
miles of service lines.
     In  1998,  industrial  and  power  generation  customers consumed
approximately  65  percent  of  PGS'  annual  therm volume. Commercial
customers  used  approximately 29 percent with the balance consumed by
residential customers.
     While  the  residential market represents only a small percentage
of  total  therm  volume, residential operations generally comprise 24
p e r c ent  of  total  revenues.  New  residential  construction  and
conversions  of  existing  residences  to  gas have steadily increased
since the late 1980's.
     Natural  gas  has  historically  been  used  in  many traditional
industrial  and  commercial  operations  throughout Florida, including
production  of  products  such  as steel, glass, ceramic tile and food

                                   9


products.  Gas  climate  control  technology  is  expanding throughout
F l orida,  and  commercial/industrial  customers  including  schools,
hospitals,  office  complexes  and  churches  are  utilizing  this new
technology.
     Within the PGS operating territory, large cogeneration facilities
utilize  gas technology in the production of electric power and steam.
Over  the  past  three years, the company has transported, on average,
a b o ut  300  million  therms  annually  to  facilities  involved  in
cogeneration.

Revenues for PGS for the years ended Dec. 31, are as follows:     

(millions)                   1998      1997      1996
Residential                $ 57.7    $ 56.3    $ 51.6
Commercial                  141.2     138.9     141.3
Industrial                   20.9      23.2      30.9
Power Generation             10.4      11.7      12.4
Other revenues               22.6      19.5      22.5
Total                      $252.8    $249.6    $258.7

     PGS  had  897  employees  as  of  Dec.  31,  1998. A total of 128
employees   in  six  of  the  company's  13  operating  divisions  are
represented by various union organizations.

Regulation

     The operations of PGS are regulated by the FPSC separate from the
regulation  of  Tampa  Electric's  electric  operations.  The FPSC has
jurisdiction  over  rates,  service,  issuance  of certain securities,
safety, accounting and depreciation practices and other matters.
     In  general, the FPSC sets rates at a level that allows a utility
such  as PGS to collect total revenues (revenue requirements) equal to
its  cost  of  providing  service,  including  a  reasonable return on
invested capital.
     The  basic  costs,  other  than  the  costs  of purchased gas and
interstate  pipeline  capacity,  of  providing natural gas service are
recovered  through base rates, which are designed to recover the costs
of  owning,  operating and maintaining the utility system. The rate of
return  on  rate  base, which is intended to approximate PGS' weighted
cost of capital, primarily includes its cost for debt, deferred income
taxes  at  a  zero  cost rate, and an allowed return on common equity.
Base  prices  are  determined  in  FPSC  proceedings  which  occur  at
irregular  intervals  at  the  initiative  of  PGS,  the FPSC or other
parties.
     PGS recovers the charges (both reservation and usage) it pays for
transportation  of  gas  for  system  supply through the purchased gas
adjustment  charge.  This  charge  is  designed  to  recover the costs
incurred  by  PGS  for  purchased  gas,  and  for  holding  and  using
interstate pipeline capacity for the transportation of gas it sells to
its  customers.  These  charges,  which  are reset annually in an FPSC
hearing,  are  based  on estimated costs of purchased gas and pipeline
capacity, and estimated customer usage for a specific recovery period,
with  a true-up adjustment to reflect the variance of actual costs and
usage from the projected charges for prior periods.
     In addition to its base rates and purchased gas adjustment clause
c h a r g es  for  system  supply  customers,  PGS  customers  (except
interruptible  customers)  also  pay  a  per-therm  charge for all gas
consumed  to  recover  the costs incurred by the company in developing

                                  10


and  implementing  energy conservation programs, which are mandated by
Florida  law and approved and supervised by the FPSC. PGS is permitted
to  recover,  on  a  dollar-for-dollar  basis,  expenditures  made  in
connection  with  these  programs if it demonstrates that the programs
are cost effective for its ratepayers.
     In June 1996, following informal workshops held in late 1995, the
FPSC  initiated  a  proceeding  for  the  purpose of investigating the
unbundling  of  natural  gas  services provided by PGS and other local
distribution companies subject to the FPSC's regulatory jurisdiction. 
     In September 1998, the FPSC staff circulated a proposed rule that
would  require  natural  gas  utilities  to  offer transportation-only
service  to  all non-residential customers. The proposed rule is vague
and  does not prescribe any method for achieving this requirement. PGS
believes  a  generic  rule is unnecessary and is opposed to this broad
proposal. The rulemaking process is expected to last anywhere from six
months  to  in  excess of a year. It is unclear whether the FPSC staff
action  will  lead  to  FPSC  adoption  of  a  rule  requiring further
unbundling.
     Under  a separate docket, in February 1999, the FPSC approved PGS
petition  to  expand  for a two-year period its existing, experimental
unbundling  program  to  a maximum of 1,000 customers from the current
170  customers  for  two  years.    This  program,  known  as the Firm
Transportation  Aggregation  (FTA)  program,  advances  the unbundling
initiative  being  pursued  by the FPSC Staff, but contemplates a more
reasonable  pace  toward  total  unbundled  service to non-residential
customers. 
     In  addition to economic regulation, PGS is subject to the FPSC's
safety   jurisdiction,  pursuant  to  which  the  FPSC  regulates  the
construction,  operation  and maintenance of PGS' distribution system.
In  general,  the  FPSC  has  implemented this by adopting the Minimum
Federal  Safety  Standards  and  reporting  requirements  for pipeline
facilities and transportation of gas prescribed by the U.S. Department
of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal
Regulations.
     PGS  is  also  subject  to Federal, state and local environmental
laws  and  regulations  pertaining to air and water quality, land use,
noise and aesthetics, solid waste and other environmental matters.

Competition

     PGS  is  not  in  direct  competition  with  any  other regulated
distributors of natural gas for customers within its service areas. At
the  present  time,  the principal form of competition for residential
and  small  commercial  customers  is  from  companies providing other
sources  of energy and energy services including fuel oil, electricity
and in some cases liquid propane gas.  PGS has taken actions to retain
and  expand  its  commodity  and  transportation  business,  including
managing costs and providing high quality service to customers.
     Competition  is  most  prevalent  in  the  large  commercial  and
industrial  markets.  In recent years, these classes of customers have
been  targeted  by  competing  companies  seeking to sell gas directly
either   using  PGS  facilities  or  transporting  gas  through  other
f a c i lities,  thereby  bypassing  PGS  facilities.  Many  of  these
competitors are larger natural gas marketers with a national presence.
The  FPSC  has allowed PGS to adjust rates to meet competition for the
largest interruptible customers.

Gas Supplies

                                  11


     PGS  purchases  gas from various suppliers depending on the needs
of its customers.  The gas is delivered to the PGS distribution system
for  further  delivery  by PGS to its customers through two interstate
pipelines on which PGS has reserved firm transportation capacity.
     Gas  is  delivered by Florida Gas Transmission (FGT) through more
than  40  interconnections  (gate  stations)  serving  PGS'  operating
divisions.  In  addition,  PGS'  Jacksonville  Division  receives  gas
delivered  by  the  South  Georgia Natural Gas Company (South Georgia)
pipeline through a gate station located northwest of Jacksonville.
     Companies  with  firm  pipeline  capacity  receive  priority  in
scheduling  deliveries  during times when the pipeline is operating at
its  maximum capacity. PGS presently holds sufficient firm capacity to
permit  it  to  meet  the  gas  requirements  of  its system commodity
customers  except  during  localized  emergencies  affecting  the  PGS
d i s tribution  system,  and  on  extremely  cold  days,  which  have
historically been rare in Florida.
     Firm  transportation rights on an interstate pipeline represent a
right to use the amount of the capacity reserved for transportation of
gas, on any given day. PGS pays reservation charges on the full amount
of the reserved capacity whether or not it actually uses such capacity
on  any  given  day.  When  the  capacity is actually used, PGS pays a
volumetrically  based  usage  charge  for  the  amount of the capacity
actually  used.  The  levels  of the reservation and usage charges are
regulated  by FERC. PGS actively markets any excess capacity available
on  a day to day basis to partially offset costs recovered through the
Purchased Gas Adjustment Clause.
     PGS  procures  natural  gas  supplies  using  base load and swing
supply  contracts  distributed  among  various vendors along with spot
market  purchases.  Pricing  generally  takes  the  form  of  either a
variable  price  based on published indices, or a fixed price for  the
contract term.
     The  current supply portfolio consists of approximately 1 percent
spot  purchases,  17  percent swing purchases and 82 percent base load
purchases.
     PGS  has  one  long-term  supply  contract which expires in 2002.
This  long-term contract has approximately 58 million therms remaining
to  be purchased with a total cost of $12.7 million over the remaining
years.  The purchase price is $.22 per therm.
     Neither  PGS  nor  any of its interconnected interstate pipelines
has  storage  facilities in Florida. PGS occasionally faces situations
when  the  demands  of  all  of  its customers for the delivery of gas
cannot be met.  In these instances, it is necessary that PGS interrupt
or  curtail deliveries to its interruptible customers. In general, the
largest  of  PGS'  industrial customers are in the categories that are
first  curtailed  in  such  situations. PGS  tariff and transportation
agreements  with  these  customers  give PGS the right to divert these
customers    gas  to  other higher priority users during the period of
curtailment  or interruption. PGS pays these customers for such gas at
the  price  they  paid  their  suppliers (if purchased by the customer
under  a  contract  with  a  term  of  five  years or longer), or at a
published  index  price  (if  purchased  by the customer pursuant to a
contract  with  a  term less than five years), and in either case pays
t h e    c u stomer  for  charges  incurred  for  interstate  pipeline
transportation to the PGS system.





                                  12


Franchises

     PGS  holds  franchise  and  other  rights  with 89 municipalities
within  its  service  area.  These include the cities of Jacksonville,
Daytona  Beach,  Eustis,  Orlando,  Lakeland,  Tampa,  St. Petersburg,
Bradenton,  Sarasota,  Avon  Park,  Frostproof,  Palm  Beach  Gardens,
Pompano  Beach,  Fort Lauderdale, Hollywood, North Miami, Miami Beach,
Miami,  Panama  City  and  Ocala. These agreements give PGS a right to
operate within the franchise territory. The franchises are irrevocable
and  are not subject to amendment without the consent of PGS, although
in certain events, they are subject to forfeiture.
     Municipalities  are  prohibited from granting any franchise for a
term  exceeding  30  years.  If  a  franchise  is  not  renewed  by  a
municipality,  the  franchisee  has the statutory right to require the
municipalities  to  purchase  any  and all property used in connection
with  the  franchise  at  a  valuation  to be fixed by arbitration. In
addition,  several  of  the  municipalities have reserved the right to
purchase  PGS   property used in the exercise of its franchise, if the
franchise is not renewed.
     PGS    franchise  agreements with the incorporated municipalities
within  its  service  area  have various expiration dates ranging from
April 1999 through June 2028.
     In  January  1999,  the City of Lakeland notified PGS that it was
considering  exercising  its  right  to  purchase PGS  property in the
Lakeland  franchise area when its franchise agreement with PGS expires
in  March  2000. PGS serves approximately 5,000 customers in Lakeland.
PGS  has commenced discussions with the City of Lakeland to renew this
agreement.  While  PGS  believes  it  is  best  suited  to serve these
customers,  it  cannot  at  this  time predict the ultimate outcome of
these activities.
     PGS  has  no  reason  to believe that any of its other franchises
will not be renewed.
     Franchise  fees  payable  by  PGS,  which totaled $7.9 million in
1 9 9 8,  are  calculated  using  various  formulas  which  are  based
principally on natural gas revenues. Franchise fees are collected from
only those customers within each franchise area.
     U t ility   operations   in   areas   outside   of   incorporated
municipalities are conducted in each case under one or more permits to
use  county  rights-of-way granted by the county commissioners of such
counties. There is no law limiting the time for which such permits may
be  granted by counties. There are no fixed expiration dates and these
rights are, therefore, considered perpetual.

Environmental Matters

     PGS's   operations  are  subject  to  federal,  state  and  local
statutes, rules and regulations relating to the discharge of materials
into  the  environment and the protection of the environment generally
that  require  monitoring,  permitting and ongoing expenditures. These
expenditures  have  not been significant in the past, but the trend is
toward  stricter  standards,  greater  regulation  and  more extensive
permitting requirements.
     PGS  has  been  identified as a potentially responsible party for
certain  former  manufactured  gas  plant sites. The joint and several
liability  associated  with  these  sites  presents  the potential for
significant  response  costs;  PGS  estimates  its  ultimate financial
liability  at  approximately  $20  million  over the next 10 years. To
date, PGS has been permitted by the FPSC to recover prudently incurred

                                  13


costs  of  environmental remediation and cleanup associated with these
manufactured gas sites. The environmental remediation costs associated
with  these  sites  are  not  expected  to  have  a material impact on
customer prices.
     PGS believes that it is in substantial compliance with applicable
environmental  laws,  regulations,  orders and rules. It is allowed to
recover  certain  prudently incurred environmental costs through rates
charged to its customers.
     Expenditures.  During the five years ended Dec. 31, 1998, PGS has
not  incurred  any  material  capital  additions to meet environmental
requirements, nor are any anticipated for 1999 through 2003.

TECO TRANSPORT

     TECO  Transport owns all of the common stock of four subsidiaries
w h ich  transport,  store  and  transfer  coal  and  other  dry  bulk
commodities. TECO Transport currently owns no operating assets. 
     TECO  Transport  and  its  subsidiaries had 1,139 employees as of
Dec. 31, 1998.
     All of TECO Transport's subsidiaries perform substantial services
for  Tampa  Electric.  In  1998,  approximately  51  percent  of  TECO
Transport's  revenues  were  from third-party customers and 49 percent
were  from  Tampa Electric. The pricing for services performed by TECO
Transport's operating companies for Tampa Electric is based on a fixed
price  per  ton,  adjusted  quarterly  for changes in certain fuel and
price  indices. Most of the third-party utilization of the ocean-going
b a r ges  is  for  domestic  phosphate  movements  and  domestic  and
international  movements  of  other  dry  bulk  commodities.  Both the
terminal  and  river transport operations handle a variety of dry bulk
commodities for third-party customers.
     A  substantial  portion of TECO Transport's business is dependent
upon  Tampa  Electric, industrial phosphate customers, export coal and
g r ain  customers,  and  participation  in  the  U.S.  Department  of
Agriculture cargo preference program. 
     TECO  Transport's barge subsidiaries consist of Gulfcoast Transit
Company  (Gulfcoast),  which transports products in the Gulf of Mexico
and   worldwide,  and  Mid-South  Towing  Company  (Mid-South),  which
operates  on  the Mississippi, Ohio and Illinois rivers. Their primary
competitors  are  other  barge and shipping lines and railroads with a
number  of  other  companies  offering  transportation services on the
waterways used by TECO Transport's subsidiaries. To date, physical and
technological  improvements  have  allowed barge operators to maintain
competitive  rate  structures  with  alternate methods of transporting
bulk commodities when the origin and destination of such shipments are
contiguous to navigable waterways.
     Electro-Coal Transfer Corporation (Electro-Coal) operates a major
transfer  and  storage  terminal on the Mississippi River south of New
Orleans.  Demand  for  the  use  of  such  terminals is dependent upon
customers'  use  of  water  transportation  versus  alternate means of
moving   bulk  commodities  and  the  demand  for  these  commodities.
Competition  consists  primarily  of  mid-stream operators and another
land-based terminal located nearby.
     The  business of TECO Transport's subsidiaries, taken as a whole,
is not subject to significant seasonal fluctuation.
     The   Interstate  Commerce  Act  exempts  from  regulation  water
t r ansportation  of  certain  dry  bulk  commodities.  In  1998,  all
transportation services provided by TECO Transport's subsidiaries were
within this exemption.

                                  14


     TECO  Transport's subsidiaries are also subject to the provisions
of  the  Clean  Water Act of 1977 which authorizes the Coast Guard and
t h e  EPA  to  assess  penalties  for  oil  and  hazardous  substance
discharges.  Under  this  Act,  these  agencies  are also empowered to
assess  clean-up costs for such discharges. TECO Transport believes it
is  in  substantial  compliance  with  applicable  environmental laws,
regulations,  orders  and  rules.  In  1998,  TECO Transport spent $.8
million  for  environmental compliance. Environmental expenditures are
estimated  at  $.7  million in 1999, primarily for work on solid waste
disposal  and  storm  water  drainage  at the Electro-Coal facility in
Louisiana  and for expenses related to oil and bilge water disposal at
its river-barge repair facility in Illinois.

TECO COAL

     TECO  Coal  owns  no operating assets but holds all of the common
stock  of  Gatliff  Coal Company (Gatliff), Rich Mountain Coal Company
( R ich  Mountain),  Clintwood  Elkhorn  Mining  Company  (Clintwood),
Pike-Letcher  Land  Company  (Pike-Letcher)  and  Premier Elkhorn Coal
Company  (Premier).  TECO  Coal's subsidiaries own mineral rights, and
own  or  operate surface and underground mines and coal processing and
loading facilities in Kentucky and Tennessee. 
     TECO  Coal  and its subsidiaries had 315 employees as of Dec. 31,
1998.
     In  1998,  TECO  Coal subsidiaries sold 6.8 million tons of coal,
with  approximately  89  percent  sold to third parties and 11 percent
sold  to Tampa Electric. Tampa Electric is reducing its coal purchases
from  TECO  Coal  as  a  result of its efforts to reduce costs and its
successful  increased  use  of  conventional  steam  coal  from  other
sources.  TECO  Coal  expects increased sales volumes to other parties
from  the  Premier  and  Clintwood  operations to offset the impact on
operating  results of lower sales to Tampa Electric in 1999. The Tampa
Electric  contract  with TECO Coal expires at the end of 1999 and will
not be renewed.
     Rich  Mountain  has  no reserves; it mines coal reserves owned by
Gatliff.
     Primary  competitors  of  TECO Coal's subsidiaries are other coal
suppliers,  many  of which are located in Central Appalachia. To date,
TECO  Coal  has  been  able  to compete for coal sales by mining high-
quality    steam  and  specialty  coals  and  by  effectively managing
production and processing costs.
     The  operations  of  underground  mines,  including  all  related
surface  facilities,  are  subject to the Federal Coal Mine Safety and
Health  Act  of  1977.  TECO  Coal's  subsidiaries are also subject to
various  Kentucky  and Tennessee mining laws which require approval of
roof  control,  ventilation, dust control and other facets of the coal
mining  business.  Federal  and  state inspectors inspect the mines to
ensure  compliance  with  these  laws.  TECO  Coal  believes  it is in
substantial  compliance  with the standards of the various enforcement
agencies.  It  is  unaware  of any mining laws or regulations having a
prospective  effective  date  that  would materially affect the market
price of coal sold by its subsidiaries.
     TECO  Coal's  subsidiaries  are subject to various federal, state
a n d  local  air  and  water  pollution  standards  in  their  mining
o p e rations.  In  1998  approximately  $1.5  million  was  spent  on
environmental  protection  and reclamation programs. TECO Coal expects
to spend a similar amount in 1999 on these programs.
     The coal mining operations are also subject to the Surface Mining

                                  15


Control  and Reclamation Act of 1977 which places a charge of $.15 and
$.35  on  every  net  ton  mined  of  underground  and  surface  coal,
respectively, to create a fund for reclaiming land and water adversely
affected by past coal mining. Other provisions establish standards for
the  control  of environmental effects and reclamation of surface coal
mining  and  the  surface  effects  of  underground  coal  mining, and
requirements for federal and state inspections.

TECO POWER SERVICES

     TECO Power Services (TPS) has subsidiaries that have interests in
i n dependent  power  projects  in  Florida  and  Guatemala,  and  has
investments  in unconsolidated affiliated entities that participate in
independent  power  projects in other parts of the U.S. and the world.
It had 88 employees as of Dec. 31, 1998.
     There are a number of companies competing with TPS for investment
opportunities  in the U.S. and worldwide. Several of these competitors
are  larger  and  have access to more resources. To date, TPS has been
a b l e  to  compete  effectively  for  independent  power  investment
opportunities  based  on  its  success in developing independent power
projects  in  the  U.S.  and  in  Guatemala, and its associations with
experienced partners.
     Hardee  Power  Partners  Ltd.  (Hardee  Power), a Florida limited
partnership  whose  general  and  limited  partners  are  wholly owned
subsidiaries  of  TPS,  owns  the Hardee Power Station, a 295-megawatt
combined  cycle electric generating facility located in Hardee County,
Florida,  which  began  commercial  operation  on Jan. 1, 1993. Hardee
Power  has  20-year  power supply agreements, which began in 1993, for
all  of  the  capacity  and  energy  of  the Hardee Power Station with
Seminole  Electric Cooperative (Seminole Electric), a Florida electric
cooperative  that provides wholesale power to 10 electric distribution
cooperatives,  and  with  Tampa  Electric. Under the Seminole Electric
agreement, Hardee Power has agreed to supply Seminole Electric with an
additional  145 megawatts of capacity during the first 10 years of the
contract,  which it is purchasing from Tampa Electric's coal-fired Big
Bend Unit Four for resale to Seminole Electric.
     The  Hardee  Power Station is fueled by natural gas or No. 2 fuel
oil.  In  April 1998, TPS signed a contract with PGS for the supply of
natural  gas to the station until 2000. About 99 percent of the Hardee
Power Station's generation for 1998 was from natural gas. 
     Hardee  Power's  average  fuel  cost  per million BTU has been as
follows:

     Average cost 
      per million BTU:    1998    1997    1996    1995    1994

     Oil                 $4.21   $4.73  $ 4.61  $ 4.64  $ 3.68
     Gas                 $2.46   $2.90  $ 3.60  $ 2.70  $ 2.02
     Composite           $2.48   $3.15  $ 3.65  $ 2.71  $ 2.40

     The  price  for natural gas deliveries taken in December 1998 was
$2.21 per thousand cubic feet, or $2.09 per million BTU. The price for
fuel  oil  deliveries taken in November 1998 was $20.62 per barrel, or
$3.539  per  million  BTU.  There were no fuel oil deliveries taken in
1998 subsequent to that date.
     Through  its  ownership  and  operation of a wholesale generating
facility  in the U.S., TECO Power Services is subject to regulation by
the  FERC  in  various  respects.  Depending  upon  the  nature of the

                                  16


project,  FERC  may regulate, among other things, the rates, terms and
conditions for the sale of electric capacity and energy.
     Like  Tampa  Electric, the U.S. operations of TECO Power Services
are  subject  to  federal,  state  and  local  environmental  laws and
regulations  covering  air  quality,  water  quality,  land use, power
plant,  substation and transmission line siting, noise and aesthetics,
solid waste and other environmental matters.
     Tampa  Centro  Americana  de  Electricidad,  Limitada  (TCAE), an
entity  96.06-percent  owned by TPS Guatemala One, Inc. (TPS Guatemala
One),  a  subsidiary  of  TECO  Power  Services,  has  a  U.S. dollar-
denominated  power sales agreement to provide 78 megawatts of capacity
to  an  electric  utility  in Guatemala for a 15-year period ending in
2010.  The  project  (the  Alborada  Power  Station)  consists  of two
combustion  turbines  built  at  a  total  cost  of  approximately $50
million.  TECO  Power  Services  has obtained political risk insurance
from  the Overseas Private Investment Corporation (OPIC), an agency of
the  U.S. government, for currency inconvertibility, expropriation and
political  violence covering up to 90 percent of its equity investment
and  economic  returns.  In  January  1997,  TECO  Power Services also
secured  $29  million  of  limited-recourse financing for the Alborada
Power Station from OPIC.
     TCAE  began commercial operation of the Alborada Power Station on
Sept.  14,  1995. The power sales agreement between TCAE and the power
purchaser,  Empresa Electrica de Guatemala, S.A. (EEGSA), provides for
a capacity charge and operations and maintenance expense payments. The
capacity  charge is subject to adjustment due to output, heat rate and
availability.  EEGSA  is  responsible  for  providing the fuel for the
p l a nt  with  TECO  Power  Services  providing  assistance  in  fuel
administration.
     EEGSA,  a  private  distribution and generation company formed in
1894,  serves  more  than 530,000 customers. EEGSA s service territory
includes the capital of Guatemala, Guatemala City.
     In  1996,  Central Generadora Electrica San Jose, SRL (CGESJ), an
entity  in  which  a  TECO  Power  Services affiliate has a 46 percent
ownership  interest,  signed  a  U.S.-dollar  denominated  power sales
agreement with EEGSA to provide 120 megawatts of capacity for 15 years
beginning  in  2000.  The project consists of a single unit pulverized
coal  baseload  facility  (San  Jose  Power  Station)  including  port
modifications  to  accommodate the importation of coal. The total cost
of  the  project  is  estimated  at $181 million. At Dec. 31, 1998, 46
percent  of CGESJ was owned by another U.S. independent power producer
(a  subsidiary  of The Coastal Corporation) and 8 percent was owned by
the  same Guatemalan business group that TECO Power Services partnered
with  for  the  Alborada Power Station project. The U.S. partners have
obtained  political  risk  insurance  from  OPIC for inconvertibility,
expropriation  and  political  violence  covering  up to 90 percent of
their  equity  investment and economic returns. The project entity has
obtained  construction financing, guaranteed by TPS and the other U.S.
owner.  Upon  the commencement of commercial operation of the San Jose
Power  Station  in  2000, the construction financing is expected to be
converted to limited-recourse debt.
     In  September 1998, a consortium that includes TPS, Iberdrola, an
electric  utility in Spain, and Electricidade de Portugal, an electric
utility in Portugal, completed the purchase of an 80 percent ownership
interest  in  EEGSA. TPS owns a 30 percent interest in this consortium
and  contributed $100 million in equity. The total purchase price paid
by  the  consortium was $520 million. The consortium obtained limited-
recourse debt financing for a portion of the purchase price.

                                  17


     In August 1998, TPS and Mosbacher Power Partners, Ltd. (Mosbacher
Power),  an independent power company headquartered in Houston, agreed
to  jointly  develop,  own  and  operate  domestic  and  international
independent  power  projects.  Under this arrangement, TPS will, among
other things, provide capital and technical expertise to Mosbacher and
g a i n    a n  expanded  domestic  and  international  presence  with
opportunities  for project returns, including preferred returns before
benefits are shared. 
     In  October  1998, TPS, through the Mosbacher Power joint venture
discussed above, acquired an interest in a repowered independent power
project  in  the Czech Republic. The TPS/Mosbacher Power joint venture
entity, Nations Energy Corp., NRG Energy, El Paso Energy International
a n d    S tredoceske  Energeticke  Zavody  (STE),  a  Czech  regional
distribution  company,  are owners of the project. The facility, after
planned expansion, will have a net total capacity of 344 megawatts and
is scheduled to go in service during the fourth quarter of 1999.
     In  February  1999,  TPS formed a joint venture relationship with
Energia  Global  International,  Ltd.  (EGI),  a  Bermuda-based energy
development  firm.  EGI  owns  and  operates  electric  generation and
cogeneration  facilities in Central America with a particular emphasis
on  renewable  power  (i.e. hydro, geothermal, wind, biomass). It also
has  interests  in  electric distribution companies in El Salvador and
Panama.
     See  the  discussion  of  the  risks  inherent  in doing business
internationally in the Investment Considerations section on page 49.

TECO COALBED METHANE

     TECO  Coalbed  Methane  participates in the production of natural
gas  from  coalbeds  located  in  Alabama's  Black Warrior Basin. TECO
Coalbed Methane has invested $210 million as the principal investor in
three  ventures which control, in the aggregate, approximately 100,000
acres  of lease holdings. At the end of 1998, TECO Coalbed Methane had
interests  in  734  wells  that were operational and producing gas for
sale. These wells are operated by Energen Resources, a unit of Energen
Corporation,  and,  to  a  much  lesser  extent,  by other third-party
operators.
     A non-conventional fuel tax credit is available on all production
through  the  year  2002.  The tax credit escalates with inflation and
could be limited based upon domestic oil prices. In 1998, domestic oil
prices  would have had to exceed $49 per barrel for this limitation to
have been effective.
     All  production from these wells is committed for the life of the
reserves  based  on spot prices which are tied to the price of onshore
Louisiana gas.
     TECO  Coalbed  Methane s operations are subject to federal, state
and  local regulations for air emissions and water and waste disposal.
It  believes  its  operations  are  in substantial compliance with all
applicable environmental laws and regulations.

PEOPLES GAS COMPANY

     P e o p les  Gas  Company  (PGC)  is  engaged  in  the  purchase,
distribution and marketing of propane gas for residential, commercial,
and  industrial  customers  in  the  State of Florida. It possesses no
production  facilities  but  purchases propane gas from major national
suppliers.  In  1998,  PGC  had  54,500  customers and sold 31 million
gallons of propane.

                                  18


     In  1998,  PGC  acquired  three  additional  Florida  propane gas
businesses.  These  acquisitions  facilitated growth of PGC's existing
market  in  Jacksonville,  and  its  expansion  into  new  markets  in
Gainesville, Ocala, Fort Myers and Naples.
     Propane  gas  has  historically  been  used  in many residential,
industrial  and  commercial  operations  throughout Florida, including
production  of durable products such as steel, glass, ceramic tile and
food products.
     Propane is purchased under short-term contracts which enables PGC
to  make  purchases  at  prevailing  market  prices.  During 1997, PGC
entered  into options contracts to limit the exposure to propane price
increases;  these  contracts  expired  in  early 1998, and PGC did not
enter into any additional options contracts. PGC may employ similar or
other price management strategies in the future.
     PGC  purchases  propane  from  a  small  number of major national
suppliers.  The company has storage capacity  in excess of one million
gallons,  mostly  in  South  and  Central Florida. Delivery of propane
product  to  PGC  storage  facilities  is  primarily via rail cars and
tanker  trucks.  PGC  owns rail cars and tanker trucks used throughout
the northern and northeastern markets in Florida. Propane is delivered
to  PGC's  storage  facilities throughout the central and southeastern
parts  of  the  State  by  trucks  and  railcars controlled by a major
propane supplier.      
     The  majority  of  PGC  s  propane  is  delivered  into tanks and
containers  on  the  customer's  premises  via  bulk  delivery trucks.
Propane  block  systems  are  also  an  integral part of the company's
propane  distribution  operations  in  the  residential  market. Large
industrial  and  commercial  customers  often  take delivery in tanker
trucks directly from the supply terminals.
     In  the  Florida  propane  market, there are over 30 distributors
competing  within  the residential and commercial markets. Competition
in  Florida  ranges  from  a  number  of  large, national companies to
numerous   local,  independent  operators.  The  primary  focus  among
distributors  is  to  gain  market  share  through new customer growth
(i.e.,  providing  service for home construction).  PGC, presently the
largest   independent  propane  distributor  in  Florida,  expects  to
increase   its  customers  and  volumes  through  increased  marketing
activity and acquisitions. Propane competes directly with natural gas,
electricity and fuel oil, and its marketing areas are not limited by a
pipeline infrastructure.

TECO GAS SERVICES

     TECO  Gas  Services  (formerly  Gator Gas Marketing) provides gas
management  and  marketing services for large industrial customers. In
1998,  it  provided  gas management for three cogeneration facilities.
TECO Gas Services owns no operating assets.

TeCom

     TeCom  is  marketing  advanced  energy management, automation and
control systems for commercial and residential applications, named the
InterLane    systems.  Several  utilities  and  end-use operators have
purchased  products  from  TeCom  to  demonstrate,  test  and  use the
InterLane systems.
     Because   of  a  continued  high  level  of  product  enhancement
activity, TeCom capitalized $6.8 million pretax of product development
costs in 1998, $6.5 million in 1997 and $4.9 million in 1996. In 1998,

                                  19


TeCom  wrote  off  certain  product  development costs associated with
InterLane  residential  system features developed early in the product
life  and  no  longer  incorporated  in  the  current system's design.
Capitalized  costs  related to the commercial product and other common
costs  began  to  be  amortized in late 1998 as its commercial product
became  available  for general distribution. TeCom had 46 employees at
Dec. 31, 1998.

BOSEK, GIBSON AND ASSOCIATES

     BGA  is  an  engineering energy services company headquartered in
Tampa.  It has 9 offices in Florida and two in California, and had 119
employees as of Dec. 31, 1998. 
     It  provides  engineering,  construction  management  and  energy
services  to  more  than  300  customers,  including  public  schools,
universities, health care facilities and other governmental facilities
throughout Florida and California. 

Item 2.   PROPERTIES.

     TECO   Energy  believes  that  the  physical  properties  of  its
operating  companies  are  adequate  to  carry  on their businesses as
currently   conducted.  The  properties  of  Tampa  Electric  and  the
subsidiaries  of  TECO  Power  Services are generally subject to liens
securing long-term debt.

TAMPA ELECTRIC

     At  Dec.  31,  1998,  Tampa Electric had five electric generating
plants  and  four combustion turbine units in service with a total net
winter  generating  capability  of 3,615 megawatts, including Big Bend
( 1 , 742-MW  capability  from  four  coal  units),  Gannon  (1,180-MW
capability from six coal units), Hookers Point (215-MW capability from
five  oil  units),  Phillips (34-MW capability from two diesel units),
Polk  (250-MW  capability  from  one  integrated gasification combined
cycle  unit  (IGCC))  and four combustion turbine units located at the
Big  Bend  and  Gannon  stations  (194  MWs). The capability indicated
represents  the demonstrable dependable load carrying abilities of the
generating  units  during  winter  peak periods as proven under actual
operating  conditions.  Units  at Hookers Point went into service from
1948  to  1955, at Gannon from 1957 to 1967, and at Big Bend from 1970
to  1985.  The  Polk IGCC unit began commercial operation in September
1996.  In 1991, Tampa Electric purchased two power plants (Dinner Lake
and  Phillips) from the Sebring Utilities Commission (Sebring). Dinner
Lake  (11-MW  capability  from one natural gas unit) and Phillips were
placed  in service by Sebring in 1966 and 1983, respectively. In March
1994, Dinner Lake Station was placed on long-term reserve standby.
     T a m pa  Electric  owns  182  substations  having  an  aggregate
transformer  capacity  of  16,368,281  KVA.  The  transmission  system
c o n s ists  of  approximately  1,196  pole  miles  of  high  voltage
transmission lines, and the distribution system consists of 6,905 pole
miles  of  overhead lines and 2,741 trench miles of underground lines.
As of Dec. 31, 1998, there were 537,107 meters in service. All of this
property is located in Florida.
     All plants and important fixed assets are held in fee except that
title  to  some  of  the  properties  is subject to easements, leases,
contracts,  covenants and similar encumbrances and minor defects, of a
nature  common  to  properties  of  the size and character of those of

                                  20


Tampa Electric.
     Tampa  Electric  has easements for rights-of-way adequate for the
m a i ntenance  and  operation  of  its  electrical  transmission  and
distribution  lines  that  are  not  constructed upon public highways,
roads  and  streets.  It has the power of eminent domain under Florida
law for the acquisition of any such rights-of-way for the operation of
transmission  and  distribution  lines.  Transmission and distribution
lines  located  in  public  ways  are  maintained  under franchises or
permits. 
     Tampa  Electric  has a long-term lease for its office building in
downtown  Tampa  which  serves  as headquarters for TECO Energy, Tampa
Electric and numerous other TECO Energy subsidiaries.

PEOPLES GAS SYSTEM

       PGS' distribution system extends throughout the areas it serves
in  Florida, and consists of more than 12,100 miles of pipe, including
approximately  7,300  miles  of  mains and over 4,800 miles of service
lines.
     P G S   operating  divisions  are  located  in  thirteen  markets
throughout   Florida.  While  most  of  the  operations,  storage  and
administrative facilities are owned, a small number are leased.

TECO TRANSPORT

     Electro-Coal's  storage  and transfer terminal is on a 1,070-acre
site  fronting  on the Mississippi River, approximately 40 miles south
of  New Orleans. Electro-Coal owns 342 of these acres in fee, with the
remainder held under long-term leases.
     Mid-South  operates  a  fleet  of  18 towboats and over 710 river
barges,  most  of which it owns, on the Mississippi, Ohio and Illinois
rivers.  This  includes  three  towboats  and 110 covered river barges
chartered in March 1998 under a five-year agreement which provides for
the acquisition of these assets at the conclusion of the charter term.
Mid-South  owns  15  acres  of  land  fronting  on  the  Ohio River at
Metropolis,  Illinois  on  which  its operating offices, warehouse and
repair  facilities  are  located. Fleeting and repair services for its
barges  and those of other barge lines are performed at this location.
Additionally,  Mid-South  performs  fleeting  and supply activities at
leased facilities in Cairo, Illinois.
     Gulfcoast  owns  and operates a fleet of 12 ocean-going tug/barge
units,  a  30,000  ton  ocean-going  ship and a 40,000 ton ocean-going
ship, with a combined cargo capacity of over 413,000 tons.

TECO COAL

     TECO  Coal, through its subsidiaries, controls over 100,000 acres
of coal reserves and mining property in Kentucky and Tennessee.
     Pike-Letcher  controls  in  excess  of  50,000  acres in Pike and
Letcher  Counties, Kentucky. These properties contain estimated proven
and probable reserves in excess of 110 million tons.
     Premier  owns  and  operates  a  preparation plant and unit-train
loadout  facility  in  Pike  County, Kentucky and conducts surface and
deep mining operations of reserves which are leased from Pike-Letcher.
Premier does not own any coal reserves.
     Clintwood  has 32,000 acres of coal reserves held under long-term
leases  in  Pike  County, Kentucky. These properties contain estimated
proven  and  probable reserves in excess of 25 million tons. Clintwood

                                  21


owns  and operates a rail tipple and a coal preparation plant near the
mines.
     Gatliff  has 39,000 acres of coal reserves and mining property in
Knox  and  Whitley  Counties, Kentucky and Campbell County, Tennessee.
Gatliff  owns  9,300  acres  in  fee  and  leases  29,700  acres under
long-term  leases.  These  properties  contain  estimated  proven  and
probable  coal reserves in excess of 10 million tons. This coal, which
combines low-sulfur and low-ash fusion temperature characteristics, is
found  in  both  deep  and  surface mines. Gatliff owns and operates a
rapid-loading  rail  tipple and a coal preparation plant near its deep
mines. In 1996, TECO Coal closed certain of its older Gatliff mines.
     Rich  Mountain  operates  a  surface mine for Gatliff in Campbell
County, Tennessee, and does not own any coal reserves.

TECO POWER SERVICES

     Hardee Power has a lease for approximately 1,300 acres of land in
Hardee and Polk Counties, Florida on which the Hardee Power Station is
located.  The  lease has a term that runs through 2012 with options to
extend the term for up to an additional 20 years.
     In  addition,  a  TECO  Power  Services'  subsidiary has a 96.06-
percent interest in TCAE, which owns 7 acres in Guatemala on which the
Alborada  Power  Station  is  located.  Another  TECO  Power  Services
subsidiary  has  a  46-percent  ownership  in a project entity, CGESJ,
which  owns 190 acres in Guatemala on which the San Jose Power Station
is being built.

TECO COALBED METHANE

     TECO  Coalbed  Methane's  interest in proved gas reserves at Dec.
31,  1998 was independently estimated to be 162 billion cubic feet for
655 wells.
     TECO  Coalbed  Methane's gas production for 1998 was 17.6 billion
cubic feet.

PEOPLES GAS COMPANY 

     PGC's  operating  divisions  are located in 21 markets throughout
the state; most of its facilities are leased.

Item 3.   LEGAL PROCEEDINGS.

     None.

Item 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

     No  matter  was  submitted during the fourth quarter of 1998 to a
vote  of  TECO  Energy's security holders, through the solicitation of
proxies or otherwise.










                                  22
EXECUTIVE OFFICERS OF THE REGISTRANT

Information  concerning  the current executive officers of TECO Energy
is as follows: 
                                  Current Positions and Principal
     Name             Age        Occupations During Last Five Years
Girard F. Anderson    67         Chairman of the Board, President and
                                 Chief  Executive  Officer,  February
                                 1998  to  date;  President and Chief
                                 Executive  Officer, November 1997 to
                                 February  1998;  President and Chief
                                 Operating   Officer,  July  1994  to
                                 November  1997;  and  prior thereto,
                                 Executive   Vice   President-Utility
                                 Operations  and  President and Chief
                                 Operating  Officer of Tampa Electric
                                 Company.

Alan D. Oak           52         Executive  Vice  President and Chief
                                 Operating  Officer, November 1997 to
                                 date;  Senior Vice President-Finance
                                 and  Chief  Financial Officer, April
                                 1995  to  November  1997;  and prior
                                 t h ereto,  Senior  Vice  President-
                                 F i nance,   Treasurer   and   Chief
                                 Financial Officer.

Roger H. Kessel       62         Executive  Vice  President,  January
                                 1 9 9 9   to   date;   Senior   Vice
                                 President-Legal    and    Regulatory
                                 Affairs  and  General  Counsel, July
                                 1998  to  January  1999; Senior Vice
                                 President-General     Counsel    and
                                 Secretary,  April 1995 to July 1998;
                                 a n d      prior    thereto,    Vice
                                 President-General     Counsel    and
                                 Secretary.

William N. Cantrell   46         President-Peoples   Gas   Companies,
                                 June   1997  to  date;  Director  of
                                 Peoples Gas Transition Team, January
                                 1997  to  June 1997; Vice President-
                                 Energy   Supply  of  Tampa  Electric
                                 Company, April 1995 to January 1997;
                                 and  prior  thereto, Vice President-
                                 Energy  Resources  Planning of Tampa
                                 Electric Company.

Roger A. Dunn         56         Vice President-Human Resources, July
                                 1995  to  date;  and  prior thereto,
                                 S e n ior    Vice    President-Human
                                 Resources  and  Corporate Affairs of
                                 L T V      C o r p oration    (steel
                                 manufacturer), Cleveland, Ohio.

Royston K. Eustace    57         Senior    Vice    President-Business
                                 Development, April 1998 to date; and
                                 prior   thereto,   Vice   President-
                                 S t rategic  Planning  and  Business
                                 Development.


                                  23
                                  Current Positions and Principal
     Name             Age        Occupations During Last Five Years


Gordon  L. Gillette   39         Vice  President-Finance  and  Chief
                                 Financial  Officer,  April  1998  to
                                 date;    Vice   President-Regulatory
                                 Affairs,  April  1997 to April 1998;
                                 Vice     President-Regulatory    and
                                 Business  Strategy of Tampa Electric
                                 Company,  April  1996 to April 1997;
                                 Vice President-Regulatory Affairs of
                                 Tampa Electric Company, January 1995
                                 to  April  1996;  and prior thereto,
                                 Director-Project  Services  of  TECO
                                 Power Services Corporation. 

Sheila  M. McDevitt   52         Vice   President-General   Counsel,
                                 January  1999  to  date;  and  prior
                                 thereto,   Vice  President-Assistant
                                 General Counsel.

John B. Ramil         43         President of Tampa Electric Company,
                                 April  1998 to date; Vice President-
                                 Finance and Chief Financial Officer,
                                 November  1997  to  April 1998; Vice
                                 President-Energy     Services    and
                                 Planning  of Tampa Electric Company,
                                 November 1994 to November 1997; Vice
                                 President-Energy  Services  and Bulk
                                 Power  of  Tampa  Electric  Company,
                                 April  1994  to  November  1994; and
                                 prior   thereto,   Director-Resource
                                 Planning of Tampa Electric Company.

     There  is no family relationship between any of the persons named
above.  The  term  of office of each officer extends to the meeting of
t h e  Board  of  Directors  following  the  next  annual  meeting  of
shareholders,  scheduled  to  be held on April 21, 1999, and until his
successor is elected and qualified.






















                                  24
                               PART  II

Item 5.   MARKET  FOR  THE  REGISTRANT'S  COMMON  EQUITY  AND  RELATED
          STOCKHOLDER MATTERS. 

     The  following  table shows the high, low and closing sale prices
for  shares  of  TECO  Energy common stock, which is listed on the New
York Stock Exchange, and dividends paid per share, per quarter. 

                    1st       2nd        3rd       4th
     1998
     High           $28 1/2   $28 5/16   $28 7/8   $30 5/8
     Low            $25 9/16  $25 3/16   $24 3/4   $26 3/4
     Close          $28 1/4   $26 13/16  $28 9/16  $28 3/16
     Dividend       $.295     $.31       $.31      $.31 

     1997
     High           $25 1/8   $25 5/8    $25 7/8   $28 3/16
     Low            $23 3/4   $23 3/4    $23 7/8   $22 3/4
     Close          $24       $25 9/16   $24 1/2   $28 1/8
     Dividend       $.28      $.295      $.295     $.295


___________________

     The  approximate number of shareholders of record of common stock
of TECO Energy as of Feb. 28, 1999 was 26,884.

     TECO  Energy's  primary  source  of  funds  is dividends from its
operating companies. Tampa Electric's first mortgage bonds and certain
long-term  debt  issues  at Peoples Gas System contain provisions that
limit  the  payment of dividends on the common stock of Tampa Electric
Company.  Substantially  all  of  Tampa  Electric  Company's  retained
earnings were available for dividends throughout 1998.




























                                       25


Item 6.   SELECTED FINANCIAL DATA.
Year ended Dec. 31,                         1998          1997        1996         1995       1994   
(millions, except per share amounts)
                                                                           
Revenues (1)                            $1,958.1      $1,862.3    $1,775.3    $ 1,658.9   $1,615.4   
Net income:
  From continuing operations            $  200.4(2)   $  211.4(3) $  217.4    $   200.8   $  163.8(4)
  From discontinued operations                --          (6.5)       (0.9)        (0.5)        --   
  Disposal of discontinued                          
    operations                               6.1          (3.0)         --           --         --   
Net income                              $  206.5      $  201.9    $  216.5     $  200.3   $  163.8   

Total assets                            $4,179.3      $3,960.4    $3,901.6     $3,801.0   $3,622.6   
Long-term debt                          $1,279.6      $1,080.2    $1,118.0     $1,126.4   $1,156.3   

Earnings per average share (EPS)
  outstanding -- basic: 
    From continuing operations          $   1.52(2)   $   1.62(3) $   1.68     $   1.56   $   1.28(4)
    From discontinued operations              --         (0.05)      (0.01)          --         --   
    Disposal of discontinued 
      operations                             .05         (0.03)         --           --         --   
Earnings per average common 
  share outstanding -- basic            $   1.57      $   1.54    $   1.67     $   1.56   $   1.28   
Common dividends paid per                           
  common share (5)                      $  1.225      $  1.165    $  1.105     $ 1.0475   $  .9975   

_________________
(1)  Amounts  shown in 1998, 1997, 1996 and 1995 include the impact of
     d e f erred  revenues,  as  discussed  on  pages  43  and  44  of
     Management's Discussion and Analysis.
(2)  Includes  the  effect  of  one-time  non-recurring charges, which
     reduced  net  income  by  $21.3 million and earnings per share by
     $0.16  in 1998 as discussed on page 27 of Management's Discussion
     and Analysis.
(3)  Includes   the  effect  of  one-time  merger-related  transaction
     expenses,  which  reduced net income by $5.3 million and earnings
     per   share  by  $0.04  in  1997  as  discussed  on  page  27  of
     Management's Discussion and Analysis.
(4)  Includes  the  effect  of  a corporate restructuring charge which
     reduced net income by $15 million and earnings per share by $0.12
     in 1994.
(5)  Amounts  shown  are the actual dividends paid per share (and have
     not been restated to reflect the shares issued in connection with
     the Peoples companies merger).





                                  26
Item 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION 
          AND RESULTS OF OPERATIONS.

The  Management's  Discussion  and  Analysis  which  follows  contains
f o r ward-looking  statements  which  are  subject  to  the  inherent
uncertainties  in  predicting  future  results and conditions. Certain
factors  that  could  cause  actual  results to differ materially from
those  projected  in these forward-looking statements are set forth in
the Investment Considerations section.

EARNINGS SUMMARY:

All  prior  year amounts have been restated to reflect the 1997 merger
with  the  Peoples  Gas  companies  and  to  exclude  the discontinued
operations of TECO Oil & Gas, which are now separately presented.

     TECO Energy reported basic earnings from continuing operations of
$1.52  per share in 1998 compared to $1.62 per share in 1997. Earnings
from  continuing  operations in 1998, excluding the impact of $.16 per
share  in  one-time  charges,  totaled  $1.68 per share. Earnings from
continuing  operations  in  1997, excluding $.04 per share in one-time
merger  related  charges,  were $1.66 per share. Earnings, including a
net  gain  of $.05 per share from discontinued oil and gas operations,
were $1.57 per share in 1998. This compares with earnings of $1.54 per
share  in  1997,  which  included losses from discontinued oil and gas
operations of $.08 per share.
     One-time  charges in 1998 reflect asset value adjustments at TECO
Coal's  Gatliff  mining  facilities  relating to the expiration of the
coal  supply  contract  with  Tampa Electric in 1999 (described in the
TECO   Coal  section),  a  write  off  of  product  development  costs
associated with InterLane  residential system features developed early
in the product life and no longer incorporated in the current system's
design  at  TeCom  (described in the TeCom section), a charge at Tampa
Electric  associated with ongoing actions to mitigate the effects of a
1997  Florida  Public  Service Commission (FPSC) ruling that separated
two  wholesale  power  sales  contracts  from  the retail jurisdiction
through  1999,  and  a  charge at Tampa Electric resulting from a 1998
r e g ulatory  ruling  denying  recovery  of  coal  expenses  over  an
established  benchmark  for  coal  purchases  from  Gatliff since 1992
(described in the Tampa Electric section). 
     Results  in  1997  reflected  one-time costs from the Peoples Gas
companies merger and an FPSC decision, described in the Tampa Electric
section,  to  change  the  regulatory treatment of two wholesale power
sales contracts. These items more than offset earnings growth from the
diversified businesses.


                              1998  Change     1997   Change    1996 
Earnings Per Share - basic
Continuing operations       $ 1.52   -6.2%  $ 1.62     -3.6%  $ 1.68 
Discontinued operations        .05     --     (.08)      --     (.01)
Earnings per share          $ 1.57    1.9%  $ 1.54     -7.8%  $ 1.67 

Earnings Per Share - diluted
Continuing operations       $ 1.52   -5.6%  $ 1.61     -3.6%  $ 1.67 
Discontinued operations        .05      --    (.07)      --       -- 
Earnings per share          $ 1.57    1.9%  $ 1.54     -7.8%  $ 1.67 





                                  27
Earnings Per Share by Operating Group 
From Continuing Operations - basic
  Regulated companies
    Tampa Electric          $ 1.07(1)  3.9%   $ 1.03    -4.6%  $ 1.08 
    Peoples Gas System         .12     9.1%      .11(2)    --     .11 
  Diversified companies
    /other                     .49(3) -5.8%      .52(3)  6.1%     .49 
                              1.68     1.2%     1.66    -1.2%    1.68 
 One-time charges
  Wholesale contract 
    -Tampa Electric          (.04)       --      --        --      -- 
  Coal quality 
    -Tampa Electric          (.03)       --      --        --      -- 
  Asset adjustment 
    -TECO Coal               (.07)       --      --        --      -- 
  Asset adjustment 
    -TeCom                   (.01)       --      --        --      -- 
  Merger related costs       (.01)       --    (.04)       --      -- 
Earnings per share from
 continuing operations     $ 1.52     -6.2%   $ 1.62     -3.6%  $ 1.68 
Net Income from continuing 
  operations (millions)(4) $200.4     -5.2%   $211.4     -2.8%  $217.4 
Average common shares 
  outstanding 
Basic (millions)            131.7       .7%   130.8      1.2%   129.3 
Diluted (millions)          132.2       .8%   131.2      1.1%   129.8 


Return on average common equity from continuing operations
   After one-time charges    13.0%             14.3%            15.6% 
   Before one-time charges   14.4%             14.6%            15.6% 

(1)  Excludes one-time charges totaling $.07 per share.
(2)  Excludes one-time merger related charges of $.01 per share.
(3)  Excludes asset adjustments of $.08 per share in 1998 and one-time
     merger  related  charges  of  $.01 per share in 1998 and $.03 per
     share in 1997.
(4)  Includes one-time charges.

OPERATING RESULTS:

TECO Energy's Operating Results
     Operating  income,  excluding  $25.9  million  in one-time pretax
charges,  grew  2.1  percent  in  1998. Tampa Electric and Peoples Gas
contributed  to  the  increase,  reflecting  good growth from a strong
local  economy,  expansion  of  the  gas system and the recognition of
$38.3 million of previously deferred revenues at Tampa Electric. For a
description of the origination and treatment of deferred revenues, see
Utility  Regulation  -  Rate Stabilization Strategy section. TECO Coal
and  TECO  Transport also achieved higher operating income, while TECO
Power Services and TECO Coalbed Methane were lower. 
     Operating  income  in  1997  reflected  the  recognition of $30.5
million  of  previously  deferred  revenues  at  Tampa  Electric,  the
inclusion  of  Polk  Unit  One  in rate base for earnings purposes and
strong  performance  by  the  diversified companies, particularly TECO
Transport.  In 1996, Tampa Electric deferred $34.2 million of revenues
under  agreements  approved by the FPSC. See Utility Regulation - Rate
Stabilization Strategy section.




                                  28
     The  following  table  identifies the unconsolidated revenues and
operating   income  from  continuing  operations,  excluding  one-time
charges, of the significant business segments.  For additional detail,
refer  to the Notes to Consolidated Financial Statements - Footnote K,
Segment Information.

Contributions by Operating Group (unconsolidated)

(millions)                    1998   Change     1997   Change     1996
Revenues  
Tampa Electric(1)         $1,234.6     3.8% $1,189.2     6.9% $1,112.9
Peoples Gas System           252.8     1.3%    249.6    -3.5%    258.7
Diversified companies(2)                            
   TECO Transport            230.0     5.2%    218.7     5.4%    207.5
   TECO Coal                 232.4     7.8%    215.6     3.9%    207.5
   TECO Power Services        98.7     6.1%     93.0     5.6%     88.1
   Other diversified 
     businesses              113.0     7.4%    105.2     2.2%    102.9

Operating income
Tampa Electric            $  279.7(4)  3.0% $  271.5    11.3% $  244.0
Peoples Gas System            35.8     6.5%     33.6     5.0%     32.0
Diversified companies(2)(3)
   TECO Transport             43.2     2.6%     42.1     8.2%     38.9
   TECO Coal                  23.5(5) 18.1%     19.9     8.7%     18.3
   TECO Power Services        13.0   -14.5%     15.2    -9.0%     16.7
   Other diversified 
     businesses               34.7(6) -8.4%     37.9    -5.0%     39.9

(1)  Includes the recognition of previously deferred revenues totaling
     $38.3  million  and $30.5 million in 1998 and 1997, respectively.
     1996  revenues are net of $34.2 million deferred under agreements
     described in the Utility Regulation - Rate Stabilization Strategy
     section.
(2)  From continuing operations.
(3)  Includes items which were reclassified for consolidated financial
     statement  purposes. The principal items are the non-conventional
     fuels  tax  credit  related  to  coalbed  methane  production and
     interest  expense  on  the  limited-recourse  debt related to the
     independent  power  operations. In the Consolidated Statements of
     Income,  the tax credit is part of the provision for income taxes
     and  the  interest  is  part of interest expense. Certain amounts
     have been restated to conform to current year presentation.
(4)  Excludes one-time, pretax charge of $9.6 million for treatment of
     a wholesale contract.
(5)  Excludes  one-time,  pretax  charge  of  $13.6  million for asset
     valuation adjustments.
(6)  Excludes one-time, pretax charge of $2.7 million for TeCom.

Tampa Electric - Electric Operations

Tampa Electric's Operating Results

     Tampa  Electric's 1998 operating income, before one-time charges,
increased  three  percent from 1997, reflecting strong customer growth
and continued strength in the local economy. Results in 1998 reflected
recognition of $38.3 million of  previously deferred revenues.





                                  29
     In  1997,  Tampa  Electric benefited from a strong local economy,
favorable customer growth and cost controls. Its 1997 operating income
increased more than 11 percent, after the recognition of $30.5 million
of previously deferred revenues.

Tampa Electric Results

(millions)                    1998   Change     1997   Change     1996
Revenues(1)               $1,234.6     3.8%  $1,189.2     6.8% $1,112.9
Operating expenses           954.9(2)  4.1%     917.7     5.6%    868.9
Operating income          $  279.7     3.0%  $  271.5    11.3% $  244.0

(1)  Includes  the  recognition  of $38.3 million and $30.5 million of
     previously deferred revenues in 1998 and 1997, respectively. 1996
     revenues are net of $34.2 million of deferred revenues.
(2)  Excludes one-time, pretax charge of $9.6 million for treatment of
     a wholesale contract.


Tampa Electric's Operating Revenues

     Tampa  Electric's  1998  operating  revenues  increased  almost 4
percent, after the recognition of $38.3 million of previously deferred
revenues.  The  company  had customer growth of 2.3 percent and retail
energy  sales  growth  of  more  than 6 percent. Tampa Electric's 1997
revenues,   including  recognition  of  $30.5  million  of  previously
deferred  revenues,  increased  almost 7 percent, with customer growth
increasing more than 2 percent and retail energy sales up 1 percent.
     The economy in Tampa Electric's service area continued to grow in
1998,   with  increased  employment  from  corporate  relocations  and
e x p ansions.  Combined  residential  and  commercial  sales  volumes
increased  over  7  percent in 1998, reflecting the addition of almost
12,000 customers and increased demand during warmer-than-normal summer
weather.  Combined  residential  and  commercial energy sales declined
slightly  in 1997, as the effects of mild weather more than offset the
addition of more than 12,000 new customers. 
     Non-phosphate  industrial  sales  increased  in  1998  and  1997,
reflecting  the  shift  of some commercial customers to the industrial
classification  to  take  advantage  of  favorable  tax law changes on
electricity  used  in  manufacturing. This shift does not affect Tampa
Electric revenues. 
     Sales  to the phosphate industry in 1998 were slightly below 1997
levels,  reflecting  a  gradual migration of phosphate mining activity
out of Tampa Electric's service area. This decline could accelerate if
customers  within  the  phosphate  customer group decide to pursue new
self-generation  projects.  Revenues from the phosphate customer group
represented slightly more than 3 percent of base revenues in 1998.
     Based  on expected growth reflecting both population and business
activity increases, Tampa Electric projects retail energy sales growth
of  approximately  2.5 percent annually over the next five years, with
combined energy sales growth in the residential and commercial sectors
of almost 3 percent annually. Energy sales to non-phosphate industrial
customers are expected to grow almost 2 percent annually over the next
five years.
     All  of  these  growth  projections  assume  continued local area
economic  growth, normal weather and other factors. See the Investment
Considerations section.





                                  30
     Non-fuel  revenues from sales to other utilities were $36 million
in  1998,  $39  million  in 1997 and $36 million in 1996. The non-fuel
revenue  increase  in  1997  reflected  the  shift  from broker system
economy  sales  to  longer-term  higher-margin  wholesale power sales.
Megawatt  hours  sold  to  other utilities decreased in 1998 primarily
because  higher retail energy sales absorbed more generation capacity,
and  were  lower  in  1997 due to lower Tampa Electric generating unit
availability.  The  decrease in non-fuel revenue in 1998 is the result
of  lower sales volumes and a shift from longer-term sales to shorter-
term  sales,  because  of  an  adverse  FPSC  decision  in  late 1997,
described  in the Utility Regulation - Wholesale Power Sales Contracts
section.  Tampa  Electric  will  concentrate its prospective wholesale
power  sales  efforts  on energy broker or other short-term sales, and
not  on  longer-term  capacity contracts as was the case prior to this
ruling. The FPSC decision, which required Tampa Electric to change the
regulatory  treatment  of two wholesale power sales contracts, had the
effect  of  reducing  Tampa Electric's 1997 earnings by about $.05 per
share.  The  company  terminated one contract and incurred a charge of
$.04  per  share  in  1998  for actions to mitigate the effect of this
treatment on the second contract.

Tampa Electric Megawatt-Hour Sales

(thousands)                   1998   Change     1997   Change     1996
Residential                  7,050     8.5%    6,500    -1.6%    6,607
Commercial                   5,173     5.5%    4,901     1.8%    4,815
Industrial                   2,520     2.1%    2,466     7.0%    2,304
Other                        1,284     5.1%    1,223     1.7%    1,203
  Total retail              16,027     6.2%   15,090     1.1%   14,929
Sales for resale             2,486   -21.3%    3,160    -2.5%    3,241
  Total energy sold         18,513     1.4%   18,250      .4%   18,170

Retail customers (average)   530.3     2.3%    518.4     2.4%    506.0

Tampa Electric's Operating Expenses
     Non-fuel  operation  and  maintenance expenses increased almost 7
percent  in  1998. Required expenditures to enhance system reliability
and timing of generation station outages contributed to an increase of
over $16 million in maintenance expense. Other operation expenses were
essentially  level  with 1997, the result of effective cost management
and  improved  efficiency throughout the company. Based on maintenance
activity in 1998, non-fuel operations and maintenance expenses in 1999
are expected to be lower than 1998, then increase at approximately the
rate of inflation over the next several years.
     In  September  1996, Tampa Electric completed construction of the
250-megawatt,  state-of-the-art,  clean-coal technology Polk Unit One.
The  FPSC  has  allowed  full  recovery of capital costs and operating
expenses  associated  with  the  plant  as  described  in  the Utility
Regulation - Rate Stabilization Strategy section. The addition of this
facility  was  the primary reason for the increased non-fuel operating
expenses  in  1997. Through 1998, a total of $21 million from the U.S.
Department  of  Energy  (DOE)  was  received  to  partially  offset  a
s i gnificant  portion  of  the  non-fuel  operation  and  maintenance
expenses.  For  1999,  approximately $7 million in funds are available
from the DOE.







                                  31
Operating Expenses

(millions)                    1998   Change     1997   Change     1996
Other operating expenses    $165.7      .4%   $165.1      .6%   $164.1
Maintenance                   94.6    21.0%     78.2    19.4%     65.5
Depreciation                 146.1     3.3%    141.4    17.6%    120.2
Taxes, other than income      97.2     5.9%     91.8     5.5%     87.0
 Operating expenses          503.6     5.7%    476.5     9.1%    436.8
Fuel                         366.6    -1.8%    373.4    -2.5%    383.1
Purchased power               84.7    25.1%     67.8    38.4%     49.0
  Total fuel expense         451.3     2.3%    441.2     2.1%    432.1
Total operating expenses    $954.9     4.1%   $917.7     5.6%   $868.9

     Reflecting  normal  plant additions to serve the growing customer
base,   depreciation  expense  increased  by  $4.7  million  in  1998.
Depreciation expense increased $21 million in 1997 due to normal plant
additions  and  a  full year of service of Polk Unit One. Depreciation
expense is projected to rise moderately for the next several years due
to  normal  additions  to  utility plant, as well as the addition of a
flue  gas desulfurization system in 2000. See Environmental Compliance
section.
     Taxes  other  than income increased in 1998 as a result of higher
gross  receipts  taxes  and  franchise  fees  related to higher energy
sales.  These  taxes  are  recovered  through customer bills. In 1997,
changes  in  taxes  other  than  income  reflected  the property taxes
associated with Polk Unit One. 
     Total fuel expense and purchased power increased in 1998 and 1997
due to higher energy sales. Average coal costs, on a cents-per-million
BTU  basis, increased 1.3 percent in 1998 after a 2.4 percent decrease
in  1997.  The overall success in controlling system fuel expense is a
result  of  Tampa  Electric's  use  of  lower-priced coals, the mix in
operating  generating units and favorable prices in spot coal markets.
In  1998,  the FPSC disallowed, retroactively to 1992, certain quality
adjustments  for  coal  purchased  from  a  Tampa  Electric affiliate,
resulting in a one-time pretax nonoperating charge of $7.3 million.
     Purchased  power  increased in 1998 due to weather-related demand
and  the  provision  of  replacement power for certain wholesale power
sales  contracts.  In 1997, purchased power increased primarily due to
lower  generating  unit  availability. In each year, substantially all
fuel  and  purchased  power  expenses  were recovered through the fuel
adjustment clause.
     Nearly all of Tampa Electric's generation in the last three years
has  been  from  coal,  and the fuel mix is expected to continue to be
substantially coal. 
     External forecasts indicate relatively stable coal prices for the
next few years compared to oil or gas prices. On a total energy supply
basis,  self-generation  accounted  for 92 percent of the total system
energy requirement in 1998. 

Peoples Gas System

Peoples Gas System Results
     Peoples  Gas  System  (PGS)  achieved  operating income growth in
excess  of 6 percent over 1997, with the increase due primarily to new
customer  additions  and  higher average utilization per customer. The
benefits  of customer growth for the year were partially offset by the
effects  of warmer-than-normal weather during the winter months and by
restructuring  costs  associated  with  the  1998 decision to exit the
appliance sales and service business. 
     Operating  income  grew  5  percent in 1997 over 1996, reflecting


                                  32
increased  customers,  effective  cost  control and the acquisition of
West  Florida  Natural Gas Company (WFNG). These factors were somewhat
offset by the mild weather early in 1997. 
     The  actual cost of gas and upstream transportation purchased and
resold  to  end-use  customers  is  recovered  through a Purchased Gas
Adjustment clause approved by the FPSC.

Peoples Gas System Results(1)

(millions)                    1998   Change     1997   Change     1996

Revenues                    $252.8     1.3%   $249.6    -3.5%   $258.7
Cost of gas sold             115.4    -3.5%    119.6    -8.1%    130.1
Operating expenses           101.6     5.4%     96.4     -.2%     96.6
Operating income            $ 35.8     6.5%   $ 33.6     5.0%   $ 32.0

Therms sold (millions)-by Customer Segment

   Residential                52.7     7.8%     48.9     1.5%     48.2
   Commercial                266.0     7.4%    247.6     3.9%    238.4
   Industrial                305.0     5.7%    288.6     9.7%    263.2
   Power Generation          288.3    -8.4%    314.7     7.7%    292.3
   Total                     912.0     1.4%    899.8     6.9%    842.1

Therms sold (millions)-By Sales Type

   System Supply             320.8     9.6%    292.6   -14.5%    342.3
   Transportation            591.2    -2.6%    607.2    21.5%    499.8
   Total                     912.0     1.4%    899.8     6.9%    842.1

Customers (thousands)        239.6     2.1%    234.7    16.0%    202.4

(1)  1996  data  does not include the operating revenues and expenses,
     therms sold and customers of WFNG. WFNG was acquired in 1997 in a
     merger  transaction  accounted  for  as  a  pooling of interests.
     Prior-year financial results were not restated for the effects of
     this merger due to its size.

     Residential gas sales increased in 1998, primarily as a result of
overall  customer  growth  and  the  addition  of  high-end  customers
throughout the year. Results reflected slightly warmer weather in 1998
compared to 1997.
     Residential  gas  sales  increased in 1997 due to the addition of
WFNG,  partially offset by a mild winter which followed a much colder-
than-normal winter in 1996.
     Operating revenues from residential and commercial customers grew
almost  2  percent  in  1998, while revenues from industrial and power
generation  customers  were  approximately 10 percent below last year.
The  increase  in  residential  revenues  was  primarily due to higher
average utilization per customer, reflecting the addition of high-end,
multiple appliance customers. 
     O p e rating   expenses   increased   during   1998,   reflecting
restructuring  costs totaling $3.4 million. These costs were primarily
for  early  retirement  and  severance  costs affecting 200 employees,
associated  with  a  decision in April to exit the appliance sales and
service  business. The restructuring, which was initiated in July, was
completed and began to yield savings in ongoing expenses by the end of
1998.
     PGS  is  the  largest  investor-owned gas distribution utility in
Florida, with about 70 percent of the market. It serves almost 240,000


                                  33
customers in all of the major metropolitan areas of Florida. 
     PGS  expects  to invest an average of $50-60 million per year for
the  next  five  years  to  grow  the  business,  roughly doubling the
historical  level  of  capital  expenditures.  Infrastructure is being
expanded  both in areas currently served and into areas not yet served
by natural gas.
     In  April  1998, PGS announced plans to expand into the Southwest
Florida market providing service to Fort Myers, Naples, Cape Coral and
surrounding  areas.  It  is  anticipated  that  110,000  new homes and
businesses  will  be  added  in  this  market  over  the  next decade,
representing  a  significant  opportunity  for  growth in the high-end
residential  and  the commercial customer sectors. The company also is
expanding  to  the U.S. Naval Station at Mayport near Jacksonville and
anticipates  that  the  Mayport facilities and surrounding communities
will use over 2.6 million therms of natural gas annually.
     PGS  expects  savings  from  the  discontinuance of its appliance
sales  and  service  business  and  will  continue making cost control
improvements.  PGS  began  partnering with companies in an established
dealer  network  to provide sales, installation and repair services to
customers.
     PGS expects increases in sales volumes and corresponding revenues
in  1999  and,  beginning in late 1999, customer additions and related
revenues will begin to reflect the Southwest Florida expansion. 
     All  of  these  growth  projections  assume  continued local area
economic  growth, normal weather and other factors. See the Investment
Considerations section.

TECO Transport

     TECO Transport recorded slightly higher operating income in 1998,
primarily  from  utilizing added equipment on the river system, a full
year's  operation of the ocean vessel acquired in late 1997, increased
northbound  shipments  on  the  river,  lower fuel costs and continued
initiatives   to  control  operating  expenses.  Depreciation  expense
decreased,  reflecting  longer  estimated  economic  lives  of certain
assets.  Improvements  were  partially  offset by a number of factors,
including  unprecedented extreme weather in the early part of the year
and  hurricanes  later in the year, which created delays and difficult
operating  conditions  in  each  of the transportation businesses. The
Asian  economic  situation  and  the strong U. S. dollar also affected
TECO Transport, resulting in lower prices and export volumes.
     In  1997,  TECO Transport achieved higher operating income due to
increased Tampa Electric volumes at the transfer terminal to replenish
coal inventories depleted in 1996 and increased operating efficiencies
in  each  of  the  operating  companies. The ocean-going business also
benefited  from  a full year of operations from a vessel added in 1996
and  increased grain charter business. The river business was impacted
by adverse weather conditions early in 1997. This was partially offset
by  increased northbound business and higher volumes handled for Tampa
Electric.
     In  1998,  TECO  Transport  expanded  its river fleet by about 20
percent, adding 110 barges and three towboats. 
     I n    1999,  TECO  Transport  expects  increased  transfers  and
additional  northbound  river  shipments  of  steel  and steel-related
products as a result of steel mini-mills built along the river system.
Also  in  1999,  revenue  improvement  is  expected from the continued
strong  domestic  demand for coal and phosphate products. In addition,
the  company  will continue to diversify into new markets and cargoes.
Significant factors that will influence results are weather, commodity
grain  prices  and domestic and international economic conditions. See


                                  34
the Investment Considerations section.

TECO Coal

     TECO  Coal's  operating income, excluding the one-time adjustment
to  asset  values discussed below, increased 18 percent in 1998 due to
continued  growth  in  sales  to  the metallurgical and steam markets,
lower  unit  costs at its Gatliff and Clintwood Elkhorn facilities and
improved  preparation  plant  performance  at  its  Clintwood  Elkhorn
facility. 
     In  1997,  operating  income increased 9 percent due to increased
shipments  of specialty coals to third parties from the new facilities
at Clintwood Elkhorn. The growth in third-party steam coal sales and a
slight improvement in prices for coal from the Premier mines more than
offset higher production costs at Premier and lower shipments to Tampa
Electric.
     Coal  sales  increased to 6.8 million tons in 1998, compared with
6.1 million tons in 1997 and 5.9 million tons in 1996. Volumes in 1999
are expected to approach 7 million tons.
     Tampa  Electric  shipments  represented  slightly  more  than  10
percent  of total volumes in 1998 and 16 percent in 1997. Shipments to
Tampa  Electric  of  750,000  tons  declined by about 250,000 tons, or
about  25  percent,  in  1998  after  a similar decline in 1997. Tampa
Electric's  volume  in 1999 is expected to be 500,000 tons. Success in
burning more conventional and lower-cost steam coals has enabled Tampa
Electric  to  adopt  a  competitive  strategy  of  phasing  down  coal
shipments from TECO Coal for the last several years. The contract with
Tampa Electric expires at the end of 1999 and will not be renewed.
     In  1998,  TECO  Coal  recorded a one-time pretax charge of $13.6
million to adjust the value of certain mining facilities. The majority
of this charge reflects a revaluation of assets at TECO Coal's Gatliff
mine  dedicated  to  the  Tampa  Electric  contract.  Because  of  the
anticipated  loss  in  value  of this facility at the end of the Tampa
Electric  contract,  an adjustment was required to reduce the carrying
value   of  the  assets.  The  $13.6  million  charge  also  reflected
adjustments  for  other  assets  which have decreased in market value,
reflecting  limited  markets  that  exist  for  the  coal  from  these
facilities due to the specific characteristics of the product and high
mining costs. 
     In  September  1996,  TECO  Coal  acquired  25  million  tons  of
metallurgical grade coal reserves contiguous to its existing Clintwood
Elkhorn  operation  and  constructed  a  new preparation plant at this
location. This facility, which supports an additional one million tons
of  annual production, went in service in mid-1997. Metallurgical coal
has unique characteristics and is sold primarily to the steel industry
both  domestically and internationally. Sales to this market increased
in  1998  and  are  expected  to  increase in 1999. See the Investment
Considerations section.

TECO Power Services

     TECO  Power  Services  (TPS)  recorded  slightly  lower operating
income  in  1998  and  1997,  primarily  as  a result of a significant
increase  in  business  development  activity  in  1998  and increased
interest  expense  associated  with  the  $29-million limited-recourse
project financing in 1997 for the Alborada Power Station in Guatemala.
Although  operating  income  was  below  1997, net income was slightly
above last year, reflecting lower taxes in Guatemala.
     TPS  accomplished  a number of long-term initiatives during 1998,
including  participation in a consortium which purchased 80 percent of


                                  35
EEGSA,  Guatemala's largest electric distribution company and also the
largest  in  Central  America.  TPS owns a 30 percent interest in this
consortium  and contributed $100 million in equity. The total purchase
price paid by the consortium was $520 million.
     TPS  also entered into a joint venture arrangement with Mosbacher
Power  Group  Partners  in  1998.  Through  this  affiliation,  it  is
currently  participating  in  one generation project and is working on
the development of others. TPS provides capital, technical experience,
support for development costs and other business strengths. In return,
TPS  gains  an  expanded  domestic  and  international  presence  with
opportunities  for project returns, including preferred returns before
benefits are shared.
     In  February  1999,  TPS formed a joint venture relationship with
Energia  Global  International,  Ltd.  (EGI),  a  Bermuda-based energy
development firm. The transaction provides TPS with an immediate stake
in  four  power  projects  in operation or under construction in Costa
Rica and Guatemala, and electric distribution companies in El Salvador
and  Panama.  TPS has initially committed $25 million in the form of a
loan,  and  may  provide  an additional $9 million for new projects or
acquisitions.  The transaction provides a mechanism for TPS to acquire
direct ownership in EGI without additional funding.
     TPS  has a 46 percent interest in a partnership to build, own and
operate a 120-megawatt pulverized coal-fired power plant, the San Jose
Power  Station  in  Guatemala.  The  other  partners  are  The Coastal
Corporation  and  the same local partner it has for the Alborada Power
Station.  The  partnership  has  a 15-year power supply agreement with
EEGSA, the same Guatemalan distribution utility in which TPS purchased
an equity interest in 1998. The $181-million San Jose Power Station is
under  construction and was 56 percent complete as of the end of 1998.
The partnership closed on financing for the project in September 1998,
and commercial operation is expected in early 2000.
     TPS  expects  to double its earnings contribution from identified
domestic  and  international  generation projects over the next two to
three years.
     TECO  Power  Services' domestic project, the Hardee Power Station
in  West  Central  Florida,  continues  to operate reliably, supplying
power  to  Seminole  Electric  Cooperative  and  Tampa  Electric.  The
Alborada   Power  Station  in  Guatemala  also  continues  to  operate
reliably,  achieving  its  highest annual capacity factor in 1998. See
the Investment Considerations section.

Other Diversified Companies

     TECO  Coalbed  Methane's  operating income declined 12 percent in
1998, because of declines in production and lower gas prices that were
only  partially  offset  by  reduced  operating costs and an effective
hedging  program. Production declined to 17.6 billion cubic feet (Bcf)
in 1998, from 19.2 Bcf in 1997. Effective gas prices averaged $.15 per
thousand  cubic feet (Mcf) below 1997, including the favorable results
of  hedging,  which  resulted  in  an  additional $.25 per Mcf. Proven
reserves were estimated at 162 Bcf as of year-end, compared to 195 Bcf
in 1997. 
     In  1997, operating income increased more than 2 percent as lower
per unit operating costs more than offset a production decline to 19.2
Bcf  from  19.8  Bcf  in  1996.  Production  is  expected  to  decline
approximately 9 percent in 1999.
     Production  from TECO Coalbed Methane's reserves are eligible for
non-conventional  fuels  tax  credits under Section 29 of the Internal
Revenue  Code  through  the  year  2002.  The credit, which grows with
inflation,  was  $1.07  per  Mcf in 1998, compared to $1.05 per Mcf in


                                  36
1997. The credit is estimated to be $1.07 per Mcf in 1999.
     All gas produced is sold under contract at spot market prices for
the life of the reserves. Although natural gas prices can be volatile,
the Section 29 tax credits provide stability to TECO Coalbed Methane's
operating results. See the Investment Considerations section.
     Peoples  Gas  Company (PGC), the unregulated propane gas business
acquired  in  the  1997  Peoples  Gas companies merger, is the largest
independent propane distributor in Florida. 
     In  January  1998,  TECO  Energy  acquired Griffis Gas, Inc. in a
stock-for-stock merger transaction that was accounted for as a pooling
of  interests.  About  600,000 shares of TECO Energy common stock were
issued  in the transaction. This acquisition facilitated growth of the
company's  existing market in the Jacksonville area and expansion into
new  markets  in  Gainesville  and Ocala. Prior-year financial results
were not restated for the effects of this merger due to its size.
     P G C ' s  operating  income  increased  significantly  in  1998,
reflecting  higher  volumes  resulting from the acquisition of Griffis
Gas  and  two  other  propane businesses, which increased its customer
base  by 40 percent. Operating results were also favorably impacted by
improved  margins  throughout  the  year. Reflecting the impact of the
acquisitions,  operating expenses were higher in 1998, which partially
offset the volume growth and improved margins. 
     The  company  ended  1998 with approximately 55,000 customers and
sales of 31 million gallons of propane, compared with 37,000 customers
and  22  million  gallons  in 1997. PGC expects to continue its growth
initiatives  throughout  1999,  through  acquisitions and expansion of
existing markets. See the Investment Considerations section.
     TECO  Gas  Services  (formerly  Gator  Gas  Marketing) is another
unregulated business acquired in the Peoples Gas companies merger. The
company  provides  gas  management  and  marketing  services for large
municipal,  industrial  and  power  generation customers. In 1998, the
company  focused  on  increasing its customer base while continuing to
p r o vide  gas  management  services  for  three  large  cogeneration
facilities.
     TeCom  is  marketing  advanced  energy management, automation and
control systems for residential and commercial applications, named the
InterLane  Home Manager and the InterLane Power Manager, respectively.
     T e Com  continued  to  capitalize  development  costs  in  1998,
reflecting  continued  product  development  and enhancement activity.
Total  costs capitalized in 1998 were $6.8 million, compared with $6.5
million in 1997. In accordance with accepted accounting practices, the
company began amortizing capitalized costs in 1998 in conjunction with
commercial  product availability. A total of $.8 million was amortized
in  1998. In addition, a one-time after-tax charge of $1.7 million was
recorded  in  1998,  reflecting  the  write off of product development
costs  associated with InterLane residential system features developed
early  in  the  product life and no longer incorporated in the current
system  s  design.  Total  capitalized  costs as of Dec. 31, 1998 were
$14.7 million.
     The  completion  of  a  significant product development phase has
enabled  the  company  to reduce expenditures by almost one half as it
continues strategic, marketing and distribution activities.
     Bosek,  Gibson  and  Associates,  Inc.  (BGA), an energy services
company  headquartered  in  Tampa with nine offices throughout Florida
and  two  in California, was acquired by TECO Energy in November 1996.
It provides design, engineering and construction services to more than
300  customers,  including  public  schools, universities, health care
facilities  and  other  governmental facilities throughout Florida and
California. 
     D u r ing  the  year,  BGA  expanded  its  offerings  to  include


                                  37
performance  contracting  for  a number of county school districts, as
well  as the Florida State Department of Corrections, and it completed
a  district  cooling project in Tampa. In addition, BGA continued work
begun  in 1997 for the Jacksonville Naval Air Station and the Suncoast
District of the United States Postal Service.

Discontinued Operations

     In  August  1997,  TECO  Energy  announced its intent to exit the
conventional  oil  and gas exploration and production business because
of its small scale of operations and earnings volatility.
     F o r    1997,  TECO  Energy  reported  an  after-tax  loss  from
discontinued  operations  of  $9.5  million  which  included  the  net
operating  results  for  the  year  and also included the write off of
three offshore wells that ceased production.
     In  January  1998, TECO Energy announced that it had entered into
an agreement to sell the offshore assets of TECO Oil & Gas to American
Resources  Offshore,  Inc. (ARO). In March 1998, TECO Oil & Gas closed
this sale for $57.7 million, consisting of $39.2 million in cash and a
subordinated note in the principal amount of $18.5 million. 
     Based on the likely impact of certain economic factors, including
low  oil  and  gas  prices  and  unfavorable  business and operational
developments at ARO, TECO Energy has written off the recorded value of
all  assets  associated  with  the discontinued oil and gas operation,
including  the  $18.5-million  note  and  associated  interest  income
accrued  and  remaining  on-shore  assets.  The  after-tax gain net of
charges  from  discontinued  operations  in  1998 was $6.1 million, or
approximately 5 cents per share.
     In  March  1999,  the company completed a transaction in which it
sold  the  note  from  ARO in return for $500,000 in cash. The company
also  sold  an  option relating to its ARO warrants; in the event such
option  is  exercised,  the company will receive the exercise price of
$600,000.  In a separate transaction, ARO agreed to be responsible for
disputed  joint billing payments of approximately $425,000. As part of
this  settlement,  ARO  also  conveyed  to  the  company an overriding
royalty  interest  in  two offshore Gulf of Mexico blocks. The company
does not expect any future royalty payments to be significant.

YEAR 2000 COMPUTER SYSTEMS READINESS:

Background
     There  is a global awareness that many computer programs use only
two  digits  to  refer  to  a  year  and, therefore, may not correctly
recognize  and  process date information beyond the year 1999. This is
referred to as the "Year 2000" issue.
     The  Year 2000 issue exists in two primary areas of TECO Energy's
operations:  the  critical  business  systems  (such  as the financial
reporting,  procurement,  payroll and customer information and billing
systems)  and the control systems (such as those used in the operation
of  electric  generation, transmission and distribution facilities and
coal mining facilities).
     TECO Energy began work on Year 2000 readiness in August 1995. The
project  is segmented into the following phases: awareness, inventory,
assessment,  renovation, testing and contingency planning. The project
addresses  readiness  at  Tampa  Electric,  Peoples Gas System and the
diversified companies.

Readiness
     TECO  Energy  has  completed  its  assessment  of  all  hardware,
software  and embedded systems and is currently engaged in renovation,


                                  38
testing  and contingency planning. Set forth below is a description of
readiness by functional area.

     Critical Business Systems 
     The critical business systems, including mainframe hardware which
was  replaced  in  July  1998,  have  been substantially renovated and
functionally tested. Mainframe integrated system testing has begun and
is  scheduled  to  be completed in the first half of 1999. Ninety-five
percent  of the renovations to the critical business systems have been
made, which represents 70 percent of the work required to achieve Year
2000  readiness  for  this  part of the project. To assist in assuring
readiness,  the  renovation work and the integration testing are being
handled by separate outside firms.

     Control Systems
     Tampa  Electric  management  believes  that  its transmission and
distribution  systems,  including  energy  management  and control and
related  embedded  systems,  are  now  ready  for  the Year 2000, i.e.
renovated and tested to the extent necessary.
     Tampa  Electric  retained industry specialty firms to assist with
identifying  areas  where  renovations  were  needed  in  the embedded
systems  associated with generator unit controls and with making these
renovations. Ninety percent of these renovations have been made, which
represents  an  estimated  80  percent of the work required to achieve
Year  2000  readiness  for  this  part  of  the  project.  A number of
successful  unit  tests  have  been  conducted  for  Tampa  Electric's
generating  units,  and  all required plant control system renovations
are scheduled to be complete and tested by May 1999.
     Critical systems (those required for uninterrupted operations) in
the other parts of TECO Energy have been renovated, with the exception
of  a  portion  of the Peoples Gas System and the Hardee Power Station
control  systems and a portion of the TECO Coal plant control systems,
which are scheduled to be fully renovated and tested in the first half
of  1999.  Sixty  percent  of  these renovations have been made, which
represents  an  estimated  40  percent of the work required to achieve
Year 2000 readiness for this part of the project.

     Coordination with Others
     TECO  Energy  has  surveyed  its largest suppliers (approximately
1,000)  with  respect  to  their  Year  2000  readiness, including all
providers  of  technology supplies and services, and plans to complete
its  customer survey process in the first half of 1999. As part of its
Year 2000 project, the company will be coordinating with its suppliers
and customers based on their responses to these surveys.
     A t   the  request  of  the  DOE,  the  North  American  Electric
Reliability  Council (NERC) prepared a Year 2000 coordination plan and
preliminary  status report in September 1998 and updated it in January
1999.    A  full  status  report  is  expected  by  July 1999. NERC is
conducting  monthly  readiness  assessment  surveys  and  coordinating
information  sharing  and  contingency  planning  activities among the
member   firms.  The  NERC  activity  addresses  all  aspects  of  the
interconnected   electric  grid.  The  aggregated  results  are  being
reported  to  the  DOE and other regulatory bodies in the U.S., Canada
and  Mexico.  The  Natural  Gas  Council,  through  the  American  Gas
A s sociation,  is  coordinating  similar  processes  within  the  gas
industry,  reporting  to  the  Federal  Energy  Regulatory  Commission
(FERC).  Tampa Electric and Peoples Gas System are active participants
in these industry groups.




                                  39
Costs
     The  total  cost of Year 2000 remediation is expected to be $8 to
$10  million,  which  includes  contracted  resources,  purchases  and
internal labor. An estimated breakdown of project costs is as follows:
Tampa  Electric  -  $6 million, Peoples Gas System - $2.5 million, and
the  diversified  companies - $.5 million. Approximately 40 percent of
the  projected  costs  are  attributable  to testing expenses, and the
remainder  consists  primarily  of  renovation  or  replacement costs.
Through  Dec.  31,  1998,  approximately  $6  million  had been spent,
including  approximately  $1  million spent prior to 1998. The company
expects  to  spend  approximately  $3  million  in  1999 for Year 2000
remediation.

Risks
     TECO  Energy  believes  the  most  reasonably  likely  worst case
scenario  would  be  the  occurrence  of  isolated  outages of limited
duration  for utility customers, similar to those occurring during the
utilities'  storm season. The utilities have assessed the risk of this
scenario,  and  believe  that their contingency efforts, primarily the
ability  to  bypass  automated  controls, would mitigate the effect of
such a scenario. 

Contingency Plans
     TECO  Energy's  contingency  plan is scheduled to be completed by
the  middle  of  1999.  The contingency plan will include a team to be
e s t ablished  in  1999  to  monitor  all  critical  systems  through
significant date transitions and to promptly respond to any problems.

Forward-Looking Statements
     The  costs  of  TECO  Energy's Year 2000 efforts and the dates on
which  the  company  believes  it will complete such efforts are based
upon  management's  best  estimates, which were derived using numerous
a s s u mptions  regarding  future  events,  including  the  continued
availability  of  certain resources, third-party remediation plans and
other  factors.  There  can  be no assurance that these estimates will
prove  to be accurate, and actual results could differ materially from
those  currently  projected.  Specific  factors  that could cause such
differences include, but are not limited to, the availability and cost
of  personnel  trained  in  Year 2000 issues, the ability to identify,
assess,  remediate  and  test all relevant computer codes and embedded
technology and similar uncertainties.

NON-OPERATING ITEMS:

Other Income (Expense)

     Other  income (expense) includes a one-time pretax charge of $7.3
million  at  Tampa  Electric  reflecting  the  FPSC  decision  denying
recovery  of  certain  coal  expenses.  See  Utility Regulation - Cost
Recovery Clauses section. 
     The  dividend  requirement  for  Tampa  Electric preferred stock,
included  in  Other  Income (expense), declined in 1997 reflecting the
redemption  of  all  outstanding  preferred stock. Allowance for other
funds  used  during  construction  (AFUDC) was $.1 million in 1997 and
$16.5  million  in  1996;  no  AFUDC  was  recorded  in 1998. AFUDC is
expected  to be approximately $1-2 million per year over the next five
years.





                                  40
Interest Charges

     Interest  charges  were $104.3 million, down slightly from $105.8
million  in  1997.  Lower  interest  on  a  declining deferred revenue
balance  at  Tampa  Electric and lower short-term rates were partially
offset  by  higher  borrowing  levels  for  new  TECO  Power  Services
initiatives  and  for  interest  on a capital lease of river barges in
1998. 
     Interest  charges  were  up  7  percent in 1997, reflecting lower
AFUDC on borrowed funds at Tampa Electric. 

Income Taxes

     Income tax expense decreased in 1998 as pretax income was reduced
by  $25.9 million of non-recurring charges. In 1997, income taxes were
higher than in 1996, reflecting higher pretax income and the effect of
lower AFUDC on equity funds at Tampa Electric. Income tax expense as a
percent  of  income  from  continuing  operations  before taxes was 29
percent in 1998, 31 percent in 1997 and 27 percent in 1996. 
     Total  income  tax  expense was reduced by the federal tax credit
related  to the production of coalbed methane. This tax credit totaled
$18.9  million  in  1998,  $20.2 million in 1997, and $19.6 million in
1996. The tax credit was $1.07 per Mcf in 1998, up from $1.05 in 1997.
This  rate  escalates  with inflation and could be limited by domestic
oil  prices. In 1998, domestic oil prices would have had to exceed $49
per barrel for this limitation to have been effective. The federal tax
credit  on production of coalbed methane is available through the year
2002. 
     The  income  tax  effect  of  gains  and losses from discontinued
operations  is  shown  as  a  component  of  results from discontinued
operations.

ACCOUNTING STANDARDS:

Accounting for Derivative Instruments and Hedging
     I n   1998,  the  Financial  Accounting  Standards  Board  issued
Financial  Accounting  Standard  (FAS)  133, Accounting for Derivative
Instruments  and  Hedging,  effective for fiscal years beginning after
June  15,  1999.  The  new  standard  requires  an entity to recognize
d e rivatives  as  either  assets  or  liabilities  in  the  financial
statements,  to measure those instruments at fair value and to reflect
the changes in fair value of those instruments as either components of
comprehensive income or in net income, depending on the types of those
instruments.  TECO  Energy does not use derivatives or other financial
products  for speculative purposes. The company has not yet determined
to what extent the standard will impact its financial statements.

Reporting Comprehensive Income
     In 1997, the Financial Accounting Standards Board issued FAS 130,
Reporting  Comprehensive  Income, effective for fiscal years beginning
after  Dec.  15,  1997.  The  new standard requires that comprehensive
income, which includes net income as well as certain changes in assets
and  liabilities  recorded  in  common  equity,  be  reported  in  the
f i n ancial  statements.  For  1998,  there  were  no  components  of
comprehensive income other than net income.

CAPITAL EXPENDITURES:

     TECO  Energy's 1998 capital expenditures of $296 million included
$176  million  for  Tampa Electric, $56 million for Peoples Gas System


                                  41
and $64 million for the diversified companies. Tampa Electric invested
$154  million in 1998 for equipment and facilities to meet its growing
customer  base  and  generating equipment improvements, $16 million to
begin  construction  of  a  flue  gas desulfurization (FGD) system, or
"scrubber"  for  Big  Bend  Units  One  and Two, and $6 million toward
construction  of  Polk  Unit Two, a gas and No. 2 oil-fired combustion
t u rbine.  Capital  expenditures  for  Peoples  Gas  System  included
approximately    $43   million   for   system   expansion,   including
approximately $2.5 million related to its Southwest Florida expansion,
and  approximately $13 million for maintenance of the existing system.
TECO  Transport  invested  $46 million in 1998 for equipment additions
and  normal  equipment  replacement.  TECO  Coal spent $11 million for
mining equipment replacements.
     TECO  Energy  estimates  total  capital  expenditures for ongoing
operations  to  be  $422  million for 1999 and $1.2 billion during the
2000-2003  period.  For  1999,  Tampa  Electric  expects to spend $222
million,  consisting  of  $61 million for a scrubber at Big Bend Power
Station,  $19  million in construction costs on Polk Unit Two and $142
million  for  other  capital  expenditures.  At the end of 1998, Tampa
Electric  had outstanding commitments of about $68 million to complete
the  scrubber  and  $44  million  to  complete  Polk  Unit  Two. Tampa
Electric's  total  capital  expenditures over the 2000-2003 period are
projected  to  be  $706 million, including $194 million for generation
expansion and $6 million to complete the scrubber.
     Capital  requirements  for  Peoples Gas System are expected to be
about $75 million in 1999 and $208 million during the 2000-2003 period
for  infrastructure  expansion  to grow the customer base. Included in
these  amounts  are  $21  million  in  1999  for the Southwest Florida
expansion,  and expenditures of approximately $40 million annually for
other  revenue-producing projects associated with normal system growth
and  expansion.  The  remainder  represents  expenditures  for ongoing
system  maintenance.  At  the end of 1998, $8 million of these amounts
had been committed.
     The  diversified  companies  expect capital expenditures of about
$125  million  in  1999  and $259 million during the 2000-2003 period.
Included  in  these amounts are $65 million at TECO Power Services for
construction  of the San Jose Power Station and identified investments
in  additional  projects. These estimates do not take into account any
other  future  projects which are expected to emerge. Also included in
t h e se  amounts  are  the  acquisition  of  coal  mining  equipment,
acquisition  of  ocean  transportation  equipment and river barges and
normal  asset  replacement.  At  the end of 1998, $34 million of these
amounts had been committed.

ENVIRONMENTAL COMPLIANCE:

     Tampa Electric is complying with the Phase I emission limitations
imposed  by the Clean Air Act Amendments (CAAA) which became effective
Jan. 1, 1995 by using blends of lower-sulfur coal, integrating the Big
Bend Unit Four FGD system with Unit Three, controlling stack emissions
and using emission allowances. In 1998, Tampa Electric made a decision
to  add  a  scrubber in order to comply with Phase II of the CAAA. The
$84  million scrubber will reduce the amount of sulfur dioxide emitted
by  the  Tampa  Electric's  Big  Bend Units One and Two and will allow
significant fuel savings at other Tampa Electric units. As a result of
this  project,  all of the units at Big Bend Station, Tampa Electric's
largest generating station, will be equipped with scrubber technology.
     The  FPSC  approved  the  FGD  system  as the most cost effective
a l t e rnative  for  Tampa  Electric  to  meet  its  CAAA  compliance
requirements  and the recovery of prudently incurred costs through the


                                  42
environmental  cost  recovery  clause.  Cost  recovery will not begin,
however,  until  the  FGD  system is in service and Tampa Electric has
applied for such recovery specifying the costs actually incurred.
     The  U.S.  Environmental Protection Agency (EPA) has commenced an
investigation  under  the  Clean  Air Act of coal-fired electric power
generators  to  determine  compliance  with  environmental  permitting
requirements  associated  with repairs, maintenance, modifications and
operations  changes  made  to the facilities over the years. The EPA's
focus is on whether new source performance standards should be applied
to  the  changes  and, accordingly, whether the best available control
technology  was  or  should  have  been used. Tampa Electric is one of
several electric utilities that have been visited by EPA personnel and
received  a  comprehensive request for information pursuant to Section
114  of  EPA's Clean Air Act regulations. Tampa Electric is furnishing
appropriate information. It believes that it has built, maintained and
operated  its  facilities  in  compliance  with relevant environmental
permitting  requirements.  The timing of completion and the outcome of
the EPA s investigation are uncertain.
     Tampa  Electric  Company  is  a potentially responsible party for
certain  superfund sites and, through its Peoples Gas System division,
for  certain  former manufactured gas plant sites. While the joint and
several  liability  associated with these sites presents the potential
for  significant  response costs, Tampa Electric Company estimates its
ultimate  financial  liability  at  approximately $20 million over the
next  10  years.  The  environmental remediation costs associated with
these  sites  are  not  expected to have a material impact on customer
prices.

UTILITY REGULATION:

Rate Stabilization Strategy
     Tampa  Electric's  objectives  of stabilizing prices through 1999
and  securing fair earnings opportunities during this period are being
accomplished  through  agreements entered into with the Florida Office
of  Public  Counsel (OPC) and the Florida Industrial Power Users Group
(FIPUG) which were approved by the FPSC.
     Prior  to these agreements, the FPSC approved a plan submitted by
Tampa  Electric  to defer certain 1995 revenues. Under this plan Tampa
Electric's  allowed  return  on  equity  increased to an 11.75 percent
midpoint  with  a range of 10.75 percent to 12.75 percent. For 1995 an
initial $15 million of revenues were deferred as well as 50 percent of
actual revenues in excess of a ROE of 11.75 percent up to a net earned
ROE  of 12.75 percent. Also as part of this plan, Tampa Electric's oil
backout  tariff  was  eliminated  as  of January 1996, reducing annual
revenues by approximately $12 million.
     In  1995,  Tampa  Electric deferred $51 million of revenues under
this  plan.  The  deferred  revenues  accrued  interest  at the 30-day
commercial paper rate as specified in the Florida Administrative Code.
     In 1996, the FPSC approved agreements between Tampa Electric, the
OPC  and  the  FIPUG  which  froze base rates for the electric utility
through  1999,  returned $50 million to customers between October 1996
and  December 1998 through refunds and a temporary base rate reduction
and  allowed  full recovery for the capital costs incurred in the Polk
Unit One project. 
     In  addition,  the  agreements  set  forth  multi-year  plans for
allocating  revenues based on Tampa Electric's ROE. For the years 1996
through  1998,  Tampa Electric retained all revenues contributing to a
ROE  of  11.75  percent. Under this plan, any additional revenues were
allocated as follows:
     *In 1996, 40 percent of any actual revenues contributing to a ROE


                                  43
in  excess  of  11.75  percent  were  included  in  1996 revenues. The
remaining  60  percent  were  deferred  for  use in 1997 and 1998. The
company  deferred  $34  million  in 1996. This amount and the deferred
revenues and interest from 1995 (less $25 million of refunds) provided
$68 million for use by the company in 1997 and 1998.
     *In 1997, 40 percent of any revenues that contributed to a ROE in
excess of 11.75 percent up to 12.75 percent were included in revenues.
The  remaining  60  percent  were deferred for use in 1998 as were all
revenues  in  excess  of  12.75  percent.  The  company recognized $31
million  in  1997  of the revenues and interest deferred from 1995 and
1996.
     *In 1998, 40 percent of any revenues that contributed to a ROE in
excess of 11.75 percent up to 12.75 percent were included in revenues.
The  remaining  60  percent, along with all revenues contributing to a
ROE  in excess of 12.75 percent, including deferrals from prior years,
will  be  refunded  to  customers  in  1999.  In  1998, Tampa Electric
recognized  all  of  the remaining deferred revenues and interest from
1995 and 1996, and based on 1998 earnings levels, expects to refund $1
million  to customers in 1999, following audits for the years 1997 and
1998 and final review by the FPSC.
     *For  1999,  60  percent of the revenues contributing to a ROE in
excess  of  12 percent will be refunded to customers in 2000 following
audit  and  review  by  the  FPSC  along  with  any 1999 revenues that
contribute to a ROE above 12.75 percent.
     In  1998,  Tampa  Electric  recorded  $1.1  million  in after-tax
charges  relating to its 1996 earnings as a result of an FPSC audit of
t h a t   year  which  involved  several  adjustments,  including  the
establishment  for  regulatory purposes of an equity ratio cap of 58.7
percent  for  1996  compared  to the actual ratio for the year of 59.5
percent.   Because  of  the  return  on  equity  thresholds  in  Tampa
Electric's regulatory agreements described above and the potential for
customer  refunds  in 1999 and 2000, Tampa Electric expects continuing
audit  scrutiny  by  the FPSC and active involvement of intervenors in
the  proceedings for determining the appropriate level of earnings for
the  remaining  years  of  the  stipulation and the resulting level of
deferrals and/or refunds.
     The  regulatory arrangements described above covered periods that
end  on  Dec.  31,  1999. In the absence of any new arrangement, Tampa
Electric's  rates  and  the  midpoint of its allowed rate of return on
common  equity (11.75 percent) will continue in effect until such time
as  changes  are  occasioned  by  an agreement approved by the FPSC or
other  FPSC  action as a result of rate or other proceedings initiated
by  Tampa  Electric,  FPSC  staff  or  other interested parties. Tampa
Electric  cannot  predict  whether there will be any such agreement or
the potential outcome related to any other proceedings.
     The  effective  implementation of the rate stabilization strategy
has  resulted  in residential retail rates for 1999 that are below $80
per 1,000 kwh, even as Polk Unit One was brought on line. This rate is
almost  10  percent  lower  than  1994  rates  just  prior to the rate
stabilization plan and comparable to rates in 1985.

Wholesale Power Sales Contracts
     In 1997, the FPSC ruled that costs associated with two long-term,
wholesale  power  sales  contracts should be assigned to the wholesale
jurisdiction  for  1997  through  1999.  It further required that, for
retail rate making purposes through the end of the stipulation period,
the  costs  separated  from retail to wholesale should reflect average
costs  rather  than  the  lower  incremental  costs  on  which the two
contracts  were  based.  By  1998,  one  of  these  contracts had been
terminated. 


                                  44
     In  order  to  mitigate  the  impacts of the FPSC's ruling on the
remaining contract, which expires in 2001, Tampa Electric entered into
firm  purchased  power  contracts  with third parties in early 1998 to
provide replacement power through 1999. As a result, Tampa Electric is
no  longer separating the associated generation assets from the retail
jurisdiction.  Because  the  costs  under  the  firm  purchased  power
c o ntracts  exceeded  the  revenues  associated  with  the  remaining
wholesale power sale agreement, Tampa Electric recorded a $9.6-million
pretax charge in the first quarter of 1998. 
     Tampa  Electric  is considering applying to the FPSC for a ruling
that  would provide for more favorable regulatory accounting treatment
after 1999, as well as other mitigation measures.

Cost Recovery Clauses
     In  1998,  the  FPSC  changed its proceedings for the recovery of
fuel,  purchase  power  and  environmental  costs  from semi-annual to
annual.  In  the  November 1998 proceeding for calendar year 1999, the
FPSC  disallowed retroactively to 1992 certain quality adjustments for
coal  purchased  from  a  Tampa  Electric  affiliate  in  excess of an
established  benchmark.  This  resulted in a one-time pretax charge of
$7.3  million  in  1998. In this same proceeding, the FPSC allowed the
recovery of $4.5 million in 1999 for environmental costs, a portion of
which constitutes a return on investment. These recoveries, subject to
annual approval, are expected to continue in future years in declining
amounts as assets depreciate.

Long Range Power Supply Planning
     Tampa  Electric filed a Ten Year Site Plan with the FPSC in April
1998.  An  amended  plan  was  filed  in  August 1998 as the result of
greater-than-expected  growth  in  retail load. Strong demand in 1997,
followed  by  record  energy sales throughout the summer of 1998, were
evidence  of  this  growth.  This  trend  resulted  in a projection of
reserves  falling  below the planning criteria of a 15 percent reserve
margin  prior  to the originally scheduled in service date of the next
proposed  generation  addition  in  2003.  The revised plan includes a
combustion  turbine  with  a  winter rating of 180 MW in January 2001.
Plans  for the addition of an already scheduled combustion turbine for
2003 remain unchanged. 
     These additions are not subject to the FPSC's competitive bidding
requirements  for  capacity  requirements, but they are subject to its
standard  offer. A standard offer is a requirement of the FPSC that is
made to qualifying facilities and municipal solid waste facilities for
purchased  power  in  order  to offset the construction of a new unit.
Construction  of a new unit may be disallowed entirely if enough power
is  contracted.  The quantity of power placed in the standard offer as
well  as the terms and conditions of the contract are specified by the
utility and require the approval of the FPSC. 

Utility Competition: Electric
     Tampa  Electric's  retail electric business is substantially free
from  direct competition with other electric utilities, municipalities
and  public  agencies.  At  the  present  time,  the principal form of
competition  at the retail level consists of self-generation available
to  larger  users  of  electric  energy. Such users may seek to expand
their  options  through  various  initiatives,  including  legislative
and/or  regulatory changes that would permit competition at the retail
level.  One  such  initiative,  which  has apparently been terminated,
involved  the  proposed  merchant  power  plant described below with a
claimed  self  generation  use.  This  is  further  discussed  in  the
Wholesale  Power  Market section which follows. Tampa Electric intends


                                  45
to  take  all  appropriate  actions  to  retain  and expand its retail
business,  including managing costs and providing high-quality service
to retail customers.
     In  1998,  the  FPSC  approved  a  tariff for Tampa Electric that
should assist in reducing the loss of existing at-risk load and assist
in  the  acquisition  of new load. This Commercial/ Industrial Service
Rider  is  a  load  retention  or  economic development contract, that
provides   for  flexible  pricing  to  meet  competitive  alternatives
available to existing or potential new customers.

Wholesale Power Market
     There  is  presently  active  competition  in the wholesale power
markets  in  Florida,  increasing  largely  as  a result of the Energy
Policy  act  of 1992 and related federal initiatives. This Act removed
for  independent  power  producers  certain  regulatory  barriers  and
required  utilities  to  transmit power from such producers, utilities
and others to wholesale customers.
     A  significant  question  to  be  addressed in Florida is whether
merchant  power  plants  should be permitted to serve growing customer
demand  for  electricity.  Merchant  plants  are  built on speculation
without  a  portion  or  all  of  their  capacity committed under firm
purchase   agreements.  Tampa  Electric  believes  that  only  Florida
utilities  or  entities  with contracts for firm capacity to serve the
long-term  needs  of a Florida utility can legally be applicants under
the  Florida  Power  Plant  Siting  Act  (PPSA).  The PPSA governs the
building of new generation involving steam capacity of 75 megawatts or
more  and requires the applicant to demonstrate that a plant is needed
prior to receiving construction and operating permits.
     In  1997,  IMC Agrico (IMCA), a retail customer of Tampa Electric
and  other utilities, and Duke Energy announced that they had signed a
letter  of  intent  for  the  construction  of  a  natural  gas-fired,
combined-cycle power plant with a minimum capacity of 240 megawatts to
serve load currently served by Tampa Electric and two other utilities,
and the merchant wholesale function described above.
     Tampa Electric and others objected to the proposed project on the
grounds  that  it  involved retail transactions within defined service
areas  that are prohibited under existing Florida regulation. In early
1998  and prior to an FPSC-ordered evidentiary hearing to determine if
the proposed project should be considered permitted self-generation or
a  prohibited  retail  sale,  IMCA  withdrew its petition. Duke Energy
subsequently  announced  that  it did not intend to pursue the project
with IMCA.
     In  late  1998, New Smyrna Beach and Duke Energy New Smyrna Beach
Power  Company  Ltd.  applied  for  FPSC  determination  of need for a
proposed 514-megawatt merchant power plant in Volusia County, Florida,
to  supply  30  megawatts  of  capacity  and  associated energy to the
Utilities  Commission  of  the  City  of  New  Smyrna  Beach  with the
remaining  capacity designated for wholesale sales to other utilities.
Tampa Electric and others intervened to oppose this proposal. On March
4, 1999, the FPSC determined that the proponents of the merchant plant
are proper applicants under the PPSA and voted to approve the need for
the  proposed  merchant  plant.  These  decisions  are  expected to be
appealed.  The  proposed  plant  is still subject to environmental and
other regulatory approvals.
     If the FPSC decision is upheld or other regulatory or legislative
actions  are  taken  that allow the construction of wholesale merchant
power  plants,  the  wholesale  operations of Tampa Electric and other
Florida utilities could be adversely affected.




                                  46
Utility Competition: Gas
     Although Peoples Gas System is not in direct competition with any
other  regulated  distributors of natural gas for customers within its
service  areas,  there  are other forms of competition. At the present
time,  the  principal  form  of  competition for residential and small
commercial  customers  is  from  companies  providing other sources of
energy and energy services.
     Competition  is  most  prevalent  in  the  large  commercial  and
industrial  markets.  In recent years, these classes of customers have
been  targeted by companies seeking to sell gas directly, either using
Peoples  Gas  System  facilities  or  transporting  gas  through other
facilities,  thereby  bypassing  Peoples  Gas  System  facilities.  In
response  to  this  competition,  various programs have been developed
including  the  provision  of  transportation  services  at discounted
rates.
     In  general,  Peoples  Gas  System  faces  competition from other
energy  source  suppliers  offering  fuel oil, electricity and in some
cases  propane.  Peoples  Gas  System  has taken actions to retain and
expand  its  commodity and transportation business, including managing
costs and providing high-quality service to customers.

INVESTMENT ACTIVITY:

     At  Dec.  31,  1998,  TECO Energy had $16.9 million in cash, cash
equivalents  and  short-term investments versus $10.6 million at year-
end 1997.
     The  company also has a continuing investment in leveraged leases
of  $57  million. At Dec. 31, 1998, the net leveraged lease investment
was  essentially  a  zero  balance and all leases were performing on a
current  basis. The company has made no investment in leveraged leases
since 1989.

FINANCING ACTIVITY:

     TECO  Energy's  1998  year-end  capital  structure, excluding the
effect  of  unearned  compensation, was 51 percent debt and 49 percent
common  equity.  The  company's  objective  is  to  maintain a capital
structure over time that will support its current credit ratings.

Credit Ratings / Senior Debt
                     Duff & Phelps    Moody's      Standard & Poor's

Tampa Electric Company    AA+           Aa2               AA 
TECO Finance / 
TECO Energy               AA-            A1               AA-

     In  the  second  quarter  of 1998, Tampa Electric Company filed a
registration  statement  for  the  issuance  of  up to $200 million of
medium-term  notes.  In  July  1998, Tampa Electric Company issued $50
million of Remarketed Notes due 2038. The notes, which bear an initial
coupon  rate  of  5.94%,  are  subject to mandatory tender on July 15,
2001,  at which time they will be remarketed or redeemed. Net proceeds
were  $51  million  which included a premium paid to Tampa Electric by
the  remarketing agent for the right to purchase the notes in 2001. If
this  right  is  exercised,  for the following 10 years the Notes will
bear  interest  at  5.41%  plus  a  premium  based  on  Tampa Electric
Company's  then-current  credit  spread  above  United States Treasury
Notes with 10 years to maturity.
     In  the  third  quarter of 1998, TECO Energy filed a registration
statement for the issuance of up to $200 million of medium-term notes.


                                  47
In  September  1998,  TECO  Energy  issued  $150 million of Remarketed
Notes,  due  2038.  The  notes,  which  bear an initial coupon rate of
5.54%,  are  subject  to  mandatory tender on Sept. 15, 2001, at which
time  they  will  be  remarketed  or  redeemed. Net proceeds were $153
million   which  included  a  premium  paid  to  TECO  Energy  by  the
remarketing agent for the right to purchase the notes in 2001. If this
right  is  exercised,  for  the following 10 years the Notes will bear
interest  at  5.41% plus a premium based on TECO Energy's then-current
credit  spread  above  United  States  Treasury Notes with 10 years to
maturity.
     Proceeds from both note issues were used to repay short-term debt
and for general corporate purposes. 
     TECO Energy raised $9.2 million of common equity in 1996 from the
sale  of  common  stock  through  its Dividend Reinvestment and Common
Stock  Purchase  Plan  (DRP). In 1997 and 1998, the DRP purchased TECO
Energy shares on the open market for plan participants. 
     As  a  part  of  its  risk  management  program, during 1995 TECO
Finance  entered  into an interest rate exchange agreement to moderate
its  exposure  to  short-term  interest  rate changes. This three-year
agreement  effectively  converted the interest rate on $100 million of
short-term  debt  from  a  floating rate to a fixed rate. TECO Finance
paid  a fixed rate of 5.8% and received a floating rate based on a 30-
day  commercial  paper  index.  This  agreement, which expired in June
1998,  did  not have a significant impact on interest expense in 1998,
1997 or 1996. 
     TECO  Energy is exposed to changes in interest rates primarily as
a  result  of  its  borrowing  activities.  A  hypothetical 10 percent
increase  in  TECO  Energy's  weighted  average  interest  rate on its
variable  rate  debt  would  not  have  a  significant  impact on TECO
Energy's pretax earnings over the next fiscal year. 
     A  hypothetical  10  percent decrease in interest rates would not
have a significant impact on the estimated fair value of TECO Energy's
long-term debt at Dec. 31, 1998.
     Based  on  policies  and  procedures  approved  by  the  Board of
Directors,  from  time  to time TECO Energy enters into futures, swaps
and  option  contracts  to  moderate  its  exposure  to  interest rate
changes.  The  benefits  of these arrangements are at risk only in the
event  of  non-performance  by the other party to the agreement, which
the company does not anticipate. 
     Based  on  policies  and  procedures  approved  by  the  Board of
Directors,  from  time  to time TECO Energy enters into futures, swaps
and  options  contracts  to  hedge  the selling price for its physical
production  at  TECO  Coalbed  Methane, to limit exposure to gas price
increases  at  both  the regulated natural gas utility and unregulated
propane  business,  and  to  limit exposure to fuel price increases at
TECO  Transport.  The  benefits of these financial arrangements are at
risk  only  in  the event of non-performance by the other party to the
agreement, which the company does not anticipate.
     T E CO  Energy  does  not  use  derivatives  or  other  financial
instruments for speculative purposes.

LIQUIDITY, CAPITAL RESOURCES:

     TECO  Energy  and  its  operating companies met cash needs during
1998 largely with internally generated funds, with the balance of cash
needs coming from net borrowings.
     At  Dec.  31,  1998,  TECO  Energy  had bank credit lines of $485
million, all of which were available. 
     TECO  Energy  anticipates  meeting  its  capital requirements for
o n going  operations  in  the  1999-2003  period  substantially  from


                                  48
internally generated funds. TECO Power Services expects to finance the
San  Jose  Power  Station with limited-recourse project financing upon
commercial operation.

INVESTMENT CONSIDERATIONS:

     The following are certain factors that could affect TECO Energy's
f u ture  results.  They  should  be  considered  in  connection  with
evaluating  forward-looking  statements  contained  in this report and
otherwise made by or on the behalf of TECO Energy, since these factors
could  cause  actual  results and conditions to differ materially from
those projected in these forward-looking statements.
     G e neral  Economic  Conditions.  The  company's  businesses  are
dependent on general economic conditions. In particular, the projected
growth in Tampa Electric's service area and in Florida is important to
the  realization  of  Tampa  Electric's and the Peoples Gas companies'
forecasts for annual energy sales growth. An unanticipated downturn in
the  local  area's  or  Florida's economy could adversely affect Tampa
Electric's or the Peoples Gas companies' performance.
     The  activities  of the diversified businesses, particularly TECO
Transport  and  TECO  Coal,  are  also  affected  by  general economic
conditions  in  the  respective  industries  and geographic areas they
serve, both nationally and internationally.
     Weather Variations. Most of TECO Energy's businesses are affected
by  variations  in  general  weather  conditions  and unusually severe
weather.  Tampa Electric's and the Peoples Gas companies' energy sales
are  particularly  sensitive  to variations in weather conditions. The
TECO  Energy  companies  forecast  energy sales on the basis of normal
weather,  which represents a long-term historical average. Significant
variations  from normal weather could have a material impact on energy
sales.  Unusual weather, such as hurricanes, could also have an effect
on operating costs as well as sales.
     Peoples  Gas  System  and  Peoples  Gas  Company are more weather
sensitive, with a single winter peak period, than Tampa Electric, with
both  summer  and  winter peak periods. Mild winter weather in Florida
can  be  expected  to  negatively  impact  results  at the Peoples Gas
companies.
     Variations  in  weather  conditions  also  affect  the demand and
prices for the commodities sold by TECO Coalbed Methane and TECO Coal.
TECO  Transport  also is impacted by weather because of its effects on
the  supply of and demand for the products transported. Severe weather
conditions that could interrupt or slow service and increase operating
costs also affects these businesses.
     Potential  Competitive  Changes.  The  electric industry has been
undergoing certain restructuring. Competition in wholesale power sales
has  been introduced on a national level. Some states have mandated or
encouraged  competition  at  the  retail level, and in some situations
required  divestiture  of  generating  assets.  While  there is active
wholesale  competition  in  Florida,  the retail electric business has
remained  substantially  free  from direct competition. Changes in the
competitive  environment occasioned by legislation, regulation, market
conditions  or initiatives of other electric power providers, however,
particularly  with  respect  to  retail  competition,  could adversely
affect  Tampa  Electric's  business and its performance. The company's
long-range  projections  are  based on its expectation that there will
not   be  any  significant  change  in  Tampa  Electric's  competitive
environment. 
     The  gas  distribution  industry  has been subject to competitive
forces  for  several  years.  Further  unbundling of gas service could
adversely affect Peoples Gas System.


                                  49
     Regulatory Actions. Tampa Electric and Peoples Gas System operate
in highly regulated industries. Their retail operations, including the
prices  charged,  are  regulated  by  the  FPSC,  and Tampa Electric's
wholesale  power  sales  and  transmission  services  are  subject  to
regulation  by  FERC.  Changes  in  regulatory requirements or adverse
regulatory actions could have an adverse effect on Tampa Electric's or
Peoples Gas System's performance. 
     Commodity  Price  Changes.  Most  of TECO Energy's businesses are
sensitive  to  changes in certain commodity prices. Such changes could
affect   the  prices  they  charge,  their  operating  costs  and  the
competitive position of their products and services. 
     In the case of Tampa Electric, fuel costs used for generation are
mostly affected by the cost of coal. Tampa Electric is able to recover
the  cost  of  fuel  through retail customers' bills, but increases in
fuel  costs  affect  electric  prices  and  therefore  the competitive
position of electricity against other energy sources. On the wholesale
side,  the  ability  to  make sales and the margins on power sales are
affected  by  the  cost  of coal to Tampa Electric, particularly as it
relates to the cost of gas and oil to other power producers.
     In  the  case  of Peoples Gas System, costs for purchased gas and
pipeline  capacity  are recovered through retail customers' bills, but
increases  in  gas  costs affect total retail prices and therefore the
competitive  position  of  Peoples  Gas relative to electricity, other
forms of energy and other gas suppliers.
     At  the  diversified  companies,  changes  in gas and coal prices
directly  affect  the  margins  at TECO Coalbed Methane, TECO Coal and
TECO  Transport.  TECO  Coalbed  Methane is exposed to commodity price
risk  through  the  sale  of  natural  gas. A 10 percent change in the
market  price  of  natural  gas would not have a significant impact on
TECO  Energy's  earnings. TECO Coal is exposed to commodity price risk
through coal sales. A 10 percent change in the market price of coal in
any  one  year  would  not  have a significant impact on TECO Energy's
earnings for that year. 
     Gas  Production  Levels.  Results  at  TECO  Coalbed  Methane are
affected  by its level of production which is declining. The company's
long-range forecast assumes that production will decline approximately
9  percent  annually.  Actual production levels may be greater or less
than those assumed.
     Business  Growth  Opportunities. Part of the company's previously
announced long-term strategy is to grow its diversified business. Much
of  its targeted growth is dependent on the ability to find attractive
acquisition   and  development  opportunities  and  independent  power
p r o jects.  The  company's  long-range  forecast  is  based  on  its
expectation  that it will be successful in finding and capitalizing on
these  acquisition and development opportunities and independent power
projects,  but  there  can  be  no  assurance that its efforts will be
successful.
     International  Risks.  TECO Power Services is involved in several
i n t e rnational  projects  and  expects  to  enter  into  additional
international  projects  during  the  next  few  years. These projects
involve  numerous  risks  that  are  not present in domestic projects,
including expropriation, political instability, currency exchange rate
fluctuations,  repatriation  restrictions,  and  regulatory  and legal
uncertainties.  The  company's  long-range  forecast assumes that TECO
Power  Services  will  mitigate  losses  associated  with  these risks
through  a  variety  of  risk  mitigation measures, including specific
contractual  provisions,  teaming  with strong international and local
partners, obtaining limited-recourse financing and, where appropriate,
obtaining political risk insurance.
     Environmental  Matters.  TECO  Energy's businesses are subject to


                                  50
regulation by various governmental authorities dealing with air, water
and other environmental matters. Changes in compliance requirements or
the   interpretation   by   governmental   authorities   of   existing
requirements  may  impose additional costs on the company or result in
the curtailment of some activities.


Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk
     TECO  Energy is exposed to changes in interest rates primarily as
a result of its borrowing activities.
     From  time  to time, TECO Energy or its affiliates may enter into
futures,  swaps  and option contracts to moderate exposure to interest
rate changes.
     See  the  discussion  of  interest  rate  risk  in  the Financing
Activity section on page 48.

Commodity Price Risk
     Currently,  at  Tampa  Electric and Peoples Gas System, commodity
price  increases  due  to  changes  in  market  conditions  for  fuel,
purchased  power  and  natural gas are recovered through cost recovery
clauses, with no effect on earnings.
     TECO  Coalbed  Methane is exposed to commodity price risk through
the  sale  of natural gas, and TECO Coal is exposed to commodity price
risk through coal sales.
     From  time  to time, TECO Energy or its affiliates may enter into
futures,  swaps  and  options contracts to hedge the selling price for
physical  production at TECO Coalbed Methane, to limit exposure to gas
price  increases  at  both  the  regulated  natural  gas  utility  and
unregulated  propane  business,  or  to  limit  exposure to fuel price
increases at TECO Transport.
     See  the  discussions  of  commodity price risks in the Financing
Activities  section on page 48 and in the Investment Considerations --
Commodity Price Changes section on page 50.

     TECO  Energy  and  its affiliates do not use derivatives or other
financial products for speculative purposes.
























                                  51
Item 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                                                  Page
                                                                   No.

Report of Independent Accountants                                   53

Consolidated Balance Sheets, Dec. 31, 1998 and 1997                 54

Consolidated Statements of Income for the years ended 
 Dec. 31, 1998, 1997 and 1996                                       55

Consolidated Statements of Cash Flows for the years
 ended Dec. 31, 1998, 1997 and 1996                                 56

Consolidated Statements of Common Equity for the years
 ended Dec. 31, 1998, 1997 and 1996                                 57

Notes to Consolidated Financial Statements                       58-80


     Financial  Statement  Schedules  have been omitted since they are
not   required,  are  inapplicable  or  the  required  information  is
presented in the financial statements or notes thereto.




































                                  52
REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors
and shareholders of
of TECO Energy, Inc.

     In  our opinion, the accompanying consolidated balance sheets and
the  related  consolidated  statements of income, of cash flows and of
common  equity present fairly, in all material respects, the financial
position  of  TECO  Energy, Inc. and its subsidiaries at Dec. 31, 1998
and 1997, and the results of their operations and their cash flows for
each  of  the  three  years  in  the  period  ended  Dec. 31, 1998, in
conformity   with  generally  accepted  accounting  principles.  These
f i n ancial  statements  are  the  responsibility  of  the  company's
management;  our  responsibility  is  to  express  an opinion on these
financial  statements  based on our audits. We conducted our audits of
these  financial  statements  in  accordance  with  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.


                                            PricewaterhouseCoopers LLP
                                                                      
Tampa, Florida
Jan. 15, 1999, except for certain
information included in Note I,
for which the date is March 26, 1999





























                                  53
                            CONSOLIDATED BALANCE SHEETS
                                    (millions)
                                      Assets
Dec. 31,                                 1998           1997 
Current Assets
Cash and cash equivalents            $   16.9       $   10.6 
Receivables, less allowance 
     for uncollectibles                 229.6          222.7 
Inventories, at average cost
 Fuel                                    93.2           80.8 
 Materials and supplies                  64.1           63.1 
Prepayments                              15.1           12.9 
                                        418.9          390.1 
Property, Plant and Equipment, 
     at Original Cost
Utility plant in service
 Electric                             3,991.3        3,880.6 
 Gas                                    518.5          471.1 
Construction work in progress           101.1           57.0 
Other property                          989.6          950.8 
                                      5,600.5        5,359.5 
Accumulated depreciation             (2,292.9)      (2,123.0)
                                      3,307.6        3,236.5 
Other Assets
Other investments                        72.0           88.3 
Deferred income taxes                    99.1           88.1 
Deferred charges and other assets       281.7          157.4 
                                        452.8          333.8 
                                     $4,179.3       $3,960.4 

                             Liabilities and Capital
Current Liabilities
Long-term debt due within one year   $   36.0       $   12.7 
Notes payable                           319.0          447.5 
Accounts payable                        208.1          158.7 
Customer deposits                        78.3           77.9 
Interest accrued                         14.2           21.8 
Taxes accrued                             5.1           14.0 
                                        660.7          732.6 
Other Liabilities  
Deferred income taxes                   499.9          470.9 
Investment tax credits                   46.7           51.7 
Regulatory liability-tax related         34.0           35.1 
Other deferred credits                  150.6          145.2 
Long-term debt, less amount 
     due within one year              1,279.6        1,080.2 

Capital
Common equity                         1,569.2        1,512.2 
Unearned compensation                   (61.4)         (67.5)
                                     $4,179.3       $3,960.4 

The  accompanying notes are an integral part of the consolidated financial
statements.








                                     54
                     CONSOLIDATED STATEMENTS OF INCOME
                                 (millions)

Year ended Dec. 31,                       1998         1997       1996 

Revenues                             $1,958.1     $ 1,862.3    $ 1,775.3 
Expenses
Operation                             1,030.1         966.6        955.5 
Maintenance                             128.9         114.2         97.4 
Non-recurring charges                    25.9            --           -- 
Depreciation                            228.3         225.4        202.8 
Taxes, other than income                149.4         143.5        137.8 
                                      1,562.6       1,449.7      1,393.5 

Income from Operations                  395.5         412.6        381.8 
     
Other Income (Expense)
Allowance for other funds used
 during construction                       --           0.1         16.5 
Other income (expense)                   (9.8)         (0.3)         1.4 
Preferred dividend requirements of            
 Tampa Electric                            --          (0.5)        (1.8)
                                         (9.8)         (0.7)        16.1 
Income Before Interest and
 Income Taxes                           385.7         411.9        397.9 
Interest Charges
Interest expense                        104.3         105.9        105.1 
Allowance for borrowed funds
 used during construction                  --          (0.1)        (6.4)
                                        104.3         105.8         98.7 
Income Before Provision for                   
 Income Taxes                           281.4         306.1        299.2 
Provision for income taxes               81.0          94.7         81.8 
Net income from continuing                                  
 operations                             200.4         211.4        217.4 
Net Loss from Discontinued 
 Operations, net of income tax 
 benefit of $3.5 million and $0.5 
 million for 1997 and 1996,
 respectively                              --          (6.5)        (0.9)
Gain (Loss) on Disposal of 
 Discontinued Operations, net of 
 income tax expense of $3.9 million
 for 1998 and income tax benefit of 
 $1.6 million for 1997                    6.1          (3.0)          -- 
Net Income                           $  206.5     $   201.9    $   216.5 

Average common shares 
 outstanding during year                131.7         130.8        129.3    

Earnings per Average Common Share 
 Outstanding
 From continuing operations                   
    --Basic                          $   1.52     $    1.62    $    1.68 
    --Diluted                        $   1.52     $    1.61    $    1.67 

 Net income
    --Basic                          $   1.57     $    1.54    $    1.67 
    --Diluted                        $   1.57     $    1.54    $    1.67 

The  accompanying  notes are an integral part of the consolidated financial
statements.








                                     55
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (millions)
Year ended Dec. 31,                       1998         1997         1996 
Cash Flows from Operating Activities
Net income                            $ 206.5       $ 201.9      $ 216.5 
Adjustments to reconcile net income to
  net cash from operating activities
 Depreciation                           228.3         225.4        202.8 
 Deferred income taxes                   14.6          (1.9)         9.7 
 Investment tax credits, net             (5.0)         (5.0)        (5.1)
 Allowance for funds used 
  during construction                      --          (0.2)       (22.9)
 Amortization of unearned 
  compensation                            7.8           5.9          5.4 
 Loss (gain) on disposal of
 discontinued operations, pretax        (10.0)           --           -- 
 Deferred revenue                       (38.3)        (30.5)        34.2 
 Deferred recovery clause                17.4           2.7          7.4 
 Refund to customers                       --         (19.8)        (6.0)
 Non-recurring charges                   33.2            --           -- 
 Receivables, less allowance for 
  uncollectibles                         (6.9)          6.4        (26.3)
 Inventories                            (13.5)        (21.4)         7.6 
 Taxes accrued                           (8.8)         (0.9)        (1.6)
 Interest accrued                        (7.7)          1.6          2.8 
 Accounts payable                        47.3          (2.8)        (9.6)
 Other                                   25.5         (10.6)        (1.3)
                                        490.4         350.8        413.6 
Cash Flows from Investing Activities
 Capital expenditures                  (296.1)       (212.6)      (296.3)
 Allowance for funds used 
  during construction                      --           0.2         22.9 
 Investment in short-term investments      --            --         32.3 
 Net proceeds from sale of assets        37.5            --           -- 
 Investment in unconsolidated 
     affiliates                        (135.1)         (4.9)          -- 
 Other non-current investments            7.8           6.9          2.8 
                                       (385.9)       (210.4)      (238.3)
Cash Flows from Financing Activities
 Common stock                             6.7           5.1         13.9 
 Proceeds from long-term debt           201.2          29.3         78.1 
 Repayment of long-term debt            (16.2)       (103.8)       (34.0)
 Net increase (decrease) in 
     credit lines                          --         (49.8)        (6.2)
 Net increase (decrease) in 
     short-term debt                   (128.5)        141.2        (55.8)
 Redemption of preferred stock             --         (20.4)       (35.5)
 Dividends                             (161.4)       (147.3)      (134.2)
                                        (98.2)       (145.7)      (173.7)
Net increase (decrease) in 
 cash and cash equivalents                6.3          (5.3)         1.6 
Cash and cash equivalents at 
 beginning of year                       10.6          15.9         14.3 
Cash and cash equivalents at 
     end of year                      $  16.9       $  10.6      $  15.9 

Supplemental Disclosure of Cash Flow Information
Cash paid during the year for
 Interest (net of amounts capitalized)$  99.3        $115.5       $ 93.8 
 Income taxes                         $  66.2        $ 97.4       $ 87.1 

The  accompanying  notes are an integral part of the consolidated financial
statements.

                                     56

                              CONSOLIDATED STATEMENTS OF COMMON EQUITY
                                             (millions)

                                               Additional                                Total 
                                       Common    Paid-in   Retained      Unearned       Common 
                           Shares(1)     Stock    Capital  Earnings  Compensation       Equity 
                                                                    
Balance, Dec. 31, 1995         128.8    $128.8    $332.3   $  878.1        $(74.2)    $1,265.0 
 Net income for 1996                                          216.5                      216.5 
 Common stock issued             0.9       0.9      17.2                     (1.9)        16.8 
 Cash dividends declared                                     (134.2)                    (134.2)
 Amortization of unearned
  compensation                                                                5.4          5.4 
 Premium on redemption of
  preferred stock                                              (0.5)                      (0.5)
 Tax benefits-ESOP dividends
  and stock options                                  0.9        2.2                        2.5 
Balance, Dec. 31, 1996         129.7     129.7     350.4      962.1         (70.7)     1,371.5 
 Net income for 1997                                          201.9                      201.9 
 Common stock issued             0.4       0.4       7.3                     (2.7)         5.0 
 Common stock issued-
  West Florida Gas Inc. merger   0.8       0.8      (1.1)       5.8                        5.5 
 Cash dividends declared                                     (147.3)                    (147.3)
 Amortization of unearned
  compensation                                                                5.9          5.9 
 Tax benefits-ESOP dividends
  and stock options                                  0.1        2.1                        2.2 
Balance, Dec. 31, 1997         130.9     130.9     356.7    1,024.6         (67.5)     1,444.7 
 Net income for 1998                                          206.5                      206.5 
 Common stock issued             0.5       0.5       7.2                     (1.7)         6.0 
 Common stock issued-
  Griffis, Inc. merger           0.6       0.6                  0.8                        1.4 
 Dividends declared                                          (161.4)                    (161.4)
 Amortization of unearned
  compensation                                                                7.8          7.8 
 Tax benefits-ESOP dividends
  and stock options                                   0.7       2.1                        2.8 
Balance, Dec. 31, 1998         132.0    $132.0     $364.6  $1,072.6        $(61.4)    $1,507.8 

The accompanying notes are an integral part of the consolidated financial
statements.

(1) TECO  Energy  had  400  million  shares  of  $1 par value common stock
    authorized in 1998, 1997 and 1996.


                                     57


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A.   Summary of Significant Accounting Policies

Principles of Consolidation
     The   significant  accounting  policies  for  both  utility  and
diversified operations are as follows:
     The  consolidated  financial  statements include the accounts of
TECO  Energy,  Inc. (TECO Energy or the company) and its wholly owned
subsidiaries, including the Peoples Gas companies acquired in 1997.
     The   equity  method  of  accounting  is  used  to  account  for
investments  in  partnership arrangements in which TECO Energy or its
subsidiary  companies  do  not  have  majority  ownership or exercise
control.
     T h e  proportional  share  of  expenses,  revenues  and  assets
reflecting  TECO  Coalbed  Methane's  and  TECO  Oil & Gas  undivided
interest  in  joint  venture property is included in the consolidated
financial statements.
     All   significant   intercompany   balances   and   intercompany
transactions have been eliminated in consolidation.

Basis of Accounting
     Tampa  Electric and Peoples Gas System (the regulated utilities)
maintain  their  accounts  in  accordance  with  recognized  policies
prescribed  or  permitted  by  the  Florida Public Service Commission
(FPSC).    In  addition,  Tampa  Electric  maintains  its accounts in
accordance  with  recognized  policies prescribed or permitted by the
Federal  Energy  Regulatory Commission (FERC). These policies conform
with   generally  accepted  accounting  principles  in  all  material
respects.
     The  impact  of  Financial  Accounting  Standard  (FAS)  No. 71,
Accounting  for  the Effects of Certain Types of Regulation, has been
minimal  in  the experience of the regulated utilities, but when cost
recovery  is  ordered  over a period longer than a fiscal year, costs
are  recognized  in  the period that the regulatory agency recognizes
them  in  accordance  with  FAS 71. Also as provided in FAS 71, Tampa
Electric  has  deferred  revenues  in  accordance  with  the  various
regulatory agreements approved by the FPSC in 1995 and 1996. Revenues
are  recognized  as  allowed  in 1997 and 1998 under the terms of the
agreements.
     The  regulated  utilities    retail business is regulated by the
FPSC  and  Tampa  Electric s wholesale business is regulated by FERC.
Prices  allowed, with respect to Tampa Electric, by both agencies are
generally  based  on  recovery  of  prudent  costs  incurred  plus  a
reasonable return on invested capital.
     The use of estimates is inherent in the preparation of financial
s t a t ements  in  accordance  with  generally  accepted  accounting
principles.

Revenues and Fuel Costs
     Revenues  include  amounts  resulting from cost recovery clauses
which  provide  for  monthly  billing charges to reflect increases or
decreases in fuel, purchased capacity, conservation and environmental
costs  for  Tampa  Electric  and  purchased  gas, interstate pipeline
capacity  and  conservation  costs  for  Peoples  Gas  System.  These
adjustment  factors  are  based  on  costs  projected  for a specific
recovery period. Any over-recovery or under-recovery of costs plus an
interest  factor  are  taken  into  account in the process of setting

                                  58


adjustment  factors  for subsequent recovery periods. Over-recoveries
of  costs  are  recorded as deferred credits, and under-recoveries of
costs are recorded as deferred debits.
     In  August 1996, the FPSC approved Tampa Electric's petition for
recovery  of  certain  environmental  compliance  costs  through  the
Environmental Cost Recovery Clause.
     In  December  1994,  Tampa  Electric bought out a long-term coal
supply  contract  which  would  have  expired  in 2004 for a lump sum
payment  of $25.5 million and entered into two new contracts with the
supplier. The coal supplied under the new contracts is competitive in
price  with  coal  of comparable quality. As a result of this buyout,
Tampa  Electric  customers  will  benefit  from  anticipated net fuel
savings  of  more than $40 million through the year 2004. In February
1995,  the  FPSC authorized the recovery of the $25.5-million buy-out
amount  plus carrying costs through the Fuel and Purchased Power Cost
Recovery  Clause  over the 10-year period beginning April 1, 1995. In
1998,  1997 and 1996, $2.7 million of buy-out costs were amortized to
expense.
     Certain  other  costs  incurred  by  the regulated utilities are
allowed to be recovered from customers through prices approved in the
regulatory  process.  These  costs  are  recognized as the associated
revenues are billed.
     The  regulated  utilities  accrue  base  revenues  for  services
rendered  but  unbilled  to provide a closer matching of revenues and
expenses.
     In  May  1996,  the  FPSC issued an order approving an agreement
among  Tampa  Electric,  the  Office  of Public Counsel (OPC) and the
Florida Industrial Power Users Group (FIPUG) regarding 1996 earnings.
This agreement provided for a $25-million revenue refund to customers
to  be  made  over  the  12-month period beginning Oct. 1, 1996. This
refund  consisted  of  $15 million of revenues deferred from 1996 and
$10 million of revenues deferred from 1995, plus accrued interest.
     In  October  1996,  the  FPSC  approved an agreement among Tampa
Electric,  OPC  and FIPUG that resolved all pending regulatory issues
associated with the Polk Power Station. The agreement allows the full
recovery  of  the  capital  costs incurred in the construction of the
Polk  Power  Station  project, and calls for an extension of the base
rate  freeze  established  in  the  May  agreement  through 1999. The
October  agreement also established a $25-million temporary base rate
reduction  reflected  as  a  credit on customer bills over a 15-month
period.  The  reduction began Oct. 1, 1997 which immediately followed
the $25-million refund in the May agreement.

Depreciation
     TECO Energy provides for depreciation primarily by the straight-
line method at annual rates that amortize the original cost, less net
salvage, of depreciable property over its estimated service life. The
provision  for utility plant in service, expressed as a percentage of
the original cost of depreciable property, was 4.1% for 1998 and 4.0%
for 1997 and 1996.
     The original cost of utility plant retired or otherwise disposed
of  and  the  cost of removal less salvage are charged to accumulated
depreciation.

Asset Impairment
     The  company  periodically  assesses  whether  there  has been a
permanent impairment of its long-lived assets and certain intangibles
held  and used by the Company, in accordance with FAS 121, Accounting

                                  59


for  the  Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed  of.  In  1998,  TECO  Coal  Corporation recorded a one-time
after-tax  charge  of $8.9 million to adjust assets values of certain
mining  operations,  and  TeCom, Inc. recorded an after-tax charge of
$1.7  million  to write off product development costs associated with
InterLane  features developed early in the product life and no longer
incorporated  in the current system's design. No write-down of assets
due to impairment was required in 1997 or 1996.

Reporting Comprehensive Income
     In  1997,  the  Financial  Accounting Standards Board issued FAS
130,  Reporting  Comprehensive  Income,  effective  for  fiscal years
beginning  after  Dec.  15,  1997.  The  new  standard  requires that
comprehensive  income,  which  includes net income as well as certain
changes  in  assets  and  liabilities  recorded  in common equity, be
reported  in  the  financial  statements. There were no components of
comprehensive  income  other than net income for the years ended Dec.
31, 1998, 1997 and 1996.

Foreign Operations
     The  functional currency of the company's foreign investments is
primarily  the  U.S.  dollar.  Transactions in the local currency are
remeasured  to  the U.S. dollar for financial reporting purposes with
aggregate  transaction  gains  or  losses included in net income. The
aggregate transaction gains or losses included in net income in 1998,
1997 and 1996 were not significant.
     The  investments  are  generally  protected from any significant
currency  gains  or losses by the terms of the power sales agreements
and  other  related  contracts, in which payments are defined in U.S.
dollars.

Deferred Income Taxes
     TECO  Energy utilizes the liability method in the measurement of
deferred  income  taxes.  Under  the  liability method, the temporary
differences  between  the financial statement and tax bases of assets
and  liabilities  are  reported as deferred taxes measured at current
tax  rates.  Tampa Electric and Peoples Gas System are regulated, and
their  books  and  records  reflect  approved  regulatory  treatment,
including  certain  adjustments  to accumulated deferred income taxes
and  the  establishment  of  a corresponding regulatory tax liability
reflecting the amount payable to customers through future rates.

Investment Tax Credits
     Investment  tax  credits  have been recorded as deferred credits
and  are being amortized to income tax expense over the service lives
of the related property.

Allowance for Funds Used During Construction (AFUDC)
     AFUDC is a non-cash credit to income with a corresponding charge
to  utility  plant  which represents the cost of borrowed funds and a
reasonable return on other funds used for construction. The rate used
to  calculate  AFUDC  is  revised periodically to reflect significant
changes  in  Tampa Electric's cost of capital. The rate was 7.79% for
1998,  1997  and 1996. Total AFUDC for 1997 and 1996 was $0.2 million
and $22.9 million, respectively. There were no qualifying projects in
1998.  The  base  on  which AFUDC is calculated excludes construction
work in progress which has been included in rate base.


                                  60


Capitalized Development Costs
     TeCom,  a  subsidiary  of  TECO Energy, is developing for market
advanced  energy management and automation systems for commercial and
residential applications. TeCom capitalized product development costs
of  $6.8  million  in  1998, $6.5 million in 1997 and $4.9 million in
1996.  The  costs  capitalized since 1996 and those anticipated to be
capitalized  during  the  product  enhancement  period  are  will  be
amortized over the expected life of the products, generally estimated
to  be  the  4-year  period  after  they become available for general
distribution.  Amortization  expense,  which began in September 1998,
for  products that have reached general availability was $0.8 million
in 1998.

Interest Capitalized
     Interest  costs  for  the construction of non-utility facilities
are capitalized and depreciated over the service lives of the related
property.

Cash Equivalents
     C a s h    equivalents  are  highly  liquid,  high-quality  debt
instruments  purchased  with a maturity of three months or less.  The
carrying  amount  of  cash equivalents approximated fair market value
because  of  the  short maturity of these instruments.  The amount of
cash  equivalents  outstanding  at  Dec.  31,  1998  and 1997 was not
significant.

Other Investments
     Other   investments  include  longer-term  passive  investments,
primarily leveraged leases.

Coalbed Methane Gas Properties
     TECO Coalbed Methane, a subsidiary of TECO Energy, has developed
jointly  the  natural  gas  potential in a portion of Alabama's Black
Warrior Basin.
     TECO  Coalbed  Methane utilizes the successful efforts method to
account  for  its gas operations. Under this method, expenditures for
unsuccessful exploration activities are expensed currently.
     Capitalized costs are amortized on the unit-of-production method
u s i ng  estimates  of  proven  reserves.  Investments  in  unproven
properties  and  major  development  projects are not amortized until
proven  reserves  associated  with  the projects can be determined or
until impairment occurs.
     Aggregate capitalized costs related to wells producing and under
development  at Dec. 31, 1998 and 1997 were $210.3 million and $209.1
million  respectively.  Net proven reserves at Dec. 31, 1998 and 1997
were as follows:

Net Proven Reserves - Coalbed Methane Gas

(billion cubic feet)              1998           1997  
Proven reserves, 
  beginning of year               195.0          190.4 
Production                        (17.6)         (19.2)
Revisions of previous estimates   (15.6)          23.8 
Proven reserves, end of year      161.8          195.0 
Number of wells                     655            669 

Hedges - Fuel Prices

                                  61


     TECO Energy enters into futures and options contracts, from time
to  time,  to  hedge  the  selling  price  for TECO Coalbed Methane s
physical production, and to limit its exposure to gas price increases
in  both the regulated Peoples Gas System and the unregulated propane
business,  and  oil  price  increases in the transportation business.
TECO Energy does not use derivatives or other hedging instruments for
speculative purposes.

Accounting for Derivative Instruments and Hedging
     In  1998,  the  Financial  Accounting Standards Board issued FAS
133, Accounting for Derivative Instruments and Hedging, effective for
fiscal years beginning after June 15, 1999. The new standard requires
that  an entity recognize derivatives as either assets or liabilities
in  the  financial  statements,  to measure those instruments at fair
value  and  to reflect the changes in fair value of those instruments
as either components of comprehensive income or net income, depending
on  the  types  of  those  instruments.  TECO  Energy  does  not  use
derivatives or other financial products for speculative purposes. The
company  has  not  yet  determined  to  what extent the standard will
impact its financial statements.

Mergers
     In  June  1997,  TECO  Energy  completed  its  merger with Lykes
Energy,  Inc.  (the  Peoples companies) and issued approximately 12.1
million shares of its common stock.  Concurrent with this merger, the
regulated  gas  distribution  utility,  Peoples Gas System, Inc., was
merged  into  Tampa  Electric Company and now operates as the Peoples
Gas System division of Tampa Electric Company.
     Also  in  June  1997, TECO Energy completed its merger with West
Florida  Gas  Inc. (West Florida) and issued approximately .8 million
shares  of  its  common  stock.    Concurrent  with this merger, West
Florida  s  regulated  gas distribution utility, West Florida Natural
Gas  Company, was merged into Tampa Electric Company and now operates
as part of the Peoples Gas System division.
     These  mergers  were accounted for as poolings of interests and,
accordingly,  the company s Consolidated Balance Sheet as of Dec. 31,
1997 and its Consolidated Statements of Income and Cash Flows for the
period  ended  Dec.  31,  1997  include  the  results  of the Peoples
companies and West Florida.
     In  January  1998,  the  company acquired an unregulated Florida
propane  business,  Griffis,  Inc.  (Griffis) and its affiliate, U.S.
Propane,  Inc.,  in  a merger transaction and issued approximately .6
million  shares  of  its common stock. These acquired businesses were
then merged into and now operate as part of Peoples Gas Company.
     Financial statements and all financial information presented for
periods  prior  to  1997 have been restated to include the results of
the  Peoples  Gas  companies.  Prior period financial statements have
not been restated to reflect the operations and financial position of
West Florida and Griffis due to their size.

Reclassifications and Restatements
     Certain  prior  year  amounts  were  reclassified or restated to
conform with current year presentation.






                                  62
B.   Common Equity

Stock-Based Compensation
     In  April  1996,  the  shareholders  approved  the  1996  Equity
Incentive  Plan  (the "1996 Plan"). The 1996 Plan superseded the 1990
Equity  Incentive  Plan  (the  "1990 Plan") which superseded the 1980
Stock  Option  and  Appreciation Rights Plan (the "1980 Plan") and no
additional grants will be made under the superseded Plans. The rights
of  the  holders  of  outstanding options under the 1990 Plan and the
1980  Plan  were  not  affected.  The  purpose of the 1996 Plan is to
attract  and  retain  key  employees  of  the  company, to provide an
incentive  for  them  to  achieve long-range performance goals and to
enable  them  to  participate in the long-term growth of the company.
The  1996 Plan amended the 1990 Plan to increase the number of shares
of  common  stock  subject  to grants by 3,750,000 shares, expand the
types  of  awards  available to be granted and specify a limit on the
maximum  number  of  shares  with  respect to which stock options and
stock  appreciation  rights  may be made to any participant under the
Plan. Under the 1996 Plan, the Compensation Committee of the Board of
Directors   may  award  stock  grants,  stock  options  and/or  stock
equivalents  to  officers  and  key  employees of TECO Energy and its
subsidiaries.  The Compensation Committee has discretion to determine
the  terms  and  conditions  of  each  award, which may be subject to
conditions relating to continued employment, restrictions on transfer
or performance criteria.
     In  April  1998, under the 1996 Plan, 749,585 stock options were
granted,  each  with  a weighted average option price of $27.56 and a
maximum  term  of 10 years.  In addition, 60,257 shares of restricted
stock  were  awarded,  each  with  a  weighted  average fair value of
$27.56.  Compensation  expense  recognized  for  stock grants awarded
under  the  1996 Plan was $2.3 million, $1.3 million and $0.5 million
in  1998,  1997 and 1996. In general, the stock grants are restricted
subject  to  continued employment; the 1998 stock grants vest in five
years with the remainder vesting at normal retirement age.
     Stock  option transactions during the last three years under the
1996  Plan, the 1990 Plan and the 1980 Plan (collectively referred to
as the "Equity Plans"), are summarized as follows:

Stock Options - Equity Plans
                                     Option         Weighted Avg.
                                     Shares                Option
                                  (thousands)               Price

1998
Outstanding, beginning of year          2,372              $20.70
 Granted                                  750              $27.56
 Exercised                                385              $17.26
 Canceled                                   5              $26.48
Outstanding, end of year                2,732              $23.06
Exercisable, end of year                2,732              $23.06
Available for grant                     4,047                    

1997
Outstanding, beginning of year          2,286              $19.77
 Granted                                  352              $24.38
 Exercised                                265              $17.53
 Canceled                                   1              $24.38
Outstanding, end of year                2,372              $20.70
Exercisable, end of year                2,372              $20.70
Available for grant                     4,852


                                  63
1996 
Outstanding, beginning of year          2,263              $18.99
 Granted                                  293              $23.69
 Exercised                                268              $17.42
 Canceled                                   2              $23.56
Outstanding, end of year                2,286              $19.77
Exercisable, end of year                2,286              $19.77
Available for grant                     5,314

     As  of  Dec.  31,  1998  the 2.7 million options outstanding and
currently  exercisable  under  the Equity Plans are summarized in the
following table:

Stock Options Outstanding at Dec. 31, 1998
                                                   Weighted 
                                      Weighted        Avg.  
      Option                             Avg.     Remaining 
      Shares            Range of       Option    Contractual
   (thousands)       Option Prices      Price          Life 

           70       $11.53 - $14.56     $13.95      1 Years 
        1,008       $17.38 - $21.63     $19.65      5 Years 
        1,654       $23.56 - $27.56     $25.52      8 years 

     In  April  1997,  the  Shareholders  approved  the 1997 Director
Equity Plan (the "1997 Plan"), as an amendment and restatement of the
1991  Director  Stock  Option  Plan  (the  1991 Plan ). The 1997 Plan
supersedes the 1991 Plan, and no additional grants will be made under
the 1991 Plan. The rights of the holders of outstanding options under
the  1991  Plan will not be affected. The purpose of the 1997 Plan is
to  attract and retain highly qualified non-employee directors of the
company  and  to  encourage  them to own shares of TECO Energy common
stock.  The  1997 Plan is administered by the Board of Directors. The
1997  Plan  amended the 1991 Plan to increase the number of shares of
common  stock subject to grants by 250,000 shares, expanded the types
of  awards  available  to  be  granted and replaced the current fixed
formula   grant  by  giving  the  Board  discretionary  authority  to
determine the amount and timing of awards under the Plan.
     In April 1998, 24,000 options were granted, each with a weighted
average  option  price of $27.56.  Transactions during the last three
years under the 1997 Plan are summarized as follows:





















                                  64
Director Equity Plan
                                     Option         Weighted Avg.
                                     Shares             Option   
                                  (thousands)            Price   
1998
Outstanding, beginning of year            249              $20.59
 Granted                                   24              $27.56
 Exercised                                 32              $21.10
 Canceled                                  --                  --
Outstanding, end of year                  241              $21.22
Exercisable, end of year                  241              $21.22
Available for grant                       400                    

1997
Outstanding, beginning of year            215              $19.96
 Granted                                   34              $24.60
 Exercised                                 --                  --
 Canceled                                  --                  --
Outstanding, end of year                  249              $20.59
Exercisable, end of year                  249              $20.59
Available for grant                       428                    

1996
Outstanding, beginning of year            175              $19.13
 Granted                                   40              $23.63
 Exercised                                 --                  --
 Canceled                                  --                  --
Outstanding, end of year                  215              $19.96
Exercisable, end of year                  215              $19.96
Available for grant                       246

     As  of  Dec.  31,  1998,  the  241,000  options  outstanding and
currently  exercisable  under  the  1997  Plan  with option prices of
$17.72-$27.56,  had  a  weighted average option price of $21.22 and a
weighted average remaining contractual life of five years.
     TECO  Energy  has  adopted the disclosure-only provisions of FAS
123,  Accounting  for Stock-Based Compensation (FAS 123), but applies
Accounting    Principles   Board   Opinion   No.   25   and   related
i n t e rpretations  in  accounting  for  its  plans.  Therefore,  no
compensation  expense  has  been recognized for stock options granted
under  the 1996 Plan and the 1997 Plan. If the company had elected to
recognize  compensation  expense  for stock options based on the fair
value  at  grant  date,  consistent with the method prescribed by FAS
123, net income and earnings per share would have been reduced to the
pro forma amounts shown below:

















                                  65
                                 1998         1997      1996 
Net Income
from
continuing
operations   As reported        $200.4       $211.4    $217.4    
(millions)   Pro forma          $198.8       $210.7    $216.7    

Net Income   As reported        $206.5       $201.9    $216.5    
(millions)   Pro forma          $204.9       $201.1    $215.8    

Net Income
from
continuing
operations   As reported        $ 1.52       $ 1.62    $ 1.68 
- -EPS basic   Pro forma          $ 1.51       $ 1.61    $ 1.68 

Net Income   As reported        $ 1.57       $ 1.54    $ 1.67 
- -EPS basic   Pro forma          $ 1.56       $ 1.54    $ 1.67 

     These  pro forma amounts were determined using the Black-Scholes
valuation  model  with  the following key assumptions: (a) a discount
rate of 5.64%, 6.81% and 6.42% for 1998, 1997 and 1996, respectively;
(b)  an  expected  volatility  factor and dividend yield to equal the
rate  in  effect for the 36 months prior to grant; and (c) an average
expected option life of 6 years.

Dividend Reinvestment Plan
     In  1992,  TECO  Energy  implemented a Dividend Reinvestment and
Common  Stock  Purchase  Plan (DRP). TECO Energy raised common equity
from  this  plan  of $9.2 million in 1996.  In 1998 and 1997, the DRP
purchased  shares  of TECO Energy common stock on the open market for
plan participants.

Shareholder Rights Plan
     In  1989,  TECO  Energy  declared  a  distribution  of Rights to
purchase  one  additional  share  of  the company's common stock at a
price  of $40 per share for each share outstanding. The Rights expire
in  May  1999.  The  Rights  will  become exercisable 10 days after a
person  acquires  20  percent  or  more  of the company's outstanding
common  stock  or  commences a tender offer that would result in such
person  owning  30  percent  or more of such stock or at the time the
Board  of Directors declares a person who acquired 10 percent or more
of  such  stock to be an "adverse person."  If any person acquires 20
percent or more of the outstanding common stock or the Board declares
that a person is an adverse person, the rights of holders, other than
such  acquiring person or adverse person, become rights to buy shares
of  common  stock  of the company (or of the acquiring company if the
company  is involved in a merger or other business combination and is
not  the  surviving  corporation)  having a market value of twice the
exercise price of each right.
     The  company  may redeem the Rights at a nominal price per Right
until  10  days  after  a  person  acquires 20 percent or more of the
outstanding  common  stock  but  not  after  the Board has declared a
person to be an adverse person.
     In  October 1998, the Board of Directors renewed the Shareholder
Rights  Plan on substantially the same terms. Under the renewed plan,
among  other  things, the Rights become effective upon the expiration
(in May 1999) or the earlier termination of the existing Rights plan,
the  exercise price of the Rights is $90, the threshold percentage of
beneficial  ownership at which the Rights entitle holders to purchase


                                  66
common  stock at a discount is 10% and the Rights expire in May 2009,
subject to extension.

Employee Stock Ownership Plan
     Effective  Jan.  1,  1990,  TECO  Energy amended the TECO Energy
Group Retirement Savings Plan, a tax-qualified benefit plan available
to   substantially  all  employees,  to  include  an  employee  stock
ownership  plan  (ESOP).  During  1990,  the ESOP purchased 7 million
shares  of  TECO  Energy  common  stock  on  the open market for $100
million.  The  share  purchase  was financed through a loan from TECO
Energy to the ESOP. This loan is at a fixed interest rate of 9.3% and
will  be  repaid from dividends on ESOP shares and from TECO Energy's
contributions to the ESOP.
     TECO  Energy's contributions to the ESOP were $4.3 million, $3.4
million  and  $3.6 million in 1998, 1997 and 1996, respectively. TECO
Energy's  annual contribution equals the interest accrued on the loan
during the year plus additional principal payments needed to meet the
matching  allocation  requirements  under  the  plan,  less dividends
received  on  the  ESOP  shares.  The  components of net ESOP expense
recognized for the past three years are as follows:


(millions)                       1998           1997           1996 
Interest expense                 $7.3           $7.7           $8.0 
Compensation expense              5.5            4.7            4.9 
Dividends                        (8.1)          (7.8)          (7.5)
Net ESOP expense                 $4.7           $4.6           $5.4 

     Compensation  expense  was  determined  by  the shares allocated
method.
     At  Dec. 31, 1998, the ESOP had 2.4 million allocated shares, .1
million  committed-to-be-released shares, and 4.1 million unallocated
shares.  Shares  are  released  to provide employees with the company
match  in  accordance  with  the  terms  of  the  TECO  Energy  Group
Retirement  Savings  Plan  and in lieu of dividends on allocated ESOP
shares.  The  dividends  received  by  the  ESOP are used to pay debt
service.
     For financial statement purposes, the unallocated shares of TECO
Energy   stock  are  reflected  as  a  reduction  of  common  equity,
classified as unearned compensation. Dividends on all ESOP shares are
recorded as a reduction of retained earnings, as are dividends on all
TECO  Energy  common  stock. The tax benefit related to the dividends
paid  to  the  ESOP for allocated shares is a reduction of income tax
expense  and  for  unallocated  shares  is  an  increase  in retained
earnings. All ESOP shares are considered outstanding for earnings per
share computations.

C. Preferred Stock

Preferred Stock of TECO Energy - $1 Par
10 million shares authorized, none outstanding.

Preferred Stock of Tampa Electric - no Par
2.5 million shares authorized, none outstanding.

Preference Stock of Tampa Electric - no Par
2.5 million shares authorized, none outstanding.

Preferred Stock of Tampa Electric - $100 Par Value
1.5 million shares authorized, none outstanding.


                                  67
     In  July  1997,  Tampa  Electric  retired all of its outstanding
shares  ($20  million  aggregate  par value) of 4.32% Series A, 4.16%
Series  B  and 4.58% Series D preferred stock at redemption prices of
$103.75, $102.875 and $101.00 per share, respectively.
     Cash  dividends paid in 1997 were $0.2 million, $0.1 million and
$0.3 million for Series A, Series B and Series D, respectively. These
amounts  reflect  dividends paid through July 16, 1997, the date that
these series were redeemed.

D.   Short-term Debt
     Notes  payable  consisted  primarily  of  commercial  paper with
weighted  average  interest rates of 5.16% and 5.72% at Dec. 31, 1998
and   1997,  respectively.  The  carrying  amount  of  notes  payable
approximated fair market value because of the short maturity of these
instruments.  Consolidated  unused  lines  of credit at Dec. 31, 1998
were  $485  million.  Certain lines of credit require commitment fees
ranging from .05% to .075% on the unused balances.
     During 1995, TECO Finance entered into an interest rate exchange
agreement  to  moderate  its  exposure to interest rate changes. This
t h ree-year  agreement,  which  ended  June  26,  1998,  effectively
converted the interest rate on $100 million of short-term debt from a
floating rate to a fixed rate. TECO Finance paid a fixed rate of 5.8%
and  received  a  floating  rate  based  on a 30-day commercial paper
index.  The costs of this agreement did not have a significant impact
on interest expense in 1998, 1997 or 1996.





































                                  68
E.   Long-term Debt
                                                          Dec. 31,     
(millions)                                  Due        1998       1997
TECO Energy
Medium-term notes payable: 9.29%(1)        2000    $   50.0    $  50.0 
Medium-term notes payable: 5.35%(1)(2)     2001       150.0         -- 
                                                      200.0       50.0 

Tampa Electric
First mortgage bonds (issuable in series):
 7 3/4%                                    2022        75.0       75.0 
 5 3/4%                                    2000        80.0       80.0 
 6 1/8%                                    2003        75.0       75.0 
Installment contracts payable(3):
 5 3/4%                                    2007        23.5       23.8 
 7 7/8% Refunding bonds(4)                 2021        25.0       25.0 
 8% Refunding bonds(4)                     2022       100.0      100.0 
 6 1/4% Refunding bonds(5)                 2034        86.0       86.0 
 5.85%                                     2030        75.0       75.0 
 Variable rate: 3.06% for 1998 and 
  3.55% for 1997(1)                        2025        51.6       51.6 
 Variable rate: 3.17% for 1998 and 
  3.45% for 1997(1)                        2018        54.2       54.2 
 Variable rate: 3.39% for 1998 and
  3.78% for 1997(1)                        2020        20.0       20.0 
Medium-term notes payable: 5.11% (1)(6)    2001        38.0         -- 
                                                      703.3      665.6 

Peoples Gas System
Senior Notes (7)
 10.35%                                    2007         6.8        7.4 
 10.33%                                    2008         8.6        9.2 
 10.3%                                     2009         9.2        9.4 
 9.93%                                     2010         9.4        9.6 
 8.0%                                      2012        32.0       33.5 
Medium-term notes payable: 5.11% (1)(6)    2001        12.0         -- 
                                                       78.0       69.1 
Diversified companies
Dock and wharf bonds, variable rate:
 3.15% for 1998 and 3.75% for 1997(1)(3)   2007       110.6      110.6 
Mortgage notes payable: 7.6%               1999         0.2        0.8 
Non-recourse secured facility notes,
 Series A: 7.8%                         1999-2012     137.9      143.5 
Limited recourse secured facility
 note: 9.875%                           1999-2008      24.4       26.8 
Capital lease: implicit rate of 
 8.5% for 1998                          1999-2003      33.4         -- 
                                                      306.5      281.7 
TECO Finance
Medium-term notes payable, various rates:
 7.26% for 1998 and 1997(1)             1999-2002      30.0       30.0 

Unamortized debt premium (discount), net               (2.2)      (3.5)
                                                    1,315.6    1,092.9 
Less amount due within one year(8)                     36.0       12.7 
Total long-term debt                               $1,279.6   $1,080.2 

(1)  Composite year-end interest rate.
(2)  These  notes  are subject to mandatory tender on Sept. 15, 2001,
     at which time they will be redeemed or remarketed.
(3)  Tax-exempt securities.






                                  69
(4)  Proceeds  of these bonds were used to refund bonds with interest
     rates  of  11  5/8% - 12 5/8%. For accounting purposes, interest
     expense  has been recorded using blended rates of 8.28%-8.66% on
     the  original  and  refunding  bonds, consistent with regulatory
     treatment.
(5)  Proceeds  of  these  bonds  were  used  to  refund bonds with an
     interest rate of 9.9% in February 1995. For accounting purposes,
     interest expense has been recorded using a blended rate of 6.52%
     on  the original and refunding bonds, consistent with regulatory
     treatment.
(6)  These notes are subject to mandatory tender on July 15, 2001, at
     which time they will be redeemed or remarketed.
(7)  These  long-term  debt  agreements  contain  various restrictive
     covenants,  including  provisions  related to interest coverage,
     maximum  levels  of debt to total capitalization and limitations
     on dividends.
(8)  Of  the amount due in 1999, $0.8 million may be satisfied by the
     substitution of property in lieu of cash payments.

     TECO  Transport  entered  into  a  capital  lease agreement with
Midwest  Marine  Management  Company in March 1998 for the charter of
additional  capacity.  This  lease  covers 110 river barges and three
towboats,  classified as property, plant and equipment on the balance
sheet;  the  corresponding $35 million five-year lease commitment was
recorded as a long-term debt on the balance sheet. The following is a
schedule of future minimum lease payments under the capitalized lease
together  with the present value of the net minimum lease payments as
of Dec. 31, 1998:

                                             Amount  
Year Ended Dec. 31:                        (millions)
     1999                                     $ 4.6  
     2000                                       4.6  
     2001                                       4.6  
     2002                                       4.6  
     2003                                      25.5  
Total minimum lease payments                   43.9  
Less: Amount representing interest             10.5  
Present value of net minimum lease
 payments, including current 
 maturities of $1.8 million                   $33.4  

     Substantially  all of the property, plant and equipment of Tampa
Electric  is  pledged  as  collateral  to  secure its long-term debt.
Maturities and annual sinking fund requirements of long-term debt for
the  years  2000,  2001,  2002  and  2003  are $145.7 million, $216.8
million,  $27.3  million,  and $117.0 million, respectively. Of these
amounts  $0.8 million per year for 2000 through 2003 may be satisfied
by the substitution of property in lieu of cash payments.
     At  Dec. 31, 1998, total long-term debt had a carrying amount of
$1,279.6  million  and  an  estimated  fair  market value of $1,404.7
million.  The estimated fair market value of long-term debt was based
on  quoted  market  prices  for  the  same  or similar issues, on the
current  rates  offered for debt of the same remaining maturities, or
for long-term debt issues with variable rates that approximate market
rates, at carrying amounts. The carrying amount of long-term debt due
within  one  year approximated fair market value because of the short
maturity of these instruments.




                                  70
F.   Retirement Plan

TECO Energy Retirement Plan

     TECO  Energy  has  a non-contributory defined benefit retirement
plan  which covers substantially all employees. Benefits are based on
employees' years of service and average final salary.
     The  company's  policy is to fund the plan within the guidelines
set  by  ERISA  for  the  minimum annual contribution and the maximum
allowable  as  a  tax  deduction by the IRS. About 70 percent of plan
assets  were invested in common stocks and 30 percent in fixed income
investments at Dec. 31, 1998.
     The  Peoples Gas System retirement plan was merged with the TECO
Energy  retirement plan effective Jan. 1, 1998.  As of Dec. 31, 1997,
Peoples  Gas System had a non-contributory defined benefit retirement
plan  which  covered substantially all employees. Benefits were based
on  employees'  years  of  service  and  average  compensation during
specified years of employment.
     Peoples  Gas System s retirement plan was funded annually by the
company  within  the  guidelines  set by ERISA for the minimum annual
contribution and the maximum allowable as a tax deduction by the IRS.
Plan  assets were invested primarily in a collective investment trust
consisting  of  equity  securities,  fixed income securities and cash
equivalents.
     All  information  prior to 1998 has been restated to include the
Peoples Gas System Retirement Plan.
     In  1997,  the  Financial  Accounting Standards Board issued FAS
132,  Employers' Disclosures about Pensions and Other Post Retirement
Benefits.  FAS  132  standardizes  the  disclosure  requirements  for
pension and other postretirement benefits with additional information
required  on  changes  in  the benefit obligations and fair values of
plan  assets.  The  company  adopted  FAS  132  with  the  additional
disclosures  included  here and in Footnote G, Postretirement Benefit
Plan.

Components of Net Pension Expense
(millions)                                  1998      1997      1996
Service cost 
  (benefits earned during the period)      $11.2     $ 9.6     $ 9.9 
Interest cost on projected 
  benefit obligations                       24.8      23.6      22.2 
Less: Expected return on plan assets       (31.5)    (28.4)    (26.4)
Amortization of:
  Unrecognized transition asset             (1.1)     (1.2)     (1.2)
  Prior service cost                         0.9       0.9       0.8 
  Actuarial (gain) loss                       --      (0.3)     (0.1)
Net pension expense                          4.3       4.2       5.2 
Special termination benefit charge           0.7        --        -- 
Curtailment charge                          (0.8)       --      (1.0)
Net pension expense recognized
  in the Consolidated Statements
  of Income                                $ 4.2     $ 4.2     $ 4.2 










                                  71
Reconciliation  of  the  Funded Status of the Retirement Plan and the
Accrued Pension Prepayment/(Liability)
(millions)
                                              Dec. 31,     Dec. 31,
                                                 1998         1997  

Project benefit obligation, beginning
  of year                                       $344.7       $262.2 
Change in benefit obligation due to:
  Service cost                                    11.2          9.6 
  Interest cost                                   24.8         23.6 
  Actuarial (gain) loss                           22.4         22.1 
  Acquisitions                                      --         47.6 
  Curtailments                                    (1.1)          -- 
  Special termination benefits                     0.7           -- 
  Gross benefits paid                            (19.0)       (20.4)
Projected benefit obligation, end 
  of year                                        383.7        344.7 
Fair value of plan assets, beginning
  of year                                        414.8        320.5 
Change in plan assets due to:
  Actual return on plan assets                    72.2         65.8 
  Employer contributions                           0.7           -- 
  Acquisitions                                      --         48.9 
  Gross benefits paid                            (19.0)       (20.4)
Fair value of plan assets, end
  of year                                        468.7        414.8 
Funded status, end of year                        85.0         70.1 
Unrecognized net actuarial gain                 (102.9)       (83.7)
Unrecognized prior service cost                   10.7         11.0 
Unrecognized net transition asset                 (7.0)        (8.1)
Accrued pension liability                       $(14.2)      $(10.7)

Assumptions Used in Determining Actuarial Valuations
                                                  1998         1997 
Discount rate to determine projected 
  benefit obligation                              6.75%        7.25%
Rates of increase in compensation levels       3.3-5.3%     3.3-5.3%
Plan asset growth rate through time                  9%           9%


G.   Postretirement Benefit Plan

     TECO  Energy  and  its  subsidiaries  currently  provide certain
postretirement  health  care benefits for substantially all employees
retiring  after  age  55  meeting  certain  service requirements. The
company  contribution  toward health care coverage for most employees
retiring  after  Jan.  1, 1990 is limited to a defined dollar benefit
based   on  years  of  service.  Postretirement  benefit  levels  are
substantially  unrelated to salary. The company reserves the right to
terminate or modify the plans in whole or in part at any time.











                                  72
Components of Postretirement Benefit Cost 
(millions)
                                             1998     1997     1996
Service cost (benefits earned 
    during the period)                      $ 2.6    $ 2.2    $ 2.4
Interest cost on projected 
    benefit obligations                       6.1      6.1      6.1
Amortization of transition obligation
   (straight line over 20 years)              2.7      2.7      2.7
Amortization of actuarial loss/(gain)         0.1     (0.1)     0.3
 Net periodic Postretirement 
    benefit expense                         $11.5    $10.9    $11.5

Reconciliation  of  the  Funded  Status of the Postretirement Benefit
Plan and the Accrued Liability (millions)
                                                   Dec. 31,  Dec. 31,
                                                     1998      1997  
Accumulated postretirement benefit obligation,
  beginning of year                                 $ 85.8    $ 83.4 
Change in benefit obligation due to:
  Service cost                                         2.6       2.3 
  Interest cost                                        6.1       6.1 
  Plan participants' contributions                     0.3       0.3 
  Actuarial (gain) loss                                3.3      (1.2)
  Gross benefits paid                                 (5.0)     (5.1)
Accumulated postretirement benefit obligation, 
  end of year                                       $ 93.1    $ 85.8 

Funded status, end of year                          $(93.1)   $(85.8)
Unrecognized net loss from past experience            12.2       9.0 
Unrecognized transition obligation                    38.4      41.1 
Liability for accrued postretirement benefit        $(42.5)   $(35.7)

Assumptions Used in Determining Actuarial Valuations
                                                      1998      1997 
Discount rate to determine projected 
  benefit obligation                                  6.75%    7.25% 

     The  assumed health care cost trend rate for medical costs prior
to  age  65  was  8.75%  in  1998  and decreases to 5.75% in 2002 and
thereafter. The assumed health care cost trend rate for medical costs
after  age  65  was  6.75% in 1998 and decreases to 5.75% in 2002 and
thereafter.
     A  1-percent increase in the medical trend rates would produce a
9-percent  ($0.7  million)  increase  in  the  aggregate  service and
interest  cost for 1998 and a 8-percent($7.4 million) increase in the
accumulated postretirement benefit obligation as of Dec. 31, 1998.
     A  1-percent decrease in the medical trend rates would produce a
7-percent  ($0.6  million)  decrease  in  the  aggregate  service and
interest  cost for 1998 and a 7-percent($6.4 million) decrease in the
accumulated postretirement benefit obligation as of Dec. 31, 1998.











                                  73
H. Income Tax Expense

Income tax expense consists of the following components:

(millions)                                Federal    State   Total 
1998
 Currently payable                         $ 56.9   $ 10.9  $ 67.8 
 Deferred                                    15.2      3.0    18.2 
 Amortization of investment tax credits      (5.0)      --    (5.0)
 Income tax expense from continuing
   operations                                67.1     13.9    81.0 
 Currently payable                            6.9      0.6     7.5 
 Deferred                                    (3.6)      --    (3.6)
 Income tax benefit from discontinued             
   operations                                 3.3      0.6     3.9 
Total income tax expense                   $ 70.4   $ 14.5  $ 84.9 

1997
 Currently payable                         $ 88.5    $ 9.9  $ 98.4 
 Deferred                                    (6.0)     7.3     1.3 
 Amortization of investment tax credits      (5.0)      --    (5.0)
 Income tax expense from continuing
   operations                                77.5     17.2    94.7 
 Currently payable                           (4.1)     0.4    (3.7)
 Deferred                                    (1.0)    (0.4)   (1.4)
 Income tax benefit from discontinued
   operations                                (5.1)      --    (5.1)
Total income tax expense                   $ 72.4   $ 17.2  $ 89.6 

1996
 Currently payable                         $ 67.4   $ 12.7  $ 80.1 
 Deferred                                     6.9     (0.1)    6.8 
 Amortization of investment tax credits      (5.1)      --    (5.1)
 Income tax expense from continuing
   operations                                69.2     12.6    81.8 
 Currently payable                           (3.1)    (0.3)   (3.4)
 Deferred                                     2.6      0.3     2.9 
 Income tax benefit from discontinued
   operations                                (0.5)      --    (0.5)
Total income tax expense                   $ 68.7   $ 12.6  $ 81.3 






















                                  74
    D e f erred  taxes  result  from  temporary  differences  in  the
recognition  of  certain  liabilities or assets for tax and financial
reporting   purposes.  The  principal  components  of  the  company's
deferred  tax  assets and liabilities recognized in the balance sheet
are as follows:

(millions)                                Dec. 31,         Dec. 31,
                                            1998             1997  
Deferred income tax assets(1)
 Property related                          $ 63.0           $ 59.1 
 Basis differences in oil and gas
  producing properties                       (2.4)              -- 
 Other                                       38.5             29.0 
  Total deferred income tax assets           99.1             88.1 

Deferred income tax liabilities(1)
 Property related                          (548.5)          (521.9)
 Basis differences in oil and gas
  producing properties                      (15.7)           (22.2)
 Revenue deferral plan                         --             11.7 
 Alternative minimum tax
  credit carry forward                       39.3             40.8 
 Other                                       25.0             20.7 
  Total deferred income 
    tax liabilities                        (499.9)          (470.9)
  Accumulated deferred income taxes       $(400.8)         $(382.8)

(1) Certain property related assets and liabilities have been netted.

    The  total  income tax provisions differ from amounts computed by
applying the federal statutory tax rate to income before income taxes
for the following reasons:

(millions)                                 1998      1997     1996 
Net income from continuing operations     $200.4    $211.4    $217.4 
Total income tax provision                  81.0      94.7      81.8 
Preferred dividend requirements               --       0.5       1.8 

 Income from continuing operations
   before income taxes and 
   preferred dividend requirements        $281.4    $306.6    $301.0 

Income taxes on above at federal 
  statutory rate of 35%                   $ 98.5    $107.3    $105.3 
Increase (Decrease) due to:
 State income tax, net of 
   federal income tax                        9.1      11.2       8.2 
 Amortization of investment 
   tax credits                              (5.0)     (5.0)     (5.1)
 Non-conventional fuels tax credit         (18.9)    (20.2)    (19.6)
 Equity portion of AFUDC                      --        --      (5.8)
 Other                                      (2.7)      1.4      (1.2)
  Total income tax provision from
    continuing operations                 $ 81.0    $ 94.7    $ 81.8 
Provision for income taxes as a percent 
  of income from continuing operations,
  before income taxes                       28.8%     30.9%     27.1%





                                  75
    The  provision  for  income  taxes  as  a  percent of income from
discontinued operations was 35.0%, 34.8% and 34.7% for 1998, 1997 and
1996, respectively.  The total effective income tax rate differs from
the  federal  statutory  rate due to state income tax, net of federal
income tax and other miscellaneous items.

I.  Discontinued Operations

    On  Aug.  28, 1997, the company announced its plan to discontinue
operations  of  its  conventional  oil and gas subsidiary, TECO Oil &
Gas, Inc.  Since its formation in the second half of 1995, TECO Oil &
Gas  has participated in joint ventures utilizing 3-D seismic imaging
in  the  exploration  for  oil  and  gas.  It acquired a portfolio of
interests in producing wells, discoveries not yet producing and lease
prospects in the shallow waters of the Gulf of Mexico and on shore in
Texas.
    As a result of the company s intention to sell this business, all
activities  of  the subsidiary through Aug. 31, 1997, the measurement
date,  were  reported  as discontinued operations on the Consolidated
Statements  of  Income.   An estimate of activities at TECO Oil & Gas
after  that date, including the sale of the assets at book value, was
reported   in  1997  as  a  loss  on  the  disposal  of  discontinued
operations.  A summary of net assets is as follows:

(millions)                               Dec. 31,            Dec. 31,
                                          1998                1997  
 Current assets                            $ 0.2               $ 1.5 
 Net property, plant and equipment            --                19.5 
 Other assets                                 --                 3.9 
 Taxes currently payable                     9.5                 0.2 
 Deferred taxes                              2.0                (1.6)
 Total liabilities                          (0.8)               (1.7)
  Net assets                               $10.9               $21.8 

    Total  revenues  from discontinued operations for the years ended
Dec.   31,  1997  and  1996  were  $9.6  million  and  $4.7  million,
respectively.  There were no revenues in 1998.
    In  March  1998,  TECO  Oil  &  Gas  sold  its offshore assets to
A m e rican  Resources  Offshore,  Inc.  (ARO),  for  $57.7  million,
consisting  of  $39.2  million in cash and a subordinated note in the
principal  amount of $18.5 million. Based on unfavorable developments
at  ARO  late  in  the year and the likely impact of certain economic
factors on that business, the company wrote off the recorded value of
all  assets  associated  with the discontinued oil and gas operation,
including  the  $18.5  million  note  and  associated interest income
accrued.  The  net, after-tax gain, net of charges, from discontinued
operations in 1998 was $6.1 million for the year, or $0.05 per share.
    In  March  1999,  the company completed a transaction in which it
sold  the  note  from ARO in return for $500,000 in cash. The company
also  sold  an option relating to its ARO warrants; in the event such
option  is  exercised, the company will receive the exercise price of
$600,000. In a separate transaction, ARO agreed to be responsible for
disputed joint billing payments of approximately $425,000. As part of
this  settlement,  ARO  also  conveyed  to  the company an overriding
royalty  interest  in two offshore Gulf of Mexico blocks. The company
does not expect any future royalty payments to be significant.






                                  76
J.  Earnings Per Share

    In 1997, the Financial Accounting Standards Board issued FAS 128,
Earnings  per  Share,  which requires disclosure of basic and diluted
earnings  per  share  and  a  reconciliation (where different) of the
numerator  and  denominator from basic to diluted earnings per share.
The  reconciliation  of basic and diluted earnings per share is shown
below:

                                           Year ended Dec. 31,    
                                          1998      1997      1996  

Numerator (Basic and Diluted)
Net income from continuing operations     $200.4    $211.4    $217.4 
Net income                                $206.5    $201.9    $216.5 

Denominator
Average number of shares outstanding 
  - basic                                  131.7     130.8     129.3 
Plus: incremental shares for assumed
  conversions: Stock options at end
  of period                                  3.0       2.6       2.5 
Less: Treasury shares which could 
  be purchased                              (2.5)     (2.2)     (2.0)
                                                 
Average number of shares outstanding
  - diluted                                132.2     131.2     129.8 

Earnings per share from continuing operations

  Basic                                    $1.52     $1.62     $1.68 
  Diluted                                  $1.52     $1.61     $1.67 

Earnings per share                               

  Basic                                    $1.57     $1.54     $1.67 
  Diluted                                  $1.57     $1.54     $1.67 

























                       77
K.  Segment Information
    
    TECO  Energy  is  an  electric and gas utility holding company with
important   diversified  activities.  The  Management  of  TECO  Energy
d e termined  its  reportable  segments  based  on  each  subsidiaries'
contribution  of  revenues,  operating  income  and  total  assets. All
significant   intercompany   transactions   are   eliminated   in   the
consolidated  financial  statements  of TECO Energy but are included in
determining reportable segments in accordance with FAS 131, Disclosures
about  Segments  of  an Enterprise and Related Information. FAS 131 was
adopted  in  1998 and all prior years presented here have been restated
to conform to the requirements of FAS 131.


                                                Income                                     Capital  
                                                 From                         Assets    Expenditures
(millions)                      Revenues(1)  Operations(1) Depreciation(1) at Dec. 31,  for the Year
                                                                               
1998
 Tampa Electric                $1,234.6(2)(3)  $279.7  (7)      $146.1        $2,705.0        $176.2
 Peoples Gas System               252.8          35.8             21.0           375.6          55.9
 TECO Transport                   230.0 (4)      43.2             26.6           309.7          45.6
 TECO Coal                        232.4 (5)      23.5  (8)        10.6           180.0          11.2
 TECO Power Services               98.7 (6)      13.0  (9)         9.2           412.9(11)       0.4
 Other diversified businesses     113.0          34.7 (10)        14.7           301.5           5.6
                                2,161.5         429.9            228.2         4,284.7         294.9
 Other and eliminations          (203.4)        (34.4)(12)         0.1          (105.4)          1.2
 TECO Energy consolidated      $1,958.1        $395.5           $228.3        $4,179.3        $296.1

1997
 Tampa Electric                $1,189.2 (2)    $271.5           $141.4        $2,678.4        $125.1
 Peoples Gas System               249.6          33.6             19.8           348.9          30.2
 TECO Transport                   218.7 (4)      42.1             27.3           266.8          28.9
 TECO Coal                        215.6 (5)      19.9             11.6           191.4          12.3
 TECO Power Services               93.0 (6)      15.2  (9)         8.9           273.3(11)       2.1
 Other diversified businesses     105.2          37.9 (10)        16.4           301.3           6.7
                                2,071.3         420.2            225.4         4,060.1         205.3
 Other and eliminations          (209.0)         (7.6)              --           (99.7)          7.3
 TECO Energy consolidated      $1,862.3        $412.6           $225.4        $3,960.4        $212.6









                                                    78


                                                Income                                     Capital  
                                                 From                         Assets    Expenditures
(millions)                      Revenues(1)  Operations(1) Depreciation(1) at Dec. 31,  for the Year
                                                                               
1996
 Tampa Electric                $1,112.9 (2)    $244.0           $120.2        $2,645.8        $203.3
 Peoples Gas System               258.7          32.0             17.2           302.7          25.9
 TECO Transport                   207.5 (4)      38.9             27.4           265.9          34.2
 TECO Coal                        207.5 (5)      18.3             11.4           181.9          12.8
 TECO Power Services               88.1 (6)      16.7  (9)         8.4           260.4(11)       4.5
 Other diversified businesses     102.9          39.9 (10)        18.2           306.6           2.2
                                1,977.6         389.8            202.8         3,963.3         282.9
 Other and eliminations          (202.2)         (8.0)              --           (61.8)         13.4
 TECO Energy consolidated      $1,775.4        $381.8           $202.8        $3,901.5        $296.3

 (1) From continuing operations
 (2) Revenues  from  sales  to  affiliates  were $23.2 million, $22.2
     million and $20.5 million in 1998, 1997 and 1996, respectively.
 (3) Revenues  shown  in  1998  and  1997  include the recognition of
     previously  deferred revenue of $38.3 million and $30.5 million,
     respectively.  Revenues  shown  in  1996  are after the revenues
     deferral of $34.2 million.
 (4) Revenues  from  sales  to affiliates were $112.8 million, $114.7
     million and $105.0 million in 1998, 1997 and 1996, respectively.
 (5) Revenues  from  sales  to  affiliates  were $33.8 million, $44.3
     million and $51.5 million in 1998, 1997 and 1996, respectively.
 (6) Revenues  from  sales  to  affiliates  were $32.7 million, $26.7
     million and $25.0 million in 1998, 1997 and 1996, respectively.
 (7) Operating  income  excludes  a  one-time  pretax  charge of $9.6
     million in 1998. See Note L.
 (8) Operating  income  excludes  a  one-time  pretax charge of $13.6
     million in 1998. See Note L.
 (9) Operating  income includes interest cost on the limited-recourse
     debt  related  to independent power operations of $13.4 million,
     $14.1  million  and  $12.0  million  in  1998,  1997  and  1996,
     respectively.
(10) Operating income includes a non-conventional fuels tax credit of
     $18.9 million, $20.2 million and $19.6 million in 1998, 1997 and
     1996, respectively.
(11) Total   assets  include  $141.2  million  and  $5.8  million  in
     investments  in  unconsolidated  affiliates  for  1998 and 1997,
     respectively, classified as deferred charges and other assets on
     the balance sheet.
(12) Operating income includes one-time pretax charges totaling $25.9
     million in 1998. See Note L.


                                  79
     T a mpa  Electric  Company,  provides  retail  electric  utility
services  to more than 537,000 customers in West Central Florida. Its
Peoples  Gas System division is engaged in the purchase, distribution
and   marketing  of  natural  gas  for  almost  240,000  residential,
commercial, industrial and electric power generation customers in the
State of Florida.
     TECO   Transport   Corporation,   through   its   wholly   owned
subsidiaries,  transports,  stores  and  transfers coal and other dry
b u lk  commodities  for  third  parties  and  Tampa  Electric.  TECO
Transport's   subsidiaries  operate  on  the  Mississippi,  Ohio  and
Illinois rivers, in the Gulf of Mexico and worldwide.
     TECO  Coal  Corporation,  through its wholly owned subsidiaries,
owns  mineral  rights,  and  owns or operates surface and underground
mines  and  coal  processing  and  loading facilities in Kentucky and
Tennessee. TECO Coal's subsidiaries sell its coal production to third
parties and to Tampa Electric.
     TECO Power Services Corporation (TPS) has subsidiaries that have
interests in independent power projects in Florida and Guatemala, and
has  investments  in  unconsolidated  affiliates  that participate in
independent power projects in other parts of the U.S. and the world.
     TECO Energy's other diversified operating businesses are engaged
in natural gas production from coalbeds, the sale of propane gas, the
marketing  of  natural  gas, energy services and engineering, and the
marketing  of  advanced  energy  management,  automation  and control
systems.

Foreign Operations
     T P S  has  independent  power  operations  and  investments  in
Guatemala. 
     TPS,  through  its subsidiaries, owns and operates a 78-megawatt
power station that supplies energy to Empresa Electrica de Guatemala,
S.A.(EEGSA),  an  electric utility in Guatemala, under a U.S. dollar-
denominated power sales agreement.
     TPS,  through  a  wholly  owned  subsidiary,  has  a  46-percent
ownership  interest  in an entity that is constructing a 120-megawatt
power  station and transmission facilities in Guatemala. This project
is  expected  to  be  completed  in  early  2000  and begin providing
capacity  under  a  U.S.  dollar-denominated power sales agreement to
EEGSA.  In  1998,  a  consortium  that  includes  TPS,  Iberdrola, an
electric utility in Spain, and Electricidade de Portugal, an electric
utility  in  Portugal,  acquired  an 80-percent ownership interest in
EEGSA.    
     Total  assets  at  Dec.  31, 1998, 1997 and 1996 included $154.1
million,  $34.7  million  and $53.9 million, respectively, related to
these  Guatemalan investments. Revenues included $16.9 million, $15.8
million and $15.1 million for the years ended Dec. 31, 1998, 1997 and
1996,  respectively, and operating income included $7.9 million, $6.5
million  and $8.3 million for the years ended Dec. 31, 1998, 1997 and
1996, respectively, from these Guatemalan operations and investments.

L.   Assets Adjustment and One-Time Charges

     In  1998, the company recognized one-time charges totaling $33.8
million,  pretax  ($21.3  million  after-tax).  Of  the $33.8 million
pretax  charges, $25.9 million ($16.5 million, after-tax) is recorded
in  operating  expenses,  as  non-recurring  charges and $7.9 million
($4.8 million, after-tax) is recorded in other income.
     The  $8.9-million, after-tax charge recorded by TECO Coal was to
adjust  the  asset  values of certain mining facilities, primarily at
its  Gatliff  mine,  to  reflect their expected value after the Tampa


                                  80
Electric contract expires in 1999. TECO Coal expects no further asset
adjustments related to the expiration of the Tampa Electric contract.
     TeCom  recorded  a  one-time after-tax charge of $1.7 million to
write  off  certain  development  costs related to residential system
features  developed  early  in the product life and no longer used in
the current system design.
     The  FPSC  in  September  1997  ruled  that under the regulatory
agreements effective through 1999 the costs associated with two long-
term  wholesale  power  sales  contracts  should  be  assigned to the
wholesale  jurisdiction  and that for retail rate making purposes the
costs  transferred  from  retail  to wholesale should reflect average
costs  rather  than  the  lower  incremental  costs  on which the two
contracts  are  based.  As  a result of this decision and the related
reduction  of  the  retail  rate  base  upon  which Tampa Electric is
allowed  to  earn  a return, these contracts became uneconomical. One
contract  was  terminated  in  1997.  As to the other contract, which
expires  in 2001, Tampa Electric has entered into firm power purchase
contracts  with  third  parties  to provide replacement power through
1999  and  is  no  longer separating the associated generation assets
from the retail jurisdiction. The cost of purchased power under these
contracts exceeds the revenues expected through 1999. To reflect this
difference,  Tampa  Electric recorded a $5.9-million after-tax charge
in 1998.
     Tampa Electric also recorded a $4.4-million, after-tax charge in
1998  for  a  recent  FPSC denial of the recovery of certain BTU coal
quality  adjustments  for coal purchase since 1993. This was recorded
as other income on the income statement.
     TECO  Energy  recorded $0.4 million, after tax of merger related
costs  in connection with the Griffis, Inc. merger, which is recorded
as other income on the income statement.

M.   Commitments and Contingencies

     TECO  Energy has made certain commitments in connection with its
continuing  capital  improvements program. TECO Energy estimates that
capital expenditures for ongoing businesses during 1999 will be about
$422  million  and  approximately  $1.2  billion  for  the years 2000
through 2003.
     Tampa  Electric's  capital expenditures are estimated to be $142
million  in 1999 and $506 million for 2000 through 2003 for equipment
and  facilities  to  meet  customer growth and generation reliability
programs. Additionally, Tampa Electric is also expecting to spend $61
million  in  1999  and  $6  million  during 2000-2003 to complete the
scrubber  project  at  Big  Bend Power Station and is forecasting $19
million  in  1999  and  $194  million  during  2000-2003 to construct
additional  generation  expansion. At the end of 1998, Tampa Electric
had  outstanding  commitments  of  about  $68 million to complete the
s c r ubber  and  $44  million  to  construct  additional  generation
expansion.
     Peoples  Gas  System  s capital expenditures are estimated to be
$75  million  for  1999  and  $208  million for 2000 through 2003 for
infrastructure  expansion  to grow the customer base and normal asset
replacement.  At  the end of 1998, Peoples Gas System had outstanding
commitments of $8 million related to its Southwest Florida expansion.
     At the diversified companies, capital expenditures are estimated
at  $125 million for 1999 and $259 million for the years 2000 through
2003,  primarily  for  asset  replacement  and  refurbishment at TECO
Transport  and  TECO  Coal,  the  construction  of the San Jose power
station  and  a joint venture investment at TECO Power Services. This
includes  commitments  of  $34 million at the end of 1998, mainly for


                                  81
the construction of the San Jose Power Plant in Guatemala.

N.   Quarterly Data (unaudited)

Financial data by quarter is as follows: (unaudited)

                                                          
                                          Quarter ended              
                              March 31   June 30  Sept. 30   Dec. 31  
1998
 Revenues(1)                 $  467.8  $  490.6  $  525.6   $ 474.1   
 Income from operations(1)   $   69.8  $  110.4  $  128.2   $  87.1   
 Net income(1)                        
  Net income from
   continuing operations     $   30.8  $   57.9  $   70.8   $  40.9   
  Net income                 $   53.0  $   57.9  $   70.8   $  24.8   
 Earnings per share (EPS)
  - basic 
  EPS from continuing
   operations                $   0.23  $   0.44  $   0.54   $  0.31   
  EPS                        $   0.40  $   0.44  $   0.54   $  0.19   
 Dividends paid per common 
  share (2)                  $   .295  $   0.31  $   0.31   $  0.31   
 Stock price per common 
  share(3)
   High                      $ 28 1/2  $ 28 5/16 $ 28 7/8   $ 30 5/8  
   Low                       $ 25 9/16 $ 25 3/16 $ 24 3/4   $ 26 3/4  
   Close                     $ 28 1/4  $26 13/16 $ 28 9/16  $ 28 3/16 

1997
 Revenues(1)                 $  450.3  $  460.8  $  494.7   $ 456.5   
 Income from operations(1)   $   98.0  $  103.4  $  125.6   $  85.6   
 Net income(1)                        
  Net income from
   continuing operations     $   50.8  $   50.5  $   67.5   $  42.6   
  Net income                 $   50.8  $   50.5  $   59.3   $  41.3   
 Earnings per share (EPS)
  - basic 
  EPS from continuing
   operations                $   0.39  $   0.39  $   0.51   $  0.33   
  EPS                        $   0.39  $   0.39  $   0.45   $  0.31   
 Dividends paid per common 
  share (2)                  $   0.28  $   .295  $   .295   $  .295   
 Stock price per common 
  share(3)
   High                      $ 25 1/8  $ 25 5/8  $ 25 7/8   $ 28 3/16 
   Low                       $ 23 3/4  $ 23 3/4  $ 23 7/8   $ 22 3/4  
   Close                     $ 24      $ 25 9/16 $ 24 1/2   $ 28 1/8  


(1)  Millions.
(2)  Dividends paid for TECO Energy common stock (not restated for
      Peoples Companies merger).
(3)  Trading prices for common shares.









                                  82
Item 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
          AND FINANCIAL DISCLOSURE.

     During  the period Jan. 1, 1997 to the date of this report, TECO
Energy  has not had and has not filed with the Commission a report as
to  any  changes  in  or disagreements with accountants on accounting
principles  or practices, financial statement disclosure, or auditing
scope or procedure.


                               PART III

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 

(a) The information required by Item 10 with respect to the directors
of  the  registrant  is  included  under  the  caption  "Election  of
Directors"  on  pages  1  through 4 of TECO Energy's definitive proxy
s t a tement,  dated  March  4,  1999,  for  its  Annual  Meeting  of
Shareholders  to  be  held on April 21, 1999 (Proxy Statement) and is
incorporated herein by reference.
    
(b) The information required by Item 10 concerning executive officers
of  the  registrant is included under the caption "Executive Officers
of the Registrant" on pages 23 and 24 of this report.

Item 11.  EXECUTIVE COMPENSATION. 

     The  information  required  by  Item 11 is included in the Proxy
Statement  beginning  on  page  9  and ending just before the caption
"Shareholder Proposal" on page 12 and under the caption "Compensation
of Directors" on page 4, and is incorporated herein by reference. 
     
Item 12.  S E CURITY  OWNERSHIP  OF  CERTAIN  BENEFICIAL  OWNERS  AND
          MANAGEMENT. 

     The  information  required  by  Item  12  is  included under the
caption "Share Ownership" on pages 4 and 5 of the Proxy Statement and
is incorporated herein by reference. 

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. 

    The information required by Item 13 is included under the caption
"Election  of  Directors"  on  page  3  of the Proxy Statement and is
incorporated herein by reference. 


















                                  83
                               PART IV

Item 14.   EXHIBITS,  FINANCIAL  STATEMENT  SCHEDULES  AND REPORTS ON
           FORM 8-K.

(a)  1. Financial Statements - See index on page 52
     2. Financial Statement Schedules - See index on page 52
     3. Exhibits
     *3.1    Articles  of Incorporation, as amended on April 20, 1993
             (Exhibit  3,  Form  10-Q for the quarter ended March 31,
             1993 of TECO Energy, Inc.).
     *3.2    Bylaws,  as  amended  effective  May 1, 1998 (Exhibit 3,
             Form  10-Q  for  the quarter ended June 30, 1998 of TECO
             Energy, Inc.).
     *4.1    Indenture  of  Mortgage  among  Tampa  Electric Company,
             State  Street  Trust  Company  and First Savings & Trust
             Company  of Tampa, dated as of Aug. 1, 1946 (Exhibit 7-A
             to Registration Statement No. 2-6693).
     *4.2    Thirteenth  Supplemental  Indenture  dated as of Jan. 1,
             1974,   to  Exhibit  4.1  (Exhibit  2-g-1,  Registration
             Statement No. 2-51204).
     *4.3    Sixteenth  Supplemental  Indenture, dated as of Oct. 30,
             1992,  to  Exhibit  4.1  (Exhibit 4.1, Form 10-Q for the
             quarter ended Sept. 30, 1992 of TECO Energy, Inc.).
     *4.4    Eighteenth  Supplemental  Indenture,  dated as of May 1,
             1993,  to  Exhibit  4.1  (Exhibit 4.1, Form 10-Q for the
             quarter ended June 30, 1993 of TECO Energy, Inc.).
     *4.5    Installment  Purchase  and Security Contract between the
             Hillsborough County Industrial Development Authority and
             Tampa  Electric  Company,  dated  as  of  March  1, 1972
             (Exhibit 4.9, Form 10-K for 1986 of TECO Energy, Inc.).
     *4.6    First  Supplemental  Installment  Purchase  and Security
             Contract,  dated  as of Dec. 1, 1974 (Exhibit 4.10, Form
             10-K for 1986 of TECO Energy, Inc.).
     *4.7    Third  Supplemental Installment Purchase Contract, dated
             as  of  May 1, 1976 (Exhibit 4.12, Form 10-K for 1986 of
             TECO Energy, Inc.).
     *4.8    Installment  Purchase  Contract between the Hillsborough
             C o unty  Industrial  Development  Authority  and  Tampa
             Electric  Company,  dated  as  of  Aug. 1, 1981 (Exhibit
             4.13, Form 10-K for 1986 of TECO Energy, Inc.).
     *4.9    Amendment to Exhibit A of Installment Purchase Contract,
             dated    April 7, 1983 (Exhibit 4.14, Form 10-K for 1989
             of TECO Energy, Inc.).
     *4.10   Second Supplemental Installment Purchase Contract, dated
             as  of June 1, 1983 (Exhibit 4.11, Form 10-K for 1994 of
             TECO Energy, Inc.). 
     *4.11   Third  Supplemental Installment Purchase Contract, dated
             as  of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of
             TECO Energy, Inc.).
     *4.12   Installment  Purchase  Contract between the Hillsborough
             C o unty  Industrial  Development  Authority  and  Tampa
             Electric  Company,  dated  as  of Jan. 31, 1984 (Exhibit
             4.13, Form 10-K for 1993 of TECO Energy, Inc.). 
     *4.13   First  Supplemental Installment Purchase Contract, dated
             as  of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for 1994 of
             TECO Energy, Inc.). 





                                  84
     *4.14   Second Supplemental Installment Purchase Contract, dated
             as  of  July  1,  1993  (Exhibit  4.3, Form 10-Q for the
             quarter ended June 30, 1993 of TECO Energy, Inc.).
     *4.15   Loan  and  Trust Agreement among the Hillsborough County
             Industrial Development Authority, Tampa Electric Company
             and  NCNB National Bank of Florida, as trustee, dated as
             of  Sept.  24,  1990  (Exhibit  4.1,  Form  10-Q for the
             quarter ended Sept. 30, 1990 for TECO Energy, Inc.).
     *4.16   Loan  and  Trust  Agreement,  dated  as of Oct. 26, 1992
             among  the  Hillsborough  County  Industrial Development
             Authority,  Tampa  Electric  Company  and NationsBank of
             Florida,  N.A.,  as  trustee (Exhibit 4.2, Form 10-Q for
             the quarter ended Sept. 30, 1992 of TECO Energy, Inc.).
     *4.17   Loan  and  Trust  Agreement,  dated as of June 23, 1993,
             among  the  Hillsborough  County  Industrial Development
             Authority,  Tampa  Electric  Company  and NationsBank of
             Florida,  N.A.,  as  trustee (Exhibit 4.2, Form 10-Q for
             the quarter ended June 30, 1993 of TECO Energy, Inc.).
     *4.18   Installment  Sales  Agreement  between  the  Plaquemines
             Port,  Harbor  and  Terminal  District  (Louisiana)  and
             Electro-Coal  Transfer Corporation, dated as of Sept. 1,
             1985  (Exhibit  4.19, Form 10-K for 1986 of TECO Energy,
             Inc.). 
     *4.19   Reimbursement  Agreement  between  TECO Energy, Inc. and
             Electro-Coal Transfer Corporation, dated as of March 22,
             1989  (Exhibit  4.19, Form 10-K for 1988 of TECO Energy,
             Inc.).
     *4.20   Rights Agreement between TECO Energy, Inc. and The First
             National  Bank  of  Boston, as Rights Agent, dated as of
             April  27, 1989 (Exhibit 4, Form 8-K, dated as of May 2,
             1989 of TECO Energy, Inc.). 
     *4.21   Amendment No. 1 to Rights Agreement dated as of July 20,
             1993  between  TECO  Energy  Inc. and the First National
             Bank  of  Boston,  as Rights Agent (Exhibit 1.2, Form 8-
             A/A, dated as of July 27, 1993 of TECO Energy, Inc.).
     *4.22   Renewed  Rights  Agreement between TECO Energy, Inc. and
             BankBoston,  N.A.  as Rights Agent, dated as of Oct. 21,
             1998  (Exhibit  4,  Form 8-K dated Oct. 31, 1998 of TECO
             Energy, Inc.).
     *4.23   Loan  and  Trust  Agreement,  dated  as of Dec. 1, 1996,
             among  the Polk County Industrial Development Authority,
             Tampa  Electric  Company  and  the  Bank of New York, as
             trustee.  (Exhibit  4.22,  Form  10-K  for  1996 of TECO
             Energy, Inc.).
     *4.24   First  Supplemental  Indenture dated as of July 15, 1998
             between Tampa Electric Company and the Bank of New York,
             as trustee (Exhibit 4.1, Form 10-Q for the quarter ended
             June 30, 1998 of TECO Energy, Inc.).
     *4.25   First  Supplemental  Indenture dated as of Sept. 1, 1998
             between  TECO  Energy, Inc. and The Bank of New York, as
             trustee  (Exhibit  4.1, Form 8-K dated Sept. 11, 1998 of
             TECO Energy, Inc.).
     *10.1   1980  Stock  Option  and  Appreciation  Rights  Plan, as
             amended  on  July  18, 1989 (Exhibit 28.1, Form 10-Q for
             quarter ended June 30, 1989 of TECO Energy, Inc.). 
     *10.2   S u pplemental  Executive  Retirement  Plan  for  H.  L.
             Culbreath,  as amended on April 27, 1989 (Exhibit 10.14,
             Form 10-K for 1989 of TECO Energy, Inc.).




                                  85
     *10.3   Supplemental Executive Retirement Plan for R. H. Kessel,
             as  amended  and  restated  as of Jan. 15, 1997 (Exhibit
             10.5, Form 10-K for 1996 of TECO Energy, Inc.).
     *10.4   TECO  Energy  Group  Supplemental  Executive  Retirement
             Plan,  as  amended  and  restated  as  of  Oct. 16, 1996
             (Exhibit 10.6, Form 10-K for 1996 of TECO Energy, Inc.).
     *10.5   TECO Energy Group Supplemental Retirement Benefits Trust
             Agreement  as  amended  and restated as of Jan. 15, 1997
             (Exhibit 10.7, Form 10-K for 1996 of TECO Energy, Inc.).
      10.6   Annual  Incentive  Compensation Plan for TECO Energy and
             subsidiaries, as revised Jan. 20, 1999.
     *10.7   TECO  Energy  Group Supplemental Disability Income Plan,
             dated as of March 20, 1989 (Exhibit 10.22, Form 10-K for
             1988 of TECO Energy, Inc.). 
     *10.8   Forms  of  Severance Agreement between TECO Energy, Inc.
             and  certain  senior executives, as amended and restated
             as  of  July  15,  1998 (Exhibit 10.1, Form 10-Q for the
             quarter ended Sept. 30, 1998 of TECO Energy, Inc.).
     *10.9   Severance  Agreement  between TECO Energy, Inc. and H.L.
             Culbreath,  dated  as  of April 28, 1989 (Exhibit 10.24,
             Form 10-K for 1989 of TECO Energy, Inc.).
     *10.10  Loan  and  Stock Purchase Agreement between TECO Energy,
             Inc.  and  Barnett Banks Trust Company, N.A., as trustee
             of  the  TECO  Energy Group Savings Plan Trust Agreement
             (Exhibit 10.3, Form 10-Q for the quarter ended March 31,
             1990 for TECO Energy, Inc.).
     *10.11  Supplemental  Executive Retirement Plan for A.D. Oak, as
             amended  and  restated  effective  as  of  Oct. 16, 1996
             (Exhibit  10.14,  Form  10-K  for  1996  of TECO Energy,
             Inc.).
     *10.12  S u pplemental  Executive  Retirement  Plan  for  G.  F.
             Anderson,  as  amended and restated effective as of Oct.
             16,  1996  (Exhibit  10.17,  Form  10-K for 1996 of TECO
             Energy, Inc.).
     *10.13  TECO  Energy  Directors'  Deferred Compensation Plan, as
             amended  and  restated  effective  as  of  April 1, 1994
             (Exhibit 10.1, Form 10-Q for the quarter ended March 31,
             1994 for TECO Energy, Inc.).
      10.14  TECO  Energy  Group  Retirement  Savings  Excess Benefit
             Plan,  as  amended and restated effective as of July 15,
             1998.
     *10.15  Supplemental  Executive  Retirement Plan for R. A. Dunn,
             as  amended  and  restated effective as of Jan. 15, 1997
             (Exhibit  10.20,  Form  10-K  for  1996  of TECO Energy,
             Inc.).
     *10.16  TECO  Energy,  Inc.  1996 Equity Incentive Plan (Exhibit
             10.1,  Form 10-Q for the quarter ended March 31, 1996 of
             TECO Energy, Inc.).
     *10.17  Form of Nonstatutory Stock Option under the TECO Energy,
             Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q
             for  the  quarter  ended  June  30, 1996 of TECO Energy,
             Inc.).
     *10.18  Form of Amendment to Nonstatutory Stock Option, dated as
             of  July  15,  1998,  under  the  TECO Energy, Inc. 1996
             Equity  Incentive  Plan (Exhibit 10.3, Form 10-Q for the
             quarter ended Sept. 30, 1998 of TECO Energy, Inc.).
     *10.19  Form  of Restricted Stock Agreement between TECO Energy,
             Inc.  and certain executives under the TECO Energy, Inc.
             1996  Equity Incentive Plan (Exhibit 10.1, Form 10-Q for
             the quarter ended June 30, 1998 of TECO Energy, Inc.).


                                  86
     *10.20  Form  of Amendment to Restricted Stock Agreements, dated
             as  of  July  15,  1998,  between  TECO Energy, Inc. and
             certain  senior  executives  under the TECO Energy, Inc.
             1996  Equity Incentive Plan (Exhibit 10.2, Form 10-Q for
             the quarter ended Sept. 30, 1998 of TECO Energy, Inc.).
     *10.21  Form  of Restricted Stock Agreement between TECO Energy,
             Inc. and G. F. Anderson under the TECO Energy, Inc. 1996
             Equity  Incentive  Plan (Exhibit 10.2, Form 10-Q for the
             quarter ended June 30, 1998 of TECO Energy, Inc.).
     *10.22  TECO  Energy,  Inc.  1997  Director Equity Plan (Exhibit
             10.1,  Form  8-K  dated  April  16, 1997 of TECO Energy,
             Inc.).
     *10.23  Form of Nonstatutory Stock Option under the TECO Energy,
             Inc.  1997  Director  Equity Plan (Exhibit 10, Form 10-Q
             for  the  quarter  ended  June  30, 1997 of TECO Energy,
             Inc.).
     *10.24  Supplemental Executive Retirement Plan for R. K. Eustace
             as  of  Jan. 15, 1997 (Exhibit 10.24, Form 10-K for 1997
             of TECO Energy, Inc.).
      12.    Ratio of Earnings to Fixed Charges.
      21.    Subsidiaries of the Registrant.
      23.    Consent of Independent Accountants.
      24.1   Power of Attorney.
       24.2  Certified  copy  of  resolution  authorizing  Power  of
             Attorney. 
      27     Financial Data Schedule (EDGAR filing only).
     _____________                
     *  Indicates  exhibit  previously  filed with the Securities and
     Exchange   Commission  and  incorporated  herein  by  reference.
     Exhibits  filed  with periodic reports of TECO Energy, Inc. were
     filed under Commission File No. 1-8180.

Executive Compensation Plans and Arrangements

     Exhibits  10.1  through  10.9  and 10.11 through 10.24 above are
management  contracts  or compensatory plans or arrangements in which
executive officers or directors of TECO Energy, Inc. participate.

     Certain  instruments defining the rights of holders of long-term
d e bt  of  TECO  Energy,  Inc.  and  its  consolidated  subsidiaries
authorizing  in  each case a total amount of securities not exceeding
10  percent  of  total  assets  on a consolidated basis are not filed
herewith.  TECO  Energy, Inc. will furnish copies of such instruments
to the Securities and Exchange Commission upon request.

(b)  TECO Energy, Inc. filed the following reports on Form 8-K during
     the last quarter of 1998. 

     The registrant filed a Current Report on Form 8-K dated Oct. 21,
     1998  reporting  under "Item 5. Other Events" the renewal of its
     existing shareholder rights plan.

     The registrant filed a Current Report on Form 8-K dated Dec. 17,
     1998  reporting under "Item 5. Other Events" fourth quarter 1998
     earnings expectations.

     





                                  87
                              SIGNATURES

     Pursuant  to  the  requirements  of  Section  13 or 15(d) of the
Securities  Exchange Act of 1934, the Registrant has duly caused this
report  to be signed on its behalf by the undersigned, thereunto duly
authorized on the 30th day of March, 1999.

                                  TECO ENERGY, INC.

                           By G. F. ANDERSON*                        
                              G. F. ANDERSON, Chairman of the Board, 
                                  President   and   Chief   Executive
Officer  

     Pursuant  to  the requirements of the Securities Exchange Act of
1934,  this report has been signed by the following persons on behalf
of the registrant and in the capacities indicated on March 30, 1999:

     Signature                    Title


     G. F. ANDERSON*              Chairman of the Board, President,
     G. F. ANDERSON               Director and Chief Executive
                                  Officer
                                  (Principal Executive Officer)

     /s/ G. L. GILLETTE           Vice President-Finance
         G. L. GILLETTE           and Chief Financial Officer
                                  (Principal Financial Officer)

     W. L. GRIFFIN*               Vice President-Controller
     W. L. GRIFFIN                (Principal Accounting Officer)

     C. D. AUSLEY*                Director
     C. D. AUSLEY

     S. L. BALDWIN*               Director
     S. L. BALDWIN

     H. L. CULBREATH*             Director
     H. L. CULBREATH

     J. L. FERMAN, JR.*           Director
     J. L. FERMAN, JR.

     E. L. FLOM*                  Director                           
     E. L. FLOM

     H. R. GUILD, JR.*            Director
     H. R. GUILD, JR.

     T. L. RANKIN*                Director
     T. L. RANKIN   

     R. L. RYAN*                  Director
     R. L. RYAN






                                  88
     W. P. SOVEY*                 Director
     W. P. SOVEY     

     J. T. TOUCHTON*              Director
     J. T. TOUCHTON

     J. A. URQUHART*              Director
     J. A. URQUHART

     J. O. WELCH, JR.*            Director
     J. O. WELCH, JR.

     *By: /s/ G. L. GILLETTE              
              G. L. GILLETTE, Attorney-in-fact
















































                                  89
                          INDEX TO EXHIBITS
 Exhibit                                                         Page
  No.     Description                                             No.

 3.1      Articles of Incorporation, as amended on                  *
          April 20, 1993 (Exhibit 3, Form 10-Q for the
          quarter ended March 31, 1993 of TECO Energy,
          Inc.).
 3.2      Bylaws, as amended effective May 1, 1998 (Exhibit 3,      *
          Form 10-Q for the quarter ended June 30, 1998 of
          TECO Energy, Inc.).
 4.1      Indenture of Mortgage among Tampa Electric                *
          Company, State Street Trust Company and First
          Savings & Trust Company of Tampa, dated as of
          Aug. 1, 1946 (Exhibit 7-A to Registration
          Statement No. 2-6693).
 4.2      Thirteenth Supplemental Indenture dated as                *
          of Jan. 1, 1974, to Exhibit 4.1 (Exhibit 2-g-1,
          Registration Statement No. 2-51204).
 4.3      Sixteenth Supplemental Indenture, dated as                *
          of Oct. 30, 1992, to Exhibit 4.1 (Exhibit 4.1,
          Form 10-Q for the quarter ended Sept. 30, 1992 of
          TECO Energy, Inc.).
 4.4      Eighteenth Supplemental Indenture, dated as               *
          of May 1, 1993, to Exhibit 4.1 (Exhibit 4.1, Form
          10-Q for the quarter ended June 30, 1993 of TECO
          Energy, Inc.).
 4.5      Installment Purchase and Security Contract                *
          between the Hillsborough County Industrial
          Development Authority and Tampa Electric Company,
          dated as of March 1, 1972 (Exhibit 4.9, Form 10-K
          for 1986 of TECO Energy, Inc.).
 4.6      First Supplemental Installment Purchase and               *
          Security Contract, dated as of Dec. 1, 1974
          (Exhibit 4.10, Form 10-K for 1986 of TECO Energy,
          Inc.).
 4.7      Third Supplemental Installment Purchase                   *
          Contract, dated as of May 1, 1976 (Exhibit 4.12,
          Form 10-K for 1986 of TECO Energy, Inc.).
 4.8      Installment Purchase Contract between the                 *
          Hillsborough County Industrial Development
          Authority and Tampa Electric Company, dated as of
          Aug. 1, 1981 (Exhibit 4.13, Form 10-K for 1986 of
          TECO Energy, Inc.).
 4.9      Amendment to Exhibit A of Installment                     *
          Purchase Contract, dated  April 7, 1983 (Exhibit
          4.14, Form 10-K for 1989 of TECO Energy, Inc.).
 4.10     Second Supplemental Installment Purchase                  *
          Contract, dated as of June 1, 1983 (Exhibit 4.11,
          Form 10-K for 1994 of TECO Energy, Inc.). 
 4.11     Third Supplemental Installment Purchase                   *
          Contract, dated as of Aug. 1, 1989 (Exhibit 4.16,
          Form 10-K for 1989 of TECO Energy, Inc.).
 4.12     Installment Purchase Contract between the                 *
          Hillsborough County Industrial Development
          Authority and Tampa Electric Company, dated as of
          Jan. 31, 1984 (Exhibit 4.13, Form 10-K for 1993
          of TECO Energy, Inc.). 
 4.13     First Supplemental Installment Purchase                   *
          Contract, dated as of Aug. 2, 1984 (Exhibit 4.14,


                                  90
          Form 10-K for 1994 of TECO Energy, Inc.). 
 4.14     Second Supplemental Installment Purchase Contract,        *
          dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q
          for the quarter ended June 30, 1993 of TECO
          Energy, Inc.).
 4.15     Loan and Trust Agreement among the Hillsborough           *
          County Industrial Development Authority, Tampa
          Electric Company and NCNB National Bank of
          Florida, as trustee, dated as of Sept. 24, 1990
          (Exhibit 4.1, Form 10-Q for the quarter ended
          Sept. 30, 1990 for TECO Energy, Inc.).
 4.16     Loan and Trust Agreement, dated as of Oct. 26,            *
          1992 among the Hillsborough County Industrial
          Development Authority, Tampa Electric Company and
          NationsBank of Florida, N.A., as trustee (Exhibit
          4.2, Form 10-Q for the quarter ended Sept. 30,
          1992 of TECO Energy, Inc.).
 4.17     Loan and Trust Agreement, dated as of                     *
          June 23, 1993, among the Hillsborough County
          Industrial Development Authority, Tampa Electric
          Company and NationsBank of Florida, N.A., as
          trustee (Exhibit 4.2, Form 10-Q for the quarter
          ended June 30, 1993 of TECO Energy, Inc.).
 4.18     Installment Sales Agreement between the                   *
          Plaquemines Port, Harbor and Terminal District
          (Louisiana) and Electro-Coal Transfer
          Corporation, dated as of Sept. 1, 1985 (Exhibit
          4.19, Form 10-K for 1986 of TECO Energy, Inc.). 
 4.19     Reimbursement Agreement between TECO Energy,              *
          Inc. and Electro-Coal Transfer Corporation, dated
          as of March 22, 1989 (Exhibit 4.19, Form 10-K for
          1988 of TECO Energy, Inc.).
 4.20     Rights Agreement between TECO Energy, Inc.                *
          and The First National Bank of Boston, as Rights
          Agent, dated as of April 27, 1989 (Exhibit 4,
          Form 8-K, dated as of May 2, 1989 of TECO Energy,
          Inc.). 
 4.21     Amendment No. 1 to Rights Agreement dated as              *
          of July 20, 1993 between TECO Energy Inc. and the
          First National Bank of Boston, as Rights Agent
          (Exhibit 1.2, Form 8-A/A, dated as of July 27,
          1993 of TECO Energy, Inc.).
 4.22     Renewed Rights Agreement between TECO Energy,             *
          Inc. and BankBoston, N.A. as Rights Agent, dated
          as of Oct. 21, 1998 (Exhibit 4, Form 8-K dated
          Oct. 31, 1998 of TECO Energy, Inc.).
 4.22     Loan and Trust Agreement, dated as of Dec. 1, 1996,       *
          among the Polk County Industrial Development
          Authority, Tampa Electric Company and the Bank of
          New York, as trustee(Exhibit 4.22, Form 10-K for
          1996 of TECO Energy, Inc.).
 4.24     First Supplemental Indenture dated as of July 15, 1998    *
          between Tampa Electric Company and the Bank of
          New York, as trustee (Exhibit 4.1, Form 10-Q for
          the quarter ended June 30, 1998 of TECO Energy,
          Inc.).
 4.25     First Supplemental Indenture dated as of Sept.            *
          1, 1998 between TECO Energy, Inc. and The Bank of
          New York, as trustee (Exhibit 4.1, Form 8-K dated
          Sept. 11, 1998 of TECO Energy, Inc.).


                                  91
10.1      1980 Stock Option and Appreciation Rights                 *
          Plan, as amended on July 18, 1989 (Exhibit 28.1,
          Form 10-Q for quarter ended June 30, 1989 of TECO
          Energy, Inc.). 
10.2      Supplemental Executive Retirement Plan for                *
          H. L. Culbreath, as amended on April 27, 1989
          (Exhibit 10.14, Form 10-K for 1989 of TECO
          Energy, Inc.).
10.3      Supplemental Executive Retirement Plan for                *
          R. H. Kessel, as amended and restated as of Jan.
          15, 1997 (Exhibit 10.5, Form 10-K for 1996 of
          TECO Energy, Inc.).
10.4      TECO Energy Group Supplemental Executive Retirement       *
          Plan, as amended and restated as of Oct. 16, 1996
          (Exhibit 10.6, Form 10-K for 1996 of TECO Energy,
          Inc.)
10.5      TECO Energy Group Supplemental Retirement Benefits        *
          Trust Agreement, as amended and restated as of
          Jan. 15, 1997 (Exhibit 10.7, Form 10-K for 1996
          of TECO Energy, Inc.).
10.6      Annual Incentive Compensation Plan for                   94
          TECO Energy and subsidiaries, as revised Jan. 20,
          1999.
10.7      TECO Energy Group Supplemental Disability Income          *
          Plan, dated as of March 20, 1989 (Exhibit 10.22,
          Form 10-K for 1988 of TECO Energy, Inc.).
10.8      Forms of Severance Agreement between TECO Energy,         *
          Inc. and certain senior executives, as amended
          and restated as of July 15, 1998 (Exhibit 10.1,
          Form 10-Q for the quarter ended Sept. 30, 1998 of
          TECO Energy, Inc.).
10.9      Severance Agreement between TECO Energy, Inc.             *
          and H.L. Culbreath, dated as of April 28, 1989
          (Exhibit 10.24, Form 10-K for 1989 of TECO
          Energy, Inc.).
10.10     Loan and Stock Purchase Agreement between                 *
          TECO Energy, Inc. and Barnett Banks Trust
          Company, N.A., as trustee of the TECO Energy
          Group Savings Plan Trust Agreement (Exhibit 10.3,
          Form 10-Q for the quarter ended March 31, 1990
          for TECO Energy, Inc.).
10.11     Supplemental Executive Retirement Plan                    *
          for A. D. Oak, as amended and restated effective
          as of Oct. 16, 1996 (Exhibit 10.14, Form 10-K for
          1996 of TECO Energy, Inc.).
10.12     Supplemental Executive Retirement Plan                    *
          for G. F. Anderson, as amended and restated
          effective as of Oct. 16, 1996 (Exhibit 10.17,
          Form 10-K for 1996 of TECO Energy, Inc.).
10.13     TECO Energy Directors' Deferred Compensation Plan,        *
          as amended and restated effective as of April 1, 1994 
          (Exhibit 10.1, Form 10-Q for the quarter ended 
          March 31, 1994 for TECO Energy, Inc.).
10.14     TECO Energy Group Retirement Savings Excess Benefit      98
          Plan, as amended and restated effective as of July 15,
          1998.
10.15     Supplemental Executive Retirement Plan for R. A. Dunn,    *
          as amended and restated effective as of Jan. 15, 1997
          (Exhibit 10.20, Form 10-K for 1996 of TECO Energy,
          Inc.).


                                  92
10.16     TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit     *
          10.1, Form 10-Q for the quarter ended March 31, 1996
          of TECO Energy, Inc.).
10.17     Form of Nonstatutory Stock Option under the TECO          *
          Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1,
          Form 10-Q for the quarter ended June 30, 1996 of TECO
          Energy, Inc.).
10.18     Form of Amendment to Nonstatutory Stock Option, dated     *
          as of July 15, 1998, under the TECO Energy, Inc.
          1996 Equity Incentive Plan (Exhibit 10.3, Form
          10-Q for the quarter ended Sept. 30, 1998 of TECO
          Energy, Inc.).
10.19     Form of Restricted Stock Agreement between TECO Energy,   *
          Inc. and certain executives under the TECO
          Energy, Inc. 1996 Equity Incentive Plan (Exhibit
          10.1, Form 10-Q for the quarter ended June 30,
          1998 of TECO Energy, Inc.).
10.20     Form of Amendment to Restricted Stock Agreements, dated   *
          as of July 15, 1998, between TECO Energy, Inc.
          and certain senior executives under the TECO
          Energy, Inc. 1996 Equity Incentive Plan (Exhibit
          10.2, Form 10-Q for the quarter ended Sept. 30,
          1998 of TECO Energy, Inc.).
10.21     Form of Restricted Stock Agreement between TECO Energy,   *
          Inc. and G. F. Anderson under the TECO Energy,
          Inc. 1996 Equity Incentive Plan (Exhibit 10.2,
          Form 10-Q for the quarter ended June 30, 1998 of
          TECO Energy, Inc.).
10.22     TECO Energy, Inc. 1997 Director Equity Plan               *
          (Exhibit 10.1, Form 8-K dated April 16, 1997 of
          TECO Energy, Inc.).
10.23     Form of Nonstatutory Stock Option under the TECO          *
          Energy, Inc. 1997 Director Equity Plan (Exhibit
          10, Form 10-Q for the quarter ended June 30, 1997
          of TECO Energy, Inc.).
10.24     Supplemental Executive Retirement Plan for R. K.          *
          Eustace as of Jan. 15, 1997 (Exhibit 10.24, Form
          10-K for 1997 of TECO Energy, Inc.).
12.       Ratio of Earnings to Fixed Charges.                     105
21.       Subsidiaries of the Registrant.                         106
23.       Consent of Independent Accountants.                     107
24.1      Power of Attorney.                                      108
24.2      Certified copy of resolution authorizing Power of
          Attorney.                                               110
27        Financial Data Schedule (EDGAR filing only).
_____________                
* Indicates exhibit previously filed with the Securities and Exchange
Commission and incorporated herein by reference. Exhibits filed with
periodic reports of TECO Energy, Inc. were filed under Commission
File No. 1-8180.












                                      93