TECO Energy 8-K Management’s Report on Internal Control Over Financial Reporting

Exhibit 99.2

MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS.

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. These forward-looking statements include references to TECO Energy’s anticipated capital investments, liquidity and financing requirements, projected operating results, future transactions and other plans. Certain factors that could cause actual results to differ materially from those projected in these forward-looking statements include: general economic conditions in Tampa Electric’s and Peoples Gas’ service areas affecting energy and gas sales; economic conditions, both national and international, affecting the demand for TECO Transport’s waterborne transportation services; state or federal regulatory actions that could reduce revenues or increase costs at all of TECO Energy’s operating companies; weather variations affecting energy and gas sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions; commodity price changes affecting the margins at TECO Coal; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional factors that could impact actual results include: the ability to complete the planned transfer of the Union and Gila River power stations to the lending group in the time frame anticipated; the ability to complete the sale of the Commonwealth Chesapeake Power Station; any debt extinguishment costs or premiums associated with the early retirement of TECO Energy debt; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; declines in the anticipated waterborne fuel volumes transported by TECO Transport for Tampa Electric; TECO Coal’s ability to successfully operate its synthetic fuel production facilities in a manner qualifying for Section 29 federal income tax credits, which could be impacted by changes in law, regulation or administration; and materially adverse outcomes in the disclosed litigation. Some of these factors and others are discussed more fully under “Investment Considerations.”

TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management’s Discussion and Analysis, “we,” “our,” “ours” and “us” refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.

OVERVIEW

Our actions in 2004 were driven by the implementation of the strategy announced in April 2003, which is to focus on our regulated utility operations in the high-growth Florida markets and our other profitable unregulated businesses and to reduce our exposure to the merchant power sector. A major component of this effort was an agreement to exit our ownership of the Union and Gila River power stations and to transfer the ownership of these power stations, which are part of the TECO Wholesale Generation (TWG) segment of TECO Energy that has been involved heretofore in merchant power activities. The exit strategy, which was announced in February 2004, is to transfer the ownership of these power stations to the lending group.

The continued generally poor financial performance at our other merchant power plants contributed to additional actions completed in 2004 that further reduced our exposure to the merchant power markets. (Merchant power plants are power plants that are not part of regulated utility operations, operate in the wholesale power market, and do not have long term contracts for the majority of their output. Most of the power from a merchant power plant is sold under short term agreements or in the more volatile wholesale power spot markets.) These actions included the sale of our 50% ownership interest in Texas Independent Energy (TIE), owner of two power plants in Texas; the sale of our 100% ownership interest in the Frontera Power Station in Texas; and the announcement in January 2005 of an agreement to sell the Commonwealth Chesapeake Power Station in Virginia. We experienced losses and value impairments on these sales and anticipated sales. In addition, we recognized an impairment of the value of the unfinished Dell and McAdams power stations, which there is a high probability we will no longer complete, to reflect the current market value for these plants. In 2004, we also sold the remaining major businesses in TECO Solutions, our small engineering and energy services unit, which operated in Florida as an adjunct to Peoples Gas. Some were sold at a gain and some at a loss. The components of TECO Solutions were acquired four or five years ago when it appeared that the Florida energy market would become more competitive.

With the commercial operation of the second phase of Tampa Electric’s H.L. Culbreath Bayside Power Station (Bayside) in January 2004, we completed the major power generation construction programs at Tampa Electric and TWG. With the construction programs complete, in 2004 we were able to build strong liquidity for normal operations and to begin accumulating the cash to position us to pay off all or the majority of our debt maturities in 2007.

For more than three months beginning in mid-August, Tampa Electric, Peoples Gas and TECO Transport were focused on either preparing for or recovering from the succession of major hurricanes that impacted Florida and surrounding states. Tampa Electric’s service area was directly impacted by three of the storms, each of which caused varying degrees of damage to its facilities and widespread customer outages. TECO Transport suffered no significant facility or equipment damage; however, its operations were disrupted by all four storms (see the Tampa Electric and TECO Transport sections).

Our financial results in 2004 were driven by the write-offs and valuation adjustments taken in the course of the year to eliminate the future risk to earnings and cash flow from the merchant power sector (see the Results Summary and TWG-Merchant sections).

The operations of the five core businesses, Tampa Electric, Peoples Gas, TECO Coal, TECO Transport and the Guatemalan operations, were fundamentally sound in 2004. While TECO Transport experienced difficult market and operating conditions in the course of the year, these five companies produced good operating results. (See the individual operating companies for a detailed discussion of their respective results.)

RESULTS SUMMARY

Our financial results for 2004 reflect the write-offs resulting from the sales of our merchant generating assets and asset valuation adjustments associated with the remaining unfinished merchant power plants. The net loss in 2004 was $552.0 million, primarily due to $555.6 million of charges and gains detailed in the 2004 Non-operating Items Affecting Net Income table. The net loss from continuing operations in 2004 was $355.5 million, compared with net income from continuing operations of $100.7 million in 2003. Non-GAAP (Generally Accepted Accounting Principles) results from continuing operations excluding the charges and gains detailed in the 2004 Non-operating Items Affecting Net Income table were $153.1 million in 2004, compared with $172.3 million in 2003. Results from discontinued operations in 2004 reflect primarily the operating results from the Commonwealth Chesapeake (CCC), Frontera, Union and Gila River power stations, BCH Mechanical, and the 2004 write-offs and charges associated with these businesses.

The sale of our interests in our merchant generating assets in Texas, the announced sale of Commonwealth Chesapeake Power Station in Virginia, and the adjustment of the value of the unfinished Dell and McAdams power stations to reflect the current fair market value resulted in $562.5 million of after-tax write-offs in 2004, comprised of $431.3 million in continuing operations and $131.2 million in discontinued operations.

Results from continuing operations in 2004 were lower than 2003, primarily due to the write-offs associated with the merchant power plants and other charges detailed in the 2004 Non-operating Items Affecting Net Income table. Excluding these charges and gains, results from continuing operations were lower due to the sale of an additional 40.5% membership interest in TECO Coal’s synthetic fuel production facilities, much lower equity Allowance for Funds Used During Construction income (AFUDC, which represents allowed equity cost capitalized to construction costs) at Tampa Electric, and lower results at TECO Transport. The sale of the portion of the synthetic fuel production facilities is and will continue to generate significant cash, but earnings at a lower level, due to our continued role in operating the synthetic fuel production facilities at a time when TECO Energy cannot utilize the Section 29 tax credits. The net loss on a per share basis was $2.87 in 2004, compared with net loss of $5.05 in 2003. The loss from continuing operations on a per share basis was $1.85 in 2004, compared with earnings per share from continuing operations of $0.56 in 2003. The number of average shares outstanding at Dec. 31, 2004 was 7% higher than at Dec. 31, 2003 primarily due to the shares issued in the early settlement offer for our equity security units completed in August.

In 2003, results from continuing operations were lower than in 2002, primarily due to charges associated with the impairment of some of our merchant power assets, charges for corporate restructuring and staffing reductions, valuation adjustments at the energy services companies and limitations on the use of tax credits (see the table 2003 Non-operating Items Affecting Net Income). Excluding these charges and gains, results from continuing operations were lower due to higher depreciation and interest expense at Tampa Electric; continued weak results at TECO Transport due to lower coal tonnage for Tampa Electric and continued weakness in the river business; higher interest expense at the TECO Energy parent level associated with the debt incurred to fund the TWG projects; lower results from TWG’s interest in the TIE projects in Texas; and the elimination of interest and support income from Panda Energy related to the TIE projects. These results were partially offset by the gain on the sale of Hardee Power Partners, higher operating results at TECO Coal from increased synthetic fuel production and sales, and the sale of the 49.5% membership interest in the synthetic fuel production facilities. The net loss on a per-share basis was $5.05 in 2003, compared with earnings of $2.15 per share in 2002. Earnings per share from continuing operations were $0.56 in 2003, compared with earnings per share from continuing operations of $1.73 in 2002. The average number of shares outstanding at Dec. 31, 2003 was more than 17% higher than at Dec. 31, 2002.

2004 Earnings Summary

(millions) Except per-share amounts	2004			2003			2002
Consolidated revenues	$	2,639.4		$	2,562.9		$	2,487.3
Earnings (loss) per share – basic
Earnings per share	$	(2.87	)	$	(5.05	)	$	2.15
Discontinued operations		(1.02	)		(5.59	)		0.42
Earnings from continuing operations before cumulative effect of change in accounting principle		(1.85	)		0.54			1.73
Cumulative effect of change in accounting principle		—			(0.02	)		—
Earnings (loss) from continuing operations	$	(1.85	)	$	0.56		$	1.73
Earnings (loss) per share – diluted
Earnings per share	$	(2.87	)	$	(5.04	)	$	2.15
Discontinued operations		(1.02	)		(5.58	)		0.42
Earnings from continuing operations before cumulative effect of change in accounting principle		(1.85	)		0.54			1.73
Cumulative effect of change in accounting principle		—			(0.02	)		—
Earnings (loss) from continuing operations	$	(1.85	)	$	0.56		$	1.73
Net income (loss)	$	(552.0	)	$	(909.4	)	$	330.1
Net income (loss) from discontinued operations		(196.5	)		(1,005.8	)		64.7
Charges and gains from continuing operations		(508.6	)		(71.6	)		(28.6	)
Cumulative effect of change in accounting principle		—			(4.3	)		—
Non-GAAP results from continuing operations (1)	$	153.1		$	172.3		$	294.0
Average common shares outstanding
Basic		192.6	(4)		179.9	(3)		153.2	(2)
Diluted		192.6	(4)		180.2	(3)		153.3	(2)

(1) A non-GAAP financial measure is a numerical measure of historical or future financial performance, financial position or cash flow that includes amounts, or is subject to adjustments, that have the effect of including amounts, that are excluded from the most directly comparable GAAP measure so calculated and presented.

(2) Average shares outstanding for 2002 reflects the issuance of 15.525 million shares in June 2002 and 19.385 million shares in October 2002 amongst other issuances

(3) Average shares outstanding for 2003 reflects the issuance of 11 million shares in September amongst other issuances.

(4) Average shares outstanding for 2004 reflect the issuance of 10.2 million shares in September in conjunction with the early settlement of the 9.5% adjustable conversion-rate equity security units amongst other issuances.

Non-GAAP Information

Many times in this Management’s Discussion and Analysis we will refer to non-GAAP results. Management uses non-GAAP results, which excludes certain charges and gains, to measure the performance of our operations. For a more complete discussion of our use of non-GAAP results see the Non-GAAP Presentation section.

2004 Non-operating Items Affecting Net Income

Net income impact (millions)	Tampa Electric		TWG Merchant			Peoples Gas		TECO Transport		TECO Coal			Other Unregulated		Parent/ Other			Total
Merchant power valuations	$	—	$	480.7		$	—	$	—	$	—		$	—	$	—		$	480.7
Steam turbine valuations		—		—			—		—		—			12.8		—			12.8
Debt extinguishment		—		—			—		—		—			6.7		(0.5	)		6.2
Taxes on cash repatriation		—		—			—		—		—			17.4		—			17.4
Asset impairment		—		—			—		0.6		—			—		—			0.6
Restructuring charges		—		—			0.4		1.1		—			—		5.0			6.5
Valuation adjustment		—		—			—		—		—			3.4		—			3.4
Tax credit reversals		—		—			—		—		(7.0	)		—		—			(7.0	)
Total charges	$	—	$	480.7		$	0.4	$	1.7	$	(7.0	)	$	40.3	$	4.5		$	520.6
Gain on asset sales	$	—	$	—		$	—	$	—	$	—		$	12.0	$	—		$	12.0
Discontinued operations:
TMDP arbitration reserve	$	—	$	(4.3	)	$	—	$	—	$	—		$	—	$	—		$	(4.3	)
Valuation adjustments		—		76.9			—		—		—			20.3		—			97.2

2003 Non-operating Items Affecting Net Income

Net income impact (millions)	Tampa Electric		TWG Merchant		Peoples Gas		TECO Transport		TECO Coal		Other Unregulated		Parent/ Other		Total
Turbine valuations	$	48.9	$	—	$	—	$	—	$	—	$	28.5	$	—	$	77.4
Restructuring charges		6.1		0.3		2.6		1.0		—		3.6		1.6		15.2
Project cancellation costs		—		—		—		—		—		9.0		—		9.0
Valuation adjustment		—		—		—		—		—		3.2		—		3.2
Tax credit reversals		—		—		—		—		7.0		2.7		—		9.7
Change in accounting		—		—		—		0.8		0.3		—		3.2		4.3
Total charges	$	55.0	$	0.3	$	2.6	$	1.8	$	7.3	$	47.0	$	4.8	$	118.8
Hardee Power Partners
Gain on sale and operations	$	—	$	—	$	—	$	—	$	—	$	42.9	$	—	$	42.9
Discontinued operations:
Goodwill impairment	$	—	$	16.3	$	—	$	—	$	—	$	—	$	—	$	16.3
TMDP arbitration reserve	$	—	$	26.7	$	—	$	—	$	—	$	—	$	—	$	26.7
Valuation adjustments	$	—	$	806.9	$	—	$	—	$	—	$	20.7	$	—	$	827.6
Loss on joint venture termination	$	—	$	94.7	$	—	$	—	$	—	$	—	$	—	$	94.7
Gain on sale of TECO Coalbed Methane	$	—	$	—	$	—	$	—	$	—	$	23.5	$	—	$	23.5

STRATEGY AND OUTLOOK

In April 2003, we announced that our business strategy would change to focus on our electric and gas utilities, which operate in the high-growth Florida market, and our long-term profitable unregulated businesses and to reduce our exposure to the merchant power sector. This change in strategic direction followed a series of major investments in unregulated domestic power generation facilities outside of Florida in the 2000 through 2003 period and other smaller investments in unregulated energy service providers within Florida, in anticipation of a movement toward competitive energy markets in Florida and other states in which we were investing in new power plants. During that same period, we also continued the development of the regulated electric and gas businesses in Florida, including significant additions to Tampa Electric’s electric generation and Peoples Gas System (PGS) infrastructure.

After we had committed to the major investments in unregulated power, starting in late 2001 and early 2002, conditions in energy markets and the independent power business changed dramatically, which reduced the prospects for the profitability of the investments in our unregulated domestic independent power generation facilities. At the time we decided to expand the independent power operations, our strategy was to construct facilities and sign contracts for the majority of the output and have only a small percentage of the output in the spot, or merchant, market. The wholesale power market evolved differently, however, and most of these facilities’ sales were short-term agreements and spot sales. During the same period, wholesale power prices declined significantly in markets across the country for many reasons, including a general slowing, or in some states a reversal, of the movement towards wholesale electric competition and the large amount of new generating capacity which came online in 2002 and 2003 that contributed to significant excess generating capacity in many areas of the country.

In April 2003, we also stated that we were ceasing any new development activities in the independent power business and would take steps to reduce our exposure to merchant power. Following the completion of the large Union and Gila River power stations, in the face of prolonged weak conditions in the merchant energy markets, in October 2003, we announced that we would invest little, if any, additional cash in the existing merchant generating plants. Following a thorough review of the outlook for the non-recourse, project-financed Union and Gila River power plants, and assessment of our ability to continue to support the plants, we decided to cease providing additional funding to the projects and to sell our ownership interest in these projects to the lending group or others (see the TWG-Merchant section).

In general, wholesale power prices remained weak in 2004, and the prospects for long-term price recovery appear poor for the next several years in markets where we had made major investments in unregulated power plants. These changed market conditions, persistent low power prices and lack of long-term contracts have caused weaker earnings and cash flow expectations and caused us to continue to delay some projects and sell others. These conditions led us to a number of actions in 2004 which, while resulting in additional write-offs and impairment charges, further reduced our merchant energy exposure.

In 2004, we completed sales of our interests in two of TWG’s three operating merchant power projects, and in January 2005, we announced an agreement to sell the third. We also sold our unregulated energy service businesses in 2004 and in January 2005. With the elimination of these unprofitable and higher risk businesses, we are positioned to focus on our five core businesses: the electric and gas utilities, the unregulated coal and transportation businesses, and the profitable wholesale power generating plants with contracts and our distribution investment in Guatemala.

In 2002 and 2003, we took significant steps to meet the cash obligations and liquidity needs associated with the completion of our large construction program including asset sales, cancellation of projects, a dividend reduction and capital markets transactions. As discussed in the Liquidity, Capital Resources section, our current and future liquidity needs are lower than in previous years and are now at levels more appropriate for our expected significantly lower levels of capital expenditures and lower risk business profile.

With the elimination of the associated losses expected from the merchant power operations, we expect improved financial results, with contributions from our regulated businesses, Tampa Electric and PGS, and the profitable unregulated businesses. Capital expenditures, except for the required environmental capital expenditures at Tampa Electric, are expected to be near maintenance levels for the next several years. We have no significant corporate debt maturities until 2007. We expect to use free cash flow generated in the 2005 through 2007 period to retire all or the majority of the TECO Energy debt maturing in 2007. We expect our financial results in 2005 to provide a base from which we will seek to return to a stronger financial position and improve earnings in the future. In addition, our goal, over time, through our actions to reduce debt and reduce business risk identified in our strategy is to return to an investment grade credit rating.

A major source of the cash that we expect to generate is through the sale of the membership interests in TECO Coal’s synthetic fuel production facilities and the Section 29 tax credits generated by the ownership for the third-party owners. These tax credits will expire Dec. 31, 2007, and, while we cannot predict if these tax credits will be extended or renewed in their current form, we are assuming that there will be no change in the current legislation. Based on the assumption that the tax credits expire as scheduled, both net income and cash flow at TECO Coal are expected to decline in 2008 due to the loss of the benefits from the sale of the third-party ownership interests.

In 2008, TECO Coal expects to no longer produce synthetic fuel, but it expects to produce conventional coal at levels approximately the same as current total production (approximately 9 million tons). When production of synthetic fuel ends, TECO Coal will stop mining the high-cost coals currently being mined for use in the production of synthetic fuel and will stop operating the synthetic fuel production equipment, which are expected to reduce production costs. At that time, the earnings and cash flow from TECO Coal will be dependent on the selling price of coal in 2008, and its ability to manage production costs. Prior to the expiration of the Section 29 tax credits at the end of 2007, we expect to develop a strategy directed toward mitigating the reduction in earnings and cash flow that will result from the expiration. The strategy will be focused on optimizing our coal operations for operating in the post-Section 29 tax credit environment, and improving results from all of the operating companies, and reducing interest expense at the parent. Based on our cash flow projections and our expected ability to retire all or the majority of the $680 million of TECO Energy corporate debt maturing in 2007, we expect earnings and cash flow to benefit from lower interest expense and lower cash interest payments in 2008.

OPERATING RESULTS

Management’s Discussion & Analysis of Financial Condition and Results of Operations utilizes TECO Energy’s consolidated financial statements, which have been prepared in accordance with GAAP, to analyze the financial condition of the company. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, asset impairment testing and others (see the Critical Accounting Policies and Estimates section).

The following table shows the unconsolidated revenues and net income and earnings per share contributions from continuing operations of our business segments (seeNote 14to the TECO EnergyConsolidated Financial Statements).

(millions) Except per share amounts	2004			2003			2002
Unconsolidated Revenues (1)
Regulated companies
Tampa Electric	$	1,687.4		$	1,586.1		$	1,583.2
Peoples Gas System		417.2			408.4			318.1
Total regulated		2,104.6			1,994.5			1,901.3
Unregulated companies
TECO Coal		327.6			296.3			317.1
TECO Transport		249.6			260.6			254.6
Other unregulated businesses		36.6			173.5			215.8
TWG - Merchant		7.6			(2.5	)		4.9
Total unregulated	$	621.4		$	727.9		$	792.4
Net Income (loss) (2)
Regulated companies
Tampa Electric	$	146.0		$	98.9		$	171.8
Peoples Gas System		27.7			24.5			24.2
Total regulated		173.7			123.4			196.0
Unregulated companies
TECO Coal		61.3			77.1			76.4
TECO Transport		10.2			15.3			21.0
Other unregulated businesses		12.1			23.2			27.0
TWG - Merchant		(534.1	)		(60.8	)		(18.8	)
Total unregulated		(450.5	)		54.8			105.6
Financing/Other		(78.7	)		(77.5	)		(36.2	)
Net income (loss) from continuing operations	$	(355.5	)	$	100.7		$	265.4
Discontinued operations		(196.5	)		(1,005.8	)		64.7
Net income (loss) before cumulative effect of change in accounting principle		(552.0	)		(905.1	)		330.1
Cumulative effect of a change in accounting principle		—			(4.3	)		—
Net income	$	(552.0	)	$	(909.4	)	$	330.1
Earnings per Share - Basic (2)
Regulated companies
Tampa Electric	$	0.76		$	0.55		$	1.12
Peoples Gas System		0.14			0.14			0.16
Total regulated		0.90			0.69			1.28
Unregulated companies
TECO Coal		0.32			0.43			0.50
TECO Transport		0.06			0.08			0.14
Other unregulated businesses		0.06			0.13			0.17
TWG - Merchant		(2.78	)		(0.34	)		(0.12	)
Total unregulated		(2.34	)		0.30			0.69
Financing/Other		(0.41	)		(0.43	)		(0.24	)
Earnings (loss) per share from continuing operations	$	(1.85	)	$	0.56		$	1.73
Discontinued operations		(1.02	)		(5.59	)		0.42
Earnings (loss) per share before cumulative effect of change in accounting principle		(2.87	)		(5.03	)		2.15
Cumulative effect of a change in accounting principle		—			(0.02	)		—
EPS Total	$	(2.87	)	$	(5.05	)	$	2.15

(1) Revenues for all periods have been adjusted to reflect the presentation of energy marketing related revenues on a net basis and the reclassification of the results from those businesses that have been sold to discontinued operations (see the Discontinued Operations section). Unconsolidated revenues include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements.

(2) Segment net income is reported on a basis that includes internally allocated financing costs to the unregulated companies. Internally allocated finance costs for 2004, 2003 and 2002 were at pretax rates of 8%, 8% and 7%, respectively, based on the average investment in each unregulated subsidiary.

TAMPA ELECTRIC

Electric Operations Results

Tampa Electric’s 2004 net income was $146.0 million, compared to $98.9 million in 2003. Non-GAAP results in 2003, which excluded turbine purchase cancellations and restructuring charges, were $153.9 million. These results were driven by lower non-fuel operating expenses, continued strong customer growth and higher energy sales offset by lower AFUDC equity, an $8.2 million after-tax disallowance by the Florida Public Service Commission (FPSC) for the recovery of a portion of the waterborne transportation costs for delivery of solid fuel (see the Regulation section), and weather patterns that resulted in 3% lower total-degree days than normal and almost 7% lower total- degree days than 2003, when total-degree days were more than 4% above normal. The equity component of AFUDC, from the Gannon to Bayside repowering project, decreased to $0.7 million, compared to $19.8 million in 2003.

Tampa Electric’s net income in 2003 was $98.9 million, compared to $171.8 million in 2002. Non-GAAP results in 2003 were $153.9 million, excluding a $48.9 million after-tax write-off associated with combustion turbine purchase cancellation and a $6.1 million after-tax restructuring charge. The decrease was due to after-tax accelerated depreciation related to Gannon Station coal-fired assets of $22.6 million, a $5.1 million after-tax disallowance by the FPSC for operations and maintenance expenses for the Gannon Station, lower AFUDC equity and higher interest expense. The expense items previously noted, lower sales to other utilities and decreased sales to phosphate customers more than offset continued good residential and commercial customer growth, lower operations and maintenance expenses and more favorable summer weather. The equity component of AFUDC decreased to $19.8 million in 2003, compared to $24.9 million in 2002 due to the April in-service date of Bayside Unit 1.

In 2004, Tampa Electric’s service area was impacted by hurricanes Charley, Frances and Jeanne. These storms caused more than 600,000 customer outages and damaged the transmission and distribution systems and other facilities. The restoration costs were expected to be $72 million, which exceeded Tampa Electric’s $44 million year-end unfunded storm damage reserve balance. Although rate base, operations and maintenance expense and capital expenditures were not affected by hurricane restoration costs, as costs were charged to the storm damage reserve, Tampa Electric paid an estimated $52 million of cash for hurricane restoration in 2004 with $20 million to be paid in 2005. In addition, the storms reduced pretax base revenues by an estimated $4.9 million, which by definition are not covered by the storm damage reserve. Tampa Electric has received FPSC approval for deferral of the $28 million until the company seeks alternative accounting treatment for the costs that exceed the reserve balance (see the Regulation section).

Summary of Operating Results – Tampa Electric

(millions)	2004		% Change	2003		% Change	2002
Revenues	$	1,687.4	6.4	$	1,586.1	0.2	$	1,583.2
Other operating expenses		190.5	-6.1		202.8	-4.5		212.3
Maintenance		87.2	-4.0		90.8	-16.5		108.7
Depreciation		180.9	-14.0		210.3	10.8		189.8
Taxes, other than income		120.8	7.3		112.6	0.3		112.3
Non-fuel operating expenses		579.4	-6.0		616.5	-1.1		623.1
Fuel		612.9	38.3		443.3	4.5		424.1
Purchased power		172.3	-26.6		234.9	-7.4		253.7
Total fuel expense		785.2	15.8		678.2	0.1		677.8
Turbine valuation adjustment		—	—		79.6	—		—
Total operating expenses		1,364.6	-0.7		1,374.3	5.6		1,300.9
Operating income	$	322.8	52.4	$	211.8	-25.0	$	282.3
AFUDC Equity	$	0.7	-96.5	$	19.8	-20.5	$	24.9
Net income	$	146.0	47.6	$	98.9	-42.4	$	171.8
Turbine cancellation charges after-tax		—	—		48.9	—		—
Restructuring charges after-tax		—	—		6.1	—		10.3
Net income before charges	$	146.0	-5.1	$	153.9	-15.5	$	182.1

Tampa Electric Operating Revenues

Retail megawatt-hour sales rose 1.1% in 2004, primarily from increased residential and commercial sales driven by customer growth. Electricity sales to the lower margin industrial customers in the phosphate industry decreased 3.7% in 2004 after a 7.4% decrease in 2003. The 2004 decline in sales to phosphate customers was driven by natural reserve depletion and migration of mining operations out of Tampa Electric’s service area. In 2004, following several years of low prices for phosphate fertilizers and high raw material costs, phosphate prices returned to levels that support normal production. In 2003, low prices contributed to temporary closures of phosphate production facilities during the year. Domestic phosphate consumption and prices are expected to remain relatively stable for the next several years with increased demand from China

driving an improved export market. Tampa Electric’s phosphate customers have indicated that, with the price improvement experienced in 2004, they expect production to remain stable in 2005. Base revenues from phosphate sales represented less than 3% of base revenues in 2004 and 2003. Non-phosphate industrial sales increased in 2004 and 2003, primarily reflecting continued economic growth in the area.

Base rates for all customers were unchanged in 2004. Fuel-related revenues increased in 2004 and 2003 under the FPSC- approved fuel adjustment clause due to the recovery of previous under recoveries of fuel expense in 2003 and 2002 and higher gas prices. Customer’s rates under the fuel adjustment clause would increase in 2005 in accordance with the rates approved by the FPSC in November 2004, to reflect the higher cost of natural gas and increased usage of natural gas due to the completion of the Bayside repowering in January 2004. The customer fuel adjustment charge increase from higher fuel prices will, however, be more than offset by the approximately $15 million pretax disallowance of the recovery from customers of a portion of the waterborne solid fuel transportation costs, which are recovered through the fuel adjustment clause (see the Regulation section).

Sales to other utilities for resale declined in 2004, primarily as a result of lower capacity being available from coal-fired generating units due to the conversion of the coal-fired Gannon Station to natural gas. Incremental generation among the utilities in Florida is primarily natural gas-fired; therefore, the Bayside units compete with all other units burning the same fuel in the state. Sales to other utilities declined in 2003, primarily due to the lack of coal-fired generating unit availability as the Gannon units underwent the conversion to natural gas, and the Jan. 1, 2003 expiration of the Big Bend Station power sales agreement with Hardee Power Partners. Energy sales to other utilities are expected to remain stable in 2005.

Based on projected growth from continued population increases and business expansion, Tampa Electric expects weather-normalized average retail energy sales growth of more than 2.5% annually over the next five years, with combined energy sales growth in the residential and commercial sectors of 3% annually. Tampa Electric’s forecasts indicate that summer retail peak demand growth is expected to average more than 100 megawatts per year for the next five years. These growth projections assume continued local area economic growth, normal weather and a continuation of the current energy market structure (see theInvestment Considerations section).

The economy in Tampa Electric’s service area continued to grow in 2004, aided by the region’s relatively low labor rates, attractive cost of living and relatively affordable housing. The Tampa metropolitan area’s non-farm employment grew 2.1% in 2004 due to a stronger local economy. Employment grew 1.2% in 2003 in spite of the U.S. economic slowdown in the first half of the year. The local Tampa area unemployment rate fell to 3.5% at year-end 2004, compared with 3.8% in December 2003, and 4.2% in December 2002. These rates are lower than the year-end 4.5% unemployment rate for the State of Florida and 5.4% for the nation. During the U.S. economic slowdown in 2002 and early 2003, the Tampa area, with its diverse service-based economy, did not experience the same drop in economic activities as those areas of the country with manufacturing-based economies and recovered sooner.

Megawatt – Hour Sales

(thousands)	2004	% Change	2003	% Change	2002
Residential	8,293	0.3	8,265	2.7	8,046
Commercial	5,988	2.2	5,860	0.5	5,832
Industrial	2,556	-0.9	2,579	-1.3	2,612
Other	1,600	4.0	1,538	7.2	1,435
Total retail	18,437	1.1	18,242	1.8	17,925
Sales for resale	664	-3.9	691	-36.3	1,084
Total energy sold	19,101	0.9	18,933	-0.4	19,009
Retail customers-thousands (average)	619.5	2.4	604.9	2.5	590.2

Tampa Electric Operating Expenses

Total operating expense decreased slightly in 2004 as higher fuel costs due to increased use of natural gas largely offset lower non-fuel operating and maintenance expenses and lower purchased power costs. Non-fuel operating and maintenance expenses decreased from the lower manpower requirements and lower maintenance requirements of the natural gas-fired repowered Bayside Station compared to the coal-fired Gannon Station. Operating expenses were also reduced by the restructuring activities in 2002 and 2003, which reduced the number of employees 12% during the two-year period.

In 2003, total operating expenses, excluding the $79.6 million pretax charge for combustion turbine purchase cancellations, were almost unchanged from 2002 levels as lower non-fuel operations and maintenance expenses for power generation plants and lower purchased power expenses largely offset higher fuel costs from increased use of higher cost natural gas, higher depreciation and increased employee benefits costs.

After significant reductions in 2004, non-fuel operations and maintenance expenses are expected to increase at slightly above the rate of inflation in 2005 due to normal operating and maintenance expense growth and higher employee-related costs, such as pension expenses.

Depreciation expense decreased in 2004 due to the end of the accelerated depreciation in 2003 related to the retirement of the Gannon Station coal-fired assets, which more than offset the additional depreciation from the addition of

Bayside Unit 2. (See the Environmental Compliance section.) Accelerated depreciation of the Gannon Station coal-fired assets was $36.6 million pretax in 2003. Depreciation expense is projected to increase in 2005, due to normal plant additions to serve the growing customer base and maintain system reliability.

Fuel costs increased 38.3% in 2004 after a 4.5% increase in 2003, primarily due to increased use of natural gas at the Bayside Power Station and higher natural gas prices. On a per million Btu basis, natural gas consumption increased 75% in 2004 while coal usage decreased 16.7%, which is in line with the increased generation from natural gas and decreased generation from coal as a result of the Bayside repowering. Fuel prices increased across the board in 2004, with increases per million Btu ranging from 5.6% for coal to 10.7% for natural gas. The delivered cost of natural gas has increased since 2002 when prices were $5.86 per million Btu to the 2004 average price of $7.14 per million Btu. Coal prices have also increased during that period from a delivered cost of $1.93 per million Btu in 2002 to $2.14 per million Btu in 2004. Coal and natural gas prices are expected to stay near the current levels due to the current world supply and demand situation, general economic conditions and the current high price of oil.

On a total energy supply basis, Tampa Electric generation accounted for 94.9%, 88.2% and 87.2% of the total retail energy sales in 2004, 2003 and 2002, respectively. The percentage increased due to the increased reliability and availability of the Bayside Station compared to the older Gannon Station.

Prior to 2003, nearly all of Tampa Electric’s generation was from coal. Starting in April 2003, the mix started to shift, with increased use of natural gas at Bayside. Nevertheless, coal is expected to continue to be more than half of Tampa Electric’s fuel mix due to the base load units at Big Bend and the coal gasification unit, Polk Unit One.

The amount of power purchased by Tampa Electric to serve its customers decreased in 2004 following a decrease in 2003, primarily due to the operations of Bayside. Purchased power is expected to decline again in 2005, due to the operation of Bayside Station and coal unit availability.

PEOPLES GAS SYSTEM

Summary of Operating Results

Peoples Gas (PGS) net income was $27.7 million in 2004, compared to $24.5 million in 2003. Non-GAAP results in 2004 were $28.1 million, excluding a $0.4 million after-tax restructuring charge, compared to non-GAAP results of $27.1 million in 2003, which exclude a $2.6 million after-tax restructuring charge. Results in 2004 reflect 5.3% customer growth partially offset by higher operating expenses. Results in 2003 reflect 5.2% customer growth and a $12 million base revenue increase effective in January 2003.

Historically, the natural gas market in Florida has been underserved with the lowest market penetration in the southeastern U.S. In 2003, natural gas had a market penetration rate of 9% compared to the next lowest state in the southeast, North Carolina, with 29%. PGS has targeted residential customer growth through agreements with builders in new residential communities throughout Florida, which have significantly higher expected average annual usage per-household than the current average.

In 2004, residential and commercial therm sales increased through customer growth. Usage per customer decreased compared to 2003 due to milder winter weather. In 2003, residential and commercial therm sales increased from customer growth of over 5%, and colder than normal early winter weather. Volumes transported for power generation customers declined again in 2004 after declining in 2003. The high gas prices experienced in 2003 persisted throughout 2004, spiking to near record levels in the fall of 2004 when oil prices rose above $50 per barrel. While the higher cost of gas has had a negative impact on sales to larger interruptible and power generation customers, especially in the second half of 2003 and into the first half of 2004, most of those who could switch fuels had already done so by mid-year 2004. Many of these customers have the ability to switch to alternative fuels or to alter consumption patterns in response to rising natural gas prices. Because these are lower-margin sales, the decrease has not significantly affected PGS results.

The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a Purchased Gas Adjustment (PGA) approved by the FPSC annually.

Summary of Operating Results

(millions)	2004		% Change	2003		% Change	2002
Revenues	$	417.2	2.1	$	408.4	28.4	$	318.1
Cost of gas sold		226.2	1.0		224.0	50.3		149.0
Operating expenses		131.1	0.8		130.0	12.5		115.6
Operating income		59.9	10.1		54.4	1.7		53.5
Net income		27.7	13.1		24.5	1.2		24.2
Restructuring charges		0.4	—		2.6	—		—
Net income before charges	$	28.1	3.7	$	27.1	12.0	$	24.2
Therms sold - by customer segment
Residential		65.8	2.5		64.2	6.6		60.2
Commercial		368.1	3.7		354.8	8.3		327.6
Industrial		399.5	-1.7		406.3	-4.1		423.8
Power generation		291.6	-19.8		363.7	-26.2		492.6
Total		1,125.0	-5.4		1,189.0	-8.8		1,304.2
Therms sold - by sales type
System supply		326.4	-3.2		337.3	1.4		332.5
Transportation		798.6	-6.2		851.7	-12.3		971.7
Total		1,125.0	-5.4		1,189.0	-8.8		1,304.2
Customers (thousands) - average		307.4	5.3		291.9	5.2		277.5

In Florida, natural gas service is unbundled for any non-residential customers that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of this unbundling is a shift from bundled transportation and commodity sales to transportation sales. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net financial impact to the company when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to these customers through its “NaturalChoice” program. At year end 2004, 11,100 of PGS’ 29,000 non-residential customers had elected to take service under this program.

Operations and maintenance expenses decreased in 2004, compared to higher than normal operations and maintenance expenses in 2003 that included higher employee-related costs, including restructuring costs. Depreciation expense increased in both years, in line with the capital expenditures made over the past several years to expand the system.

In December 2002, the FPSC authorized PGS to increase annual base revenues by $12.05 million. The new rates allow for a return on equity range of 10.25 to 12.25% with an 11.25% midpoint, which is the same as its previously allowed return on equity, and a capital structure of 57.4% equity. The increase went into effect on Jan. 16, 2003 (see theRegulation section).

In May 2002, Gulfstream Natural Gas Pipeline initiated service. This interstate pipeline starts in Mobile Bay, Alabama, crosses the Gulf of Mexico and comes ashore in Florida just south of Tampa. Gulfstream is the first new pipeline serving peninsular Florida since 1959. This pipeline increased gas transportation capacity into Florida by 50%. PGS entered into a service agreement for capacity in 2002, for which the transportation volumes increased in 2003 and again in 2004. The addition of the Gulfstream pipeline enhances reliability of service and helps to meet the capacity needs for PGS’ growing customer base.

Since its acquisition by TECO Energy in 1997, PGS has expanded its gas distribution system through system extensions into areas of Florida not previously served by natural gas, such as the lower southwest coast in the high-growth Ft. Myers and Naples areas and the northeast coast in the Jacksonville area. PGS’ expansion strategy for the next several years is to take advantage of the significant capital investments in main pipeline expansions made over the past five years and connect customers to that existing infrastructure. PGS expects increases in sales volumes and corresponding revenues in 2005 and continued customer additions and related revenues from its build-out efforts throughout the state of Florida, assuming continued local economic growth, normal weather and other factors (see theInvestment Considerations section).

TECO COAL

TECO Coal’s 2004 net income was $61.3 million, compared to $77.1 million in 2003. Non-GAAP results in 2004 were $54.3 million, excluding a $7.0 million benefit to income taxes from a true-up of Section 29 tax credits, compared to $84.1 million in 2003, which excluded a $7.0 million negative adjustment due to unrecognizable Section 29 tax credits, discussed below. Sales in 2004 were 9.1 million tons, compared to 9.2 million tons in 2003. These lower results reflect an increase of third-party ownership of the synthetic fuel production facilities to more than 90% and 17% higher production costs. The increased production costs were primarily due to increased diesel fuel prices, higher prices for steel products and higher contract miner costs. The higher production costs were partially offset by average prices for coal sales which were more than 12% higher than 2003.

The third-party ownership structure of the synthetic fuel production facilities reduces the net income per ton from the production of synthetic fuel but increases cash generation per ton. TECO Coal recorded no Section 29 tax credits for 2004 production associated with its remaining synthetic fuel ownership interest because of TECO Energy’s anticipated tax position in 2004, which was driven by tax losses incurred upon the disposition of merchant power plants. The 2004 $7.0 million positive true-up to income taxes was related to Section 29 tax credits that, due to projected limitations on taxable income, were reserved for in 2003 but were found to be recognizable in 2004 upon finalizing the 2003 tax return.

In 2003, net income was $77.1 million, compared to $76.4 million in 2002. Total coal sales were almost 9.2 million tons in 2003. These results were driven by higher volumes of synthetic fuel production and sales and the sale of a 49.5% membership interest in the synthetic fuel production facilities, partially offset by lower volumes and prices for conventional coals and higher mining costs due to the use of marginal and waste coals for the production of synthetic fuel.

In 2004, synthetic fuel production and sales increased to 6.3 million tons from 5.8 million tons and 3.8 million tons in 2003 and 2002, respectively. Included in TECO Coal’s results are the approximately $1.00 to $2.00 per ton higher mining costs associated with the use of marginal coals, which would be otherwise uneconomical to mine, in the production of synthetic fuel. In addition to the 49.5% membership sold in April of 2003, in May 2004, TECO Coal’s subsidiary, TECO Synfuel Holdings, LLC, sold an additional 40.5% of its membership interest to third parties, along with associated percentage rights to benefits in the business which adjust from time to time. Allocation of the benefits varied in 2004 such that more than 90% of the benefits were to third parties. Under these transactions, TECO Coal is paid to provide feedstock, operate the synthetic fuel production facilities and sell the output while the purchasers have the risks and rewards of ownership, including being allocated 90% of the tax credits and operating costs. In addition to receiving reimbursement of the operating costs of the 90% share (minority interest credit), TECO Coal recognizes a gain on the sale of the facilities for each ton of synthetic fuel sold. The cash benefit in 2004 includes $84.5 million of gain from this sale, net of $34.6 million escrowed, and $76.1 million of minority interest credit.

In 2005, total coal sales and synthetic fuel production are expected to be about 9.2 million tons and 6.3 million tons, respectively, with virtually all planned production sold forward under contracts of varying terms. Due to expected variations in the allocation of benefits to the third-party owners, more than 90% of the benefits are expected to be sold in 2005. Contracted coal prices for 2005 are significantly higher than for 2004 and 2003. Average coal prices for all products are expected to be 40% higher than the $33 per ton realized in 2004. Production costs are expected to increase more than 10% in 2005, driven by continued higher contract miner costs, higher royalty and severance fees that are a function of coal prices, and higher transportation costs.

TECO Coal sells almost all of its annual production under contracts that are finalized late in the previous year or early in the current year. It did not realize the high reported spot prices for the majority of its production in 2004 because of the timing of its contract renewals. Due to this contracting strategy, TECO Coal is less affected by the rapid price changes, both upward and downward, than those companies that sell a higher percentage in the spot markets.

Higher prices for competing fuels, increased demand for metallurgical coal worldwide, better balance in supply and demand, lower producer and consumer inventories and consolidation in the mining industry have contributed to higher prices recently. In addition, changes that have occurred over the past several years, including industry consolidation, longer environmental permitting time for new mines, fewer skilled coal miners, gradual depletion of high-quality Central Appalachian reserves and increased international demand for U.S. coal, have allowed producers to contract production for 2005 and 2006 at prices much higher than 2004 levels. Current indications within the coal industry are that prices may decline slightly after 2006 but remain well above 2004 levels.

In January 2000, TECO Coal purchased synthetic fuel facilities from Headwaters Technologies, Inc. The facilities were relocated to the company’s Premier Elkhorn and Clintwood Elkhorn mines in Kentucky and were producing by the second quarter of 2000. These facilities produce synthetic fuel from coal, coal fines and waste coal using a technology licensed from Headwaters. The facilities were subsequently sited at all three of TECO Coal’s complexes.

TECO Coal has received private letter rulings (PLRs) from the Internal Revenue Service (IRS) regarding the qualification of synthetic fuel production from its facilities. The PLRs confirm that the facilities are located appropriately and produce a qualified fuel eligible for Section 29 tax credits, which are available for the production of such non-conventional fuels through 2007. In June 2003, the IRS suspended issuance of PLRs to taxpayers seeking certainty regarding the use of the Section 29 tax credits for the production of synthetic fuel from coal. The suspension was due to questions raised within the IRS regarding the validity of the production of a significant chemical change in the production of synthetic fuel as required under

Section 29. In October 2003, the IRS concluded its review and resumed issuing PLRs. TECO Coal received a PLR from the IRS on Oct. 31, 2003 that affirmed previous rulings after the ownership change and confirmed that the synthetic fuel produced by TECO Coal is eligible for Section 29 tax credits and that its test procedures are in compliance with the requirements of the IRS. In the course of conducting its audit of TECO Energy’s consolidated year 2000 tax return, the first year that TECO Coal produced synthetic fuel, the IRS reviewed the company’s compliance with the requirements for Section 29 tax credits and completed the audit with no adjustments required. The return closed by statute in September 2004.

The economics of the sale of the ownership interests in the synthetic fuel production facilities are reasonably constant as they are determined by the level of the tax credits and not the price received from the sale of output. The Section 29 tax credit is determined annually and is estimated to be $1.12 per million Btu for 2004 and was $1.10 per million Btu in 2003 and $1.09 per million Btu in 2002. This rate escalates at a rate slightly less than inflation, but could be limited by domestic oil prices. For 2004, average annual domestic oil prices, as measured by a U.S. Department of Energy (DOE) index, would have had to exceed $51 per barrel for this limitation to have been effective. The DOE index is based on the “Domestic First Purchase Prices,” not the New York Mercantile Exchange (NYMEX) quoted oil futures prices, and typically averages $3.00 per barrel less than the NYMEX price. If the oil price limitation is reached, the level of the tax credits starts to decline. In 2004, it was estimated that the tax credit would have been eliminated at an average oil price of $64 per barrel. The oil price range for 2005 is expected to range from $52 to $65 per barrel, which is the equivalent of $55 to $68 per barrel on NYMEX. In late 2004, TECO Coal hedged approximately 35% of its exposure to higher oil prices on its expected synthetic fuel production (see theMarket Risk section).

Section 29 tax credits will expire Dec. 31, 2007, and we cannot predict if these tax credits will be extended or renewed in their current form. Following the expiration of the tax credits, we expect both net income and cash flow to decline due to the loss of the benefits from the sale of the third-party membership interests. In 2008, TECO Coal expects to no longer produce synthetic fuel, but it expects to produce conventional coal at levels approximately the same as current total production (approximately 9 million tons). When production of synthetic fuel ends, TECO Coal will stop mining the high-cost-of production coals currently being mined for use in the production of synthetic fuel and will stop operating the synthetic fuel production equipment, which are expected to reduce production costs. At that time, the earnings and cash flow from TECO Coal will be dependent on the selling price of coal in 2008 and its ability to manage production costs.

The significant factor that could influence TECO Coal’s results in 2005 is the higher expected costs of production. Longer-term factors that could influence results include weather, general economic conditions, commodity price changes, the level of domestic oil prices, and the ability to use Section 29 tax credits, which are scheduled to expire Dec. 31, 2007 and could be impacted earlier by administrative actions of the IRS, the U.S. Treasury or changes in laws, regulations or administration. (See theInvestment Considerations section.)

TECO TRANSPORT

TECO Transport’s 2004 net income was $10.2 million, compared to $15.3 million in 2003. Non-GAAP results in 2004 were $11.9 million excluding a $1.1 million after-tax restructuring charge and a $0.6 million after-tax valuation adjustment on ocean-going equipment, compared to non-GAAP results of $16.3 million in 2003, which excluded a $1.0 million after-tax restructuring charge. These results were driven by lower tonnage transported for Tampa Electric due to the repowering of the formerly coal-fired Gannon Station to the natural gas-fired Bayside Station, weak market conditions in the first half of 2004 for the river and terminal business segments, higher fuel costs and unusual operating conditions, including a five-day closing of the Mississippi River and the impact on operations from the four hurricanes. The hurricanes in August and September disrupted river and ocean movements and caused the terminal in Louisiana to halt operations. Estimated lost revenues and direct costs due to the hurricanes reduced TECO Transport’s pretax results by $3.8 million.

Net income in 2003 was $15.3 million, compared to $21.0 million in 2002. Non-GAAP results in 2003 were $16.3 million, excluding a $1.0 million after-tax restructuring charge, compared with $21.0 million in 2002. The decrease was primarily due to lower tonnage transported for Tampa Electric due to the conversion of the Gannon Station from coal to the natural gas-fired Bayside Station, continued weak results from the river transportation and terminal businesses due to lower northbound shipments, a very competitive pricing environment, and higher labor and repair costs. Results for 2003 also included a $3.5 million after-tax gain associated with the disposition of ocean-going assets no longer used by TECO Ocean Shipping and scrap river barges at TECO Barge Line.

TECO Transport’s operating companies were impacted by lower tonnage transported for Tampa Electric in 2004 and 2003 when coal shipments were reduced approximately 1 million tons annually in each of these years. Total annual tonnage handled for Tampa Electric has now stabilized and is expected to average about 5 million tons annually, compared to more than 7 million tons annually prior to the completion of the repowering of Bayside. TECO Transport replaced a portion of this tonnage with increased third-party business and is continuing to seek other new replacement business.

The phosphate fertilizer industry, an important business segment for TECO Ocean Shipping, had stable prices and production in 2004 following several years of low demand and prices. TECO Ocean Shipping expects 2005 phosphate shipments to be at levels similar to 2004 levels.

The river barge industry is now experiencing a better balance in supply and demand for river barge services due to improvements in the U.S. economy and the scrapping of a large number of obsolete river barges by operators throughout the country. A number of river barges which were built in the 1980’s, driven mainly by tax incentives, are now at the end of their useful lives and are being scrapped. The increased rate of barge retirements and the high cost of steel, which has made construction of replacement barges uneconomical, has reduced the supply of barges at a time of increasing demand. The improved U.S. economy, more normal shipping patterns and the reduced supply of barges is expected to improve pricing for river barge services in 2005.

Driven by strong demand for shipments of raw materials to China and India, imports and exports through the Port of New Orleans on the Mississippi River, which impact the river and terminal businesses, were below normal from the second half of 2003 through the middle of 2004. In the second half of 2004, more raw materials, both imports and exports, flowed through the Port of New Orleans. As a result, the terminal and river businesses experienced increased movements of export coal and other products. The river business also benefited from increased southbound shipments of grain products in 2004, with improved pricing during the fall grain shipping season.

The demand for non-U.S. flag ocean-going vessels to meet the demand for shipments to China caused rates for these vessels, as measured by the Baltic Dry Index, to climb significantly starting in the second half of 2003 and reach a record high in November 2004. As a U.S. flag carrier, TECO Transport does not benefit directly from these increased rates since it does not compete against non-U.S. flag vessels in these markets. However, the high international shipping rates do create additional opportunities for spot cargo shipments for TECO Transport’s ocean-going vessels. Although prices as measured by the Baltic Dry Index varied considerably in 2004, the overall trend has been for higher prices, which is expected to continue.

TECO Transport expects improved results in 2005 from better pricing for river barge transportation, increased volume through the terminal, higher rates on those contracts with fuel adjustment clauses, and continued diversification into new markets and cargoes. Future growth at TECO Transport is dependent upon improved pricing, higher asset utilization, and potential asset additions at both the river and ocean-going businesses. Significant factors that could influence results include weather, bulk commodity prices, fuel prices, domestic and international economic conditions, and import and export patterns (see theInvestment Considerations section).

OTHER UNREGULATED COMPANIES

Other Unregulated Companies

Project	Location	Size MW	Ownership Interest		Net Size MW	In Service/ Participation Date
Alborada Power Station	Guatemala	78	96	%	75	9/95
Empresa Eléctrica de Guatemala S.A.(EEGSA) (a distribution utility)	Guatemala		24	%		9/98
San José Power Station	Guatemala	120	100	%	120	1/00
Total non-merchant		198			195

Our other unregulated companies consist primarily of the non-merchant power plants operating in Guatemala and the ownership interest in Guatemala’s largest distribution utility, EEGSA. The San José and Alborada power stations in Guatemala both have long-term power sales contracts. The other unregulated companies also included BCH Mechanical, which was sold in January 2005, and its results are included in discontinued operations for all periods.

The other unregulated companies net income in 2004 was $12.1 million, compared to $23.2 million in 2003. Non-GAAP results in 2004 were $40.1 million, excluding the following after-tax charges and gains: $12.8 million associated with the write-off of unused steam turbines; a $6.7 million charge associated with the extinguishment of debt in the non-recourse financing of the San José Power Station; a $17.4 million provision for income taxes due to the repatriation of cash from Guatemala following the refinancing; a $3.4 million valuation adjustment at TECO Solutions; and a $12.0 million gain on the sale of our interest in the propane business. Non-GAAP results in 2003 were $24.3 million. These results were driven by continued good operating performance at the Guatemalan generating facilities, higher energy sales at EEGSA and a $5.6 million benefit from reducing previously deferred income taxes due to a change in Guatemalan tax law. In addition, an electric rate increase, approved in late 2003, contributed to significantly improved results at EEGSA in 2004.

Net income for the other unregulated companies in 2003 was $23.2 million, compared to $27.0 million in 2002. Non-GAAP results in 2003 were $24.3 million excluding the following after-tax charges and gains: $28.5 million of charges for turbine valuation adjustments and purchase cancellations; a $9.0 million write-off of non-merchant project development costs; a $3.6 million corporate restructuring charge; and a $42.9 million benefit from the gain on the sale and the net income from operations from the Hardee Power Station, which was sold in October 2003 (see theResults Summary section).

Results in 2003 reflected higher net income from EEGSA from increased energy sales at higher prices and favorable currency exchange rates, more than offset by unfavorable tax adjustments on the Guatemalan assets and increased maintenance costs for scheduled maintenance at the San José Power Station.

In November 2003, we announced the sale of our interest in TECO Propane Ventures (TPV) which closed in January 2004. TPV held the company’s propane business investment. The sale, which was part of a larger transaction that involved the merging of privately held Energy Transfer Company with Heritage, was announced in November 2003. Our portion of the sale generated $53.1 million of cash and a $12.0 million after-tax book gain in 2004.

TWG-MERCHANT

In 1999, we announced that a component of our strategy was to expand our presence in the domestic independent energy industry (see theStrategy and Outlook section). Our decision to invest in this industry was based on the outlook at that time for the energy markets beyond 2001, based on the expectation that there would be wide-spread deregulation of these markets. In the face of many events since that time that have diminished the prospects for the profitability of our investments in unregulated independent power plants, we have rethought our independent power strategy. As a result, in 2003 we announced that our strategy going forward was to focus on our Florida utilities and our profitable unregulated businesses and to reduce our exposure to the merchant power markets. Since that time we have taken a number of steps to implement that strategy, including the sale of merchant power assets and making the decision that we would probably not complete the Dell and McAdams power plants. During 2004, we announced our decision to transfer the ownership of the Union and Gila River projects back to the lenders; we sold our interests in Texas Independent Energy, the partnership that owned the Odessa and Guadalupe plants in Texas, and the Frontera Power Station in Texas; and announced an agreement to sell the Commonwealth Chesapeake Power Station.

With the sales completed in 2004, the only operating power plant remaining in the TWG-Merchant segment was the Commonwealth Chesapeake Power Station. CCC’s results are now accounted for as discontinued operations for all periods presented, and therefore is no longer included within the Merchant segment. Expenses related to the unfinished Dell and McAdams power stations and TECO EnergySource, Inc. (TES), the energy marketing operation for the merchant plants, also will continue to be reported in the TWG-Merchant segment unless those assets are disposed of or TES ceases operation. As of year-end 2003, the Union and Gila River power plants were considered “Held for Sale” and were accounted for in discontinued operations (described further below).

TWG-Merchant reported a loss in 2004 of $534.1 million, compared to a loss of $60.8 million in 2003. On a non-GAAP basis, the loss in 2004 was $53.4 million, compared to a non-GAAP loss of $60.5 million in 2003. The non-GAAP results in 2004 exclude after-tax charges for the $381.7 million valuation adjustment for Dell and McAdams, and the $99.0 million valuation adjustment for the TIE projects, which were sold in July. The 2003 non-GAAP results exclude an after-tax charge of $0.3 million for corporate restructuring.

The 2004 results reflect the allocated interest expense and carrying costs associated with the unfinished Dell and McAdams plants, and the operating losses at the TIE projects for the first six months of 2004 due to continued weak power prices in Texas. Results in 2003 reflected a full year of operating losses at the TIE projects and the carrying costs associated with the Dell and McAdams plants, primarily due to the cessation of interest capitalization.

Union and Gila River Power Stations

In October 2003, we announced that we would put little if any additional cash into the merchant generation portfolio, and in February 2004, we announced our decision to exit from our ownership of the Union and Gila River projects and to cease further funding of these plants. Leading up to that decision, we, as the equity investor, and the subsidiary project companies that own the two large plants negotiated with the lending group that provided the non-recourse project financing for these projects regarding the terms of a sale and transfer of ownership of the plants to these lenders.

These negotiations resulted first in a non-binding letter of intent containing a binding settlement agreement entered into on Feb. 5, 2004, supplemented by a term sheet executed in July 2004, and an agreement in October 2004 with the steering committee of the lending group on the material terms and forms of definitive agreements for the consensual sale and transfer of the plants to the lending group, subject to lender approval.

The negotiated arrangements included (i) the terms of the proposed sale and transfer; (ii) the treatment of $66 million of letters of credit posted by us under the construction undertakings related to the projects, with $35 million drawn in February 2004 for the benefit of the project companies and the remaining $31 million cancelled and returned to us; and (iii) our payment

of $30 million to the lending group upon completion of the transfer of the plants in exchange for full releases by the lenders and project entities of TECO Energy and its related entities of all previous financial obligations (except for warranty items identified prior to the expiration of the original warranty period).

The contemplated consensual transfer required 100% lender approval to implement. During the steering committee’s process of seeking approval by all lenders, certain issues regarding the post-transaction structure were raised by two of the 40-member lender group and 100% vote could not be achieved. As a result, an alternative of a pre-negotiated reorganization in bankruptcy was pursued.

Pursuant to this alternative, on Jan. 24, 2005, 95% in number and 90% in aggregate principal amount of the Union and Gila River project lenders entered into a Master Settlement and Restructuring Support Agreement (the “Master Settlement Agreement”), in which they agreed to vote their respective claims in favor of the pre-negotiated Joint Plan of Reorganization (the “Joint Plan”), and on Jan. 26, 2005, the Union and Gila River project entities filed Chapter 11 cases which included the Joint Plan in the U.S. Bankruptcy Court for the District of Arizona. The terms of the Joint Plan are substantially the same as the terms of the transaction that were previously announced as part of the proposed consensual sale and transfer of the projects to the lending group.

For the Joint Plan to be confirmed, it must be approved by an affirmative vote of creditors holding more than 50% in number of obligations and more than two-thirds of the dollar amount of such obligations in each impaired class. There are only two impaired classes of claims that are entitled to vote on the Joint Plan. Those classes are the project lenders, who hold secured claims, and holders of unsecured claims, which include the project lenders’ deficiency claims, our $190 million claims and a nominal amount of other claims. We also consented to the Joint Plan. Our claim consists of all of the payments we made to complete the plants and meet warranty and other unfulfilled obligations of the contractor pursuant to the undertakings as a result of the bankruptcy of Enron, the contractor’s parent. This amount will be reduced by the $35.6 million we have recovered through the sale of the Enron bankruptcy claims and reaching a settlement with Enron, scheduled for approval by the court in March 2005. The amounts of these claims were included in the impairment charges related to the two plants taken at year-end in 2003. First day motions were heard on Jan. 27, 2005 and a critical path scheduling order has been issued, setting Apr. 19 and 20, 2005 as the date for a confirmation hearing on the Joint Plan, with any objections required by Apr. 2, 2005. FERC approval of the transfer of the facilities to the bank lending group was received on Jan. 24, 2005.

In addition to the high approval rate for the Master Settlement Agreement, 100% of the project lenders approved the Master Release Agreement (the “Release”) providing for the release of all claims against us and the project entities, and vice versa, which is part of the Joint Plan. The Release becomes effective upon the transfer of the projects at such time as the Joint Plan is confirmed and the previously described payment by us of $30 million is made.

Although we expect this matter to be resolved as contemplated by the Joint Plan, should this not occur, the parties have reserved their rights against each other, and the lending group could seek to exercise remedies against the project companies due to defaults in connection with the non-recourse project debt and related undertakings, including accelerating the non-recourse project debt and foreclosing on the project collateral, subject to any defenses that may exist.

Accounting Treatment

Based on the anticipated schedule for completion of the pre-negotiated Chapter 11 cases for the projects, we are maintaining our short-term view of these projects. Our consolidated financial results include the 2004 results from operations and the 2003 after-tax asset impairment of $762 million for previous investments to reflect adjustments to the value of the subsidiaries that own the interests in the two plants. The 2003 after-tax impairment charges included the asset valuation adjustments which resulted in the write-off of the full investment in the facilities, costs related to the accelerated impact of the change in hedge accounting for interest rate swaps and a related valuation allowance for certain state tax benefits. The Union and Gila River power stations are considered “Held for Sale” and are included in discontinued operations for income statement purposes, and the assets and liabilities are separately stated as “Held for Sale” on the balance sheet. This accounting treatment could be affected in future periods, depending on the ultimate disposition of our ownership in the plants.

LIQUIDITY, CAPITAL RESOURCES

Our consolidated cash and cash equivalents, excluding all restricted cash, totaled $96.7 million at Dec. 31, 2004. Restricted cash of $57.1 million included $50.0 million, held in escrow until the end of 2007, related to the sale of a 49.5% membership interest in the synthetic coal production facilities. Cash at Dec. 31, 2004 excluded the San José and Alborada power stations’ unrestricted cash balances of $39.8 million and restricted cash of $8.1 million, as these companies were deconsolidated due to the adoption of FIN 46R,Consolidation of Variable Interest Entities, effective Jan. 1, 2004.

In addition, at Dec. 31, 2004 our aggregate availability under bank credit facilities was $332.6 million, net of letters of credit of $27.4 million outstanding under these facilities and $115.0 million drawn on the Tampa Electric credit facility. At Dec. 31, 2004, total liquidity, cash plus credit facilities, was $469.1 million, including $161.3 million at Tampa Electric which consisted of $160 million of undrawn credit facilities and $1.3 million of cash, and $39.8 million of unrestricted cash associated with the deconsolidated Alborada and San José power stations.

In 2004, we met our cash needs largely from internal sources and asset sales. Cash from operations was $140 million. Other sources of cash included $161 million of proceeds from the sale of more than 90% membership interest in TECO Coal’s synthetic fuel production facilities to third-party owners net of escrowed cash, and $230 million of proceeds from the sales of interests in various businesses, including the Frontera Power Station, the Hamakua Power Station, the propane business and Prior Energy. Cash used in financing activities included payment of common dividends of $145 million and the repayment of long-term debt of $225 million, including $75 million of first mortgage bonds at Tampa Electric and $123 million of TECO Capital Trust II trust preferred securities in 2004. Capital expenditures in 2004 were $272 million.

In 2003, we met our cash needs with a mix of externally and internally generated funds. Cash from operations was $311 million, net proceeds from asset sales were $250 million and proceeds from the sale of debt and equity were $792 million. Cash was used to fund $624 million of capital investments, debt repayments of $526 million, net reduction of short term debt of $323 million and dividends to common shareholders of $165 million.

Cash from Operations

In 2004, our consolidated cash flow from operations of $139.6 million was driven by a number of factors, including hurricane restoration costs at Tampa Electric; the accounting for the sale of interests in the synthetic fuel production facilities at TECO Coal, the costs of which are included in cash from operations while the benefits of which are recorded in financing and investing activities, as described more fully below; the deconsolidation of the San José and Alborada power stations; the payment of the TMDP arbitration award, and; the cash operating results of the Union and Gila River power stations. Because the substantial charges for asset impairments were non-cash in nature, they did not affect cash from operations.

Following an initial 49.5% membership interest sold in 2003, in May 2004, TECO Coal sold an additional 40.5% membership interest in its synthetic fuel production facilities, bringing the total third-party membership interest sold to 90%. Cash flow from operations includes the operating losses of approximately $10.00 per ton (pretax) associated with the production of synthetic fuel, while the cash benefits from the sale of the synthetic fuel production facilities of approximately $32 per ton (pretax) are included in the investing and financing activities on the Consolidated Statement of Cash Flows. Investing activity includes cash from the gain on the sale of the synthetic fuel facilities. The company expects to record a gain associated with the sale of the assets through the life of the contract. The cash paid by the owner for its portion of the operating loss from the production of synthetic fuel is included in Financing Activities as a minority interest.

Cash from operations in 2005 is expected to reflect improved net income from the operating companies, lower cash payments of income taxes, collection by Tampa Electric of the under-recovered fuel expense from 2004, lower interest expense due to the retirement of almost $400 million of trust preferred debt associated with the 9.5% equity security units (see theFinancing Activity section), and the remaining payments by Tampa Electric for the 2004 hurricane restoration efforts. Cash operating losses from the Union and Gila River power stations will affect consolidated cash from operations until the plants are transferred to the lenders but will not affect consolidated cash since investing activities will include an offsetting source of cash, which is currently restricted cash at the project companies.

We had not made a contribution to our defined benefit pension plan since the 1995 plan year because investment returns had been more than sufficient to cover liability growth. Negative stock market returns in 2001 and 2002 reduced the overfunding of the plan to the point where the plan was not completely funded. In 2004, we made a $14.2 million contribution to our defined benefit pension plan and expect to make a cash contribution of a similar amount in 2005 (seeNote 5 to the TECO EnergyConsolidated Financial Statements).

Cash from Investing Activities

Cash from investing activities of $90 million in 2004 included, among other items, capital investments totaling $272 million and net asset sale proceeds of $315 million. Asset sales included $141 million from the sale of the Frontera and Hamakua power stations, $83 million from the sale of the TECO Solutions companies including Prior Energy and our interest in the propane business, and installments of $84 million (net of $35 million of escrowed funds) from the sale of the more than 90% membership interest in TECO Coal’s synthetic fuel facilities.

Following the completion of a substantial capital investment program in 2003, both for TWG’s merchant power facilities and for Tampa Electric’s Bayside Power Station, capital spending in 2004 was at the maintenance levels required to support customer growth and system safety and reliability at Tampa Electric and Peoples Gas and maintenance levels at TECO Coal and TECO Transport for normal equipment replacements and capitalized maintenance expenditures. For the next several years, we expect capital spending at similar levels supporting customer growth, safety and reliability, and renewal and replacement of capital in addition to the required capital expenditures for committed environmental projects at Tampa Electric (seeCapital Investments section).

Cash from Financing Activities

Net cash used in financing activities of $242 million in 2004 included $75 million of debt repayments of Tampa Electric first mortgage bonds, scheduled principal payments of Peoples Gas debt, and the retirement of $123 million of trust preferred debt securities (see theFinancing Activity section). We also paid $145 million in common stock dividends, equity contract adjustment payments totaling $35 million, and cash payments associated with the early settlement of our equity security units. Short-term debt increased $78 million due to draws under the Tampa Electric credit facilities. We received $76 million for reimbursement of the operating losses of TECO Coal’s synthetic fuel production facilities in the form of minority interest payments from the third-party owners.

In January 2005, we received $180 million and issued 6.85 million shares of common stock in the final settlement of our equity security units (see theFinancing Activity section).

We have no significant corporate debt maturities until 2007; however, consistent with our stated goal to improve our financial position, we may from time to time use available cash to purchase debt in the open market, in privately negotiated transactions, by exercise of optional redemption rights or otherwise. We do not expect to raise capital from external sources in 2005, except for short-term borrowing under Tampa Electric’s credit facilities.

Liquidity Outlook

With the completion of our major construction programs in 2003 combined with our reduced exposure to the merchant power markets, our current and future liquidity needs are lower than in previous years. We target consolidated liquidity (unrestricted cash on hand plus undrawn credit facilities) of $450 million, comprised of $250 million for Tampa Electric Company and $200 million for TECO Energy. At Dec. 31, 2004 our consolidated liquidity was $469 million.

In January 2005, Tampa Electric entered into a $150 million accounts receivable securitized borrowing facility. With the addition of this facility, Tampa Electric has credit facilities totaling $425 million. It expects to draw upon its facilities for normal working capital fluctuations and to support its expected environmental capital spending over the next several years and otherwise utilize its credit facilities to maintain its targeted available liquidity of $250 million.

We expect to maintain liquidity in excess of our targeted level, and to accumulate additional cash to extinguish all or the majority of the TECO Energy 2007 debt maturities without raising external capital. In January 2005, we received $180 million of proceeds from the final settlement of our equity security units, and we expect to receive net proceeds of approximately $86 million upon the completion of the sale of the Commonwealth Chesapeake Power Station near the end of the first quarter of 2005.

It is possible that unforeseen cash requirements and/or shortfalls or higher capital spending requirements could cause us to fall short of our liquidity target or to require external capital to meet the 2007 TECO Energy debt maturities (see theInvestment Considerations section).

Credit Facilities

At Dec. 31, 2004, we had a bank credit facility in place of $200 million with a maturity date of July 2007, and Tampa Electric had bank credit facilities totaling $275 million with maturity dates in November 2006 and October 2007, as described below. Our TECO Energy bank credit facility includes a $100 million sublimit for letters of credit. The TECO Energy facility was undrawn at Dec. 31, 2004, except for $27.4 million of outstanding letters of credit. At Dec. 31, 2004, $115 million was drawn on the Tampa Electric credit facilities.

Our $200 million credit facility was an early replacement for the $350 million credit facility that was due to expire in November 2004. This facility is secured by the stock of TECO Transport Corporation, which is to be released upon our achieving an investment grade credit rating at both Standard & Poor’s (S&P) and Moody’s. The replacement facility has two financial covenants, earnings before interest, taxes, depreciation and amortization (EBITDA)-to-interest and debt-to-EBITDA, but no debt-to-total capital covenant (see theCovenants in Financing Agreements section).

In October 2004, Tampa Electric Company replaced its expiring $125 million 364-day credit facility with a new $150 million facility that expires in October 2007. Tampa Electric Company now has two multi-year bank credit facilities with total capacity of $275 million: the new $150 million facility and the $125 million facility that expires in November 2006. At the time the replacement facility was put in place, the existing facility was amended to conform the financial covenant requirements to the new facility levels. Both facilities contain two financial covenants, EBITDA-to-interest and debt-to-capital (see theCovenants in Financing Agreements section).

Tampa Electric’s bank credit facilities require commitment fees of 17.5 - 25 basis points, and drawn amounts are charged interest at LIBOR plus 70 - 112.5 basis points at current credit ratings. TECO Energy’s $200 million three-year credit facility requires commitment fees of 50 basis points, and drawn amounts incur interest expense at LIBOR plus 200 basis points at current ratings.

In January 2005, Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric, entered into a $150 million accounts receivable securitized borrowing facility. Under this facility, Tampa Electric will sell and/or contribute to TRC all of its receivables for the sale of electricity or gas to its customers and related rights. The receivables will be sold by Tampa Electric to TRC at a discount, which will initially be 2%. The discount is subject to adjustment for future sales to reflect changes in prevailing interest rates and collection experience. TRC will be consolidated in the financial statements of Tampa Electric and TECO Energy.

Under a Loan and Servicing Agreement, TRC may borrow up to $150 million to fund its acquisition of the receivables under the facility, and TRC will secure such borrowings with a pledge of all of its assets, including the receivables. Tampa Electric will act as servicer to service the collection of the receivables. TRC will pay program and liquidity fees based on Tampa Electric’s credit ratings, which total 35 basis points at Tampa Electric’s current ratings. Interest rates on the borrowings are expected to be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either the London interbank deposit rate plus a margin of 100

basis points at Tampa Electric’s current ratings or at Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher). The facility includes the following financial covenants: (i) for the 12-months ending each quarter-end, the ratio of Tampa Electric’s EBITDA-to-interest, as defined in the agreement, must be equal to or exceed 2.0 times; (ii) at each quarter-end, Tampa Electric’s debt-to-capital ratio, as defined in the agreement, must not exceed 60%; and (iii) certain dilution and delinquency ratios with respect to the receivables.

At TECO Energy, we have not had access to the commercial paper market since the September 2002 downgrade by S&P of our commercial paper program to A3. Tampa Electric Company continued to have access to the commercial paper market until the S&P downgrade of its commercial paper program to A3 in June 2003. The lack of access to the commercial paper market has caused TECO Energy and Tampa Electric Company to utilize bank credit facilities for short-term borrowing needs.

In February 2004, we repaid in full a one-year $37.5 million credit facility collateralized by 50% of the interests in Union and Gila River projects. The proceeds from the credit facility were used in the termination of the joint venture agreement with Panda Energy.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements (seeCredit Facilities above). In addition, TECO Energy, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. TECO Energy, Tampa Electric Company and the other operating companies are in compliance with all required financial covenants except for those related to the Union and Gila River project companies as noted in footnote 5 in the table that follows. The table that follows lists the covenants and the performance relative to them at Dec. 31, 2004. Reference is made to the specific agreements and instruments for more details.

TECO Energy Significant Financial Covenants

(millions, unless otherwise indicated) Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Dec. 31, 2004
Tampa Electric Company
PGS senior notes	EBIT/interest(2)	Minimum of 2.0 times	3.5 times
	Restricted payments	Shareholder equity at least $500	$1,662
	Funded debt/capital	Cannot exceed 65%	49.5%
	Sale of assets	Less than 20% of total assets	—  %
Credit facilities	Debt/capital	Cannot exceed 60%	49.7%
	EBITDA/interest(2)	Minimum of 2.0 times	5.5 times
6.25% senior notes	Debt/capital	Cannot exceed 60%	49.7%
	Limit on liens	Cannot exceed $787	$287 liens outstanding
TECO Energy
Credit facility	Debt/EBITDA(2)	Cannot exceed 5.25 times	4.5 times
	EBITDA/interest(2)	Minimum of 2.25 times	2.7 times
	Limit on additional indebtedness	Cannot exceed $100 million	$ —
$380 million note indenture	Limit on restricted payments(3)	Cumulative operating cash flow in excess of 1.7 times interest	$257 unrestricted
	Limit on liens	Cannot exceed 5% of tangible assets	$236 unrestricted
	Limit on indebtedness	Interest coverage at least 2.0 times	2.5 times
$300 million note indenture	Limit on liens	Cannot exceed 5% of tangible assets	$236 unrestricted
Union and Gila River	Debt/capital	Cannot exceed 65%	70.0%(5)
project guarantees(4)	EBITDA/interest(2)	Minimum of 3.0 times	1.9 times(5)
TECO Diversified
Coal supply agreement guarantee	Dividend restriction	Net worth not less than $418 (40% of tangible net assets)	$564

(1) As defined in each applicable instrument.

(2) EBIT generally represents earnings before interest and taxes. EBITDA generally represents EBIT before depreciation and amortization. However, in each circumstance, the term is subject to the definition prescribed under the relevant agreements.

(3) The limitation on restricted payments restricts the company from paying dividends or making distributions or certain investments unless there is sufficient cumulative operating cash flow, as defined, in excess of 1.7 times interest to make such distribution or investment. The operating cash flow and restricted payments are calculated on a cumulative basis since the issuance of the 10.5% Notes in the fourth quarter of 2002. This calculation at Dec. 31, 2004 reflects the amount accumulated since the issuance of the notes and available for future restricted payments.

(4) Includes the Construction Undertakings related to the Union and Gila River projects.

(5) The TECO Energy guarantees of the equity contribution agreements of TPGC and the Construction Undertakings contain debt/capital and EBITDA/interest financial covenants. The Company was not in compliance with the EBITDA/interest covenant at any quarterly measurement period in 2004 and was not in compliance with the debt/capital covenant at Dec. 31, 2004. Non-compliance constitutes a default under the non-recourse bank credit agreements of the Union and Gila River project companies (TPGC), but does not create a cross-default under any TECO Energy agreement. In December 2003, the Union and Gila River project companies were unable to make interest payments on the non-recourse debt and payments under interest rate swap agreements due Dec. 31, 2003 when the project lenders declined to fund the debt service reserve. Subsequently, the project companies, the project lenders and TECO Energy entered into a series of discussions and agreements and as of Dec. 31, 2004, the Company announced that an agreement had been reached with the steering committee of the project lenders on all material terms and forms of definitive agreements for the sale and transfer to the lenders of ownership of these plants. SeeNote 21to the TECO EnergyConsolidated Financial Statementsfor further discussion of this agreement andNote 23 for details of a related subsequent event.

Credit Ratings/Senior Unsecured Debt

	Standard & Poor’s	Moody’s	Fitch
Tampa Electric	BBB-	Baa2	BBB+
TECO Energy / TECO Finance	BB	Ba2	BB+

In December 2004, Fitch Ratings affirmed our ratings and those of Tampa Electric and revised the rating outlook to stable from negative. The outlook revision was attributed to positive developments over the previous 18 months that included the sale of merchant power and other non-core assets, the 2004 sale of the 40.5% membership interest in TECO Coal’s synthetic fuel production facilities and the successful replacement of TECO Energy’s credit facilities with a three-year credit facility.

In July 2004, S&P lowered the ratings on our senior unsecured debt securities from BB+ with a negative outlook to BB with a stable outlook. At the same time, S&P affirmed Tampa Electric Company’s senior unsecured debt securities rating at BBB- and changed the outlook to stable. At the time of the ratings action, S&P stated that the drop in the TECO Energy rating was based on their expectation of lower financial performance at TECO Energy and less support to TECO Energy from Tampa Electric. In affirming Tampa Electric’s rating, S&P noted that they acknowledged the wide differential in the stand-alone credit profiles of TECO Energy and Tampa Electric, and that Tampa Electric was unlikely to suffer further deterioration from TECO Energy’s activities. S&P further noted that management’s actions over the past three years had been consistent with maintaining Tampa Electric’s strong investment-grade credit quality.

In February 2004, Moody’s lowered the ratings on TECO Energy’s senior unsecured debt securities to Ba2 and the ratings on Tampa Electric’s senior unsecured securities to Baa2, both with a ratings outlook of negative. These ratings changes followed downgrades by Moody’s, S&P and Fitch in 2003, 2002 and 2001 due to the effects of merchant power investments on our business risk and financial position.

Any future downgrades in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings. Our interest expense would increase if maturing debt in 2007 were not retired, and instead it was replaced with new debt with higher interest rates due to the lower credit ratings.

Summary of Contractual Obligations

The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures. This table does not include contingent obligations, which are discussed in a subsequent table.

Contractual Cash Obligations⁽¹⁾

	Payments Due by Period
(millions)	Total		2005		2006		2007		2008-2009		After 2009
Long-term debt:
Recourse	$	3,613.7	$	5.5	$	5.9	$	946.7	$	11.2	$	2,644.4
Non-recourse(2)		21.5		8.1		10.8		0.9		1.7		—
Junior subordinated notes		277.6		—		—		71.4		—		206.2
Operating leases/rentals		157.0		25.2		20.7		17.2		25.6		68.3
Purchase obligations/commitments(3)		134.8		57.1		24.4		23.8		29.5		—
Total contractual obligations(4)	$	4,204.6	$	95.9	$	61.8	$	1,060.0	$	68.0	$	2,918.9

(1) Excludes annual interest payments (seeNote 7 to the TECO EnergyConsolidated Financial Statements for a list of long-term debt and the associated interest rates).

(2) Excludes the $1.4 billion of non-recourse debt associated with the Union and Gila River projects which is included in liabilities associated with assets held for sale.

(3) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2004, these commitments include Tampa Electric’s outstanding commitments of about $105 million primarily for long-term capitalized maintenance agreements for its combustion turbines, and the $30 million payment due to the lenders upon completion of the final transfer of Union and Gila River.

(4) The total excludes a $13.6 million contribution to the qualified pension plan and a $9.8 million contribution to the other postretirement employee benefits plans in 2005. No future contributions are included as they are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance which is affected by stock market performance, and other factors (seeNote 5 to the TECO EnergyConsolidated Financial Statements).

Summary of Contingent Obligations

The following table summarizes the letters of credit and guarantees outstanding that are not included in the Summary of Contractual Obligations table above and not otherwise included in our Consolidated Financial Statements.

Contingent Obligations

	Commitment Expiration
(millions)	Total(2)		2005		2006		2007-2009		After 2009
Letters of credit(1)	$	29.5	$	—	$	4.7	$	—	$	24.8
Guarantees:
Debt related		10.2		—		—		—		10.2
Fuel purchase/energy management		203.6		174.9		—		—		28.7	(3)
Other		13.4		12.0		—		—		1.4
Total contingent obligations	$	256.7	$	186.9	$	4.7	$	—	$	65.1

(1) Expected final expiration date with annual renewals.

(2) Expected maximum exposure.

(3) These guarantee amounts renew annually and are shown on the basis of our intent to renew beyond the current expiration date.

CAPITAL INVESTMENTS

Capital Investments

			Forecast
(millions)	Actual 2004		2005		2006		2007-2009		2005-2009 Total
Tampa Electric
Transmission	$	15	$	19	$	25	$	99	$	143
Distribution		90		75		78		236		389
Generation		48		56		58		191		305
Other		15		20		16		43		79
Environmental		12		44		69		286		399
Tampa Electric	$	180	$	214	$	246	$	855	$	1,315
Peoples Gas		39		40		40		120		200
TECO Coal		23		24		22		55		101
TECO Transport		20		20		20		59		99
Other		10		5		—		1		6
Total	$	272	$	303	$	328	$	1,090	$	1,721

TECO Energy’s 2004 capital investments of $272 million (without reduction for asset and business sale proceeds) included $180 million for Tampa Electric, $39 million for PGS and $3 million for the unregulated Florida operations. Tampa Electric’s electric division capital investments in 2004 were primarily for equipment and facilities to meet its growing customer base and generating equipment maintenance. Capital expenditures for PGS were approximately $24 million for system expansion and approximately $15 million for maintenance of the existing system. TECO Coal’s capital expenditures included $23 million for normal mining equipment replacement. TECO Transport invested $20 million in 2004 primarily for capitalized maintenance of ocean-going vessels.

Asset sale proceeds in 2004 were $315 million net of escrowed cash of $35 million. Included in the proceeds were the sale of the Hamakua and Frontera power stations, the sale of Prior Energy, the sale of our investment in the propane business, TECO Transport’s sale of equipment no longer used at TECO Ocean Shipping and scrap river barges, and TECO Coal’s sale of membership interests in its synthetic fuel production facilities (see theTECO Coal andLiquidity, Capital Resources sections).

TECO Energy estimates capital spending for ongoing operations, without reduction for proceeds from asset sales, to be $303 million for 2005 and $1,418 million during the 2006–2009 period.

For 2005, Tampa Electric’s electric division expects to spend $214 million, consisting of about $170 million to support system growth and generation reliability and $44 million for environmental compliance, including $30 million for the addition of selective catalytic reduction (SCR) equipment at the Big Bend Power Station. At the end of 2004, Tampa Electric had outstanding commitments of about $105 million primarily for long-term capitalized maintenance agreements for its combustion turbines. Tampa Electric’s total capital expenditures over the 2006–2009 period are projected to be $1,101 million, including $254 million for compliance with the Environmental Consent Decree for the SCR equipment and $101 million for other required environmental capital expenditures. The environmental compliance expenditures are eligible for recovery of depreciation and a return on investment through the Environmental Cost Recovery Clause (see theEnvironmental Compliance section).

Capital expenditures for PGS are expected to be about $40 million in 2005 and $160 million during the 2006–2009 period. Included in these amounts are approximately $25 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety.

TECO Coal and TECO Transport expect to invest a combined $44 million in 2005 and $156 million during the 2006–2009 period. Included in these amounts is normal renewal and replacement capital, including coal mining equipment and capitalized maintenance on ocean-going vessels and inland river transportation equipment.

FINANCING ACTIVITY

Our 2004 year-end capital structure, excluding the effect of unearned compensation, was 71.8% senior debt, 3.9% junior subordinated debt and 24.3% common equity. The debt-to-total-capital ratio increased from last year primarily due to the impairment charges taken in 2004 associated with our investments in merchant power.

In 2004, we did not access the debt and equity markets for new capital, except for short-term borrowings under our credit facilities and the small, recurring amount of equity raised through our dividend reinvestment plan. In 2003, we accessed the debt and equity capital markets on three occasions, raising $672 million to provide funds for general liquidity purposes, to repay long-term debt, and reduce short-term debt balances. In addition, debt proceeds in 2003 included non-recourse proceeds of $111 million associated with the Union and Gila River power projects.

In 2004, we completed an early settlement offer on our 9.5% Adjustable Conversion-Rate Equity Security Units (units). Under the terms of the offer, each unit holder received 0.9509 shares of TECO Energy common stock for each unit held and $1.39 per unit in cash, which included the future quarterly distributions through the normal settlement date and a $0.20 per unit incentive. Under the early settlement offer, 10.8 million units were exchanged for 10.2 million shares of our common stock, and we paid $14.9 million of cash for future distributions and incentives. The effect of the exchange was that we retired $269 million, or about 60%, of the associated trust preferred securities and increased the common shares outstanding three months earlier than would have otherwise occurred.

In 2004, we remarketed the remaining $163 million of outstanding trust preferred securities associated with the units within TECO Capital Trust II, as required. We purchased and subsequently retired $123 million of the securities offered in this transaction. Our purchase was funded through a $124 million bridge loan with Merrill Lynch and JP Morgan, which we repaid in December 2004. Trust preferred securities totaling $71 million of this series remain outstanding, including the 3% ($14 million ) held by TECO Capital Trust II, and have a coupon rate of 5.93% which was set in the remarketing. The proceeds from the remarketing were used by the Trustee to purchase a portfolio of US Treasury securities with a January 2005 maturity. Upon final settlement of the units in January 2005, we issued 6.85 million shares of TECO Energy common stock and received $180 million of cash proceeds from the matured U.S. Treasury securities.

The following table provides details of the financing activities beginning in 2002.

Date	Security	Company	Net Proceeds (millions)		Coupon		Use
Jan. 2005	Common equity(1)	TECO Energy	$	180	—		Final settlement of equity units
Jan. 2005	Credit facility	Tampa Electric	$	150	—		Accounts receivable facility
Oct. 2004	Trust preferred securities(2)	TECO Energy	$	0	5.93	%	Required TECO Capital Trust II remarketing
Oct. 2004	Credit facility	Tampa Electric	$	150	—		3-year facility
Aug. 2004	Common equity(3)	TECO Energy	$	0	—		Early settlement of equity units
July 2004	Credit facility	TECO Energy	$	200	—		3-year facility
Nov. 2003	Credit facility	Tampa Electric	$	125	—		364-day facility
			$	125	—		3-year facility
Sep. 2003	Common equity	TECO Energy	$	129	—		Repay short-term debt, and general corporate purposes
Jun. 2003	7-year notes	TECO Energy	$	293	7.5	%	Repay short-term debt, and general corporate purposes
Apr. 2003	13-year notes	Tampa Electric	$	250	6.25	%	Repay maturing short-term debt, and general corporate purposes
Dec. 2002	7-year non-recourse bank loan	TECO Wholesale Generation	$	30	6.0	%	Refinance Alborada Power Station and general corporate purposes
Nov. 2002	5-year notes	TECO Energy	$	352	10.5	%	Repay short - and long-term debt, and general corporate purposes
Oct. 2002	Common equity	TECO Energy	$	207	—		Repay short-term debt, and general corporate purposes
Aug. 2002	5-year notes	Tampa Electric	$	149	5.375	%	Repay maturing long-and short-term debt, and general corporate purposes
Aug. 2002	10-year notes	Tampa Electric	$	394	6.375	%	Repay maturing long-and short-term debt, and general corporate purposes
Jun. 2002	Pollution control bonds	Tampa Electric	$	61	5.1	%	Refinance higher cost debt
Jun. 2002	Pollution control bonds	Tampa Electric	$	86	5.5	%	Refinance higher cost debt
Jun. 2002	Common equity	TECO Energy	$	346	—		Repay short-term debt, and general corporate purposes
May 2002	5-year notes	TECO Energy	$	297	6.125	%	Repay maturing short-term debt, and general corporate purposes
May 2002	10-year notes	TECO Energy	$	397	7.0	%	Repay maturing short-term debt, and general corporate purposes
Jan. 2002	Mandatorily convertible equity units	TECO Energy	$	436	9.5	%	Repay short-term debt, and general corporate purposes

(1) 6.8 million shares issued in the final settlement of the 9.5% convertible equity units

(2) No increase in outstanding debt, interest rate reset

(3) 10.2 million shares issued in an early settlement offer on the 9.5% convertible equity units

OFF-BALANCE SHEET FINANCING

Unconsolidated affiliates have project debt balances as follows at Dec. 31, 2004. We had no debt payment obligations with respect to these financings. Although we are not directly obligated on the debt, our equity interest in those unconsolidated affiliates and its commitments with respect to those projects are at risk if those projects are not operated successfully.

Off-Balance Sheet Debt

(millions)	Long-term Ownership		Ownership Interest
San José Power Station	$	110.5	100	%
Alborada Power Station	$	21.7	94	%
Empresa Eléctrica de Guatemala S.A.(EEGSA)	$	182.7	24	%

The equity method of accounting is used to account for investments in partnership and corporate entities in which we or our subsidiary companies do not have either a majority ownership or exercise control. On Jan. 17, 2003, the Financial Accounting Standards Board issued FASB Interpretation FIN No. 46,Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which requires a new approach in determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities or VIEs. On Dec. 24, 2003, the FASB published a revision to FIN 46 (FIN46R), to clarify some of the provisions of FIN 46 and exempt certain entities from its requirements.

We deconsolidated the San José and Alborada power stations listed above in the first quarter of 2004 as a result of implementing FIN 46R. These projects were partially financed with non-recourse debt, which following the deconsolidation is considered to be off-balance sheet financing. (This and other effects of implementing FIN 46R are described inNote 2 to the TECO EnergyConsolidated Financial Statements.)

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingencies. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions. (SeeNote 1 to the TECO EnergyConsolidated Financial Statements for a description of our significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.)

Long-Lived Assets

In accordance with Financial Accounting Standard (FAS) 144, Accountingfor the Impairment or Disposal of Long- Lived Assets, we assess whether there has been an other than temporary impairment of our long-lived assets and certain intangibles held and used by us when such indicators exist. Also, we annually test the long-lived assets in the last quarter of each year to ensure that gradual change over the year and the seasonality of the markets are considered in the impairment analysis. We believe the accounting estimates related to asset impairments are critical estimates for the following reasons: 1) the estimates are highly susceptible to change as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then current market conditions in such periods; 2) markets can experience significant uncertainties; 3) the estimates are based on the ongoing expectations of management regarding probable future uses and holding periods of assets; and 4) the impact of an impairment on reported assets and earnings could be material. Our assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Our expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

During the fourth quarter of 2004, as a part of its annual impairment review, management conducted a review of the prospects for long-term power prices as well as opportunities for actual sales of assets. As a result of this review, we sold the Frontera project and determined it was appropriate to reduce the probability that the Dell, McAdams and Commonwealth Chesapeake projects would be held for use for the overall economic life of those projects. The first step in the impairment testing was weighted more toward an ultimate recovery of the investment. In each case, the testing resulted in a determination that the carrying value of each project was not recoverable. This recoverability test is conducted by comparing the probability weighted undiscounted cash flows for the asset to its carrying value. If the test is not passed, a second step is required. Each of the projects listed above required the second step, in which the difference between the fair market value of the projects and the

carrying value was estimated in order to determine and record appropriate impairment charges. Critical estimates are also inherent in determining the fair market value. We based the fair market values on probability weighted values. To the extent actual fair market value should vary from the probability weighted average values, future impairment charges or gains on disposition could occur (seeNote 18 to the TECO EnergyConsolidated Financial Statements for the discussion on the asset impairments).

When specific criteria are met, a disposal group, comprised of assets and liabilities expected to be transferred in a sale within one year, is classified in assets and liabilities, respectively, and held for sale. Furthermore, the income or loss associated with a disposal group may, if additional criteria are met, be presented as discontinued operations in the statement of income. The Union and Gila projects, Frontera, Prior Energy, TECO BGA, TECO BCH, TECO AGC, and TECO Coalbed Methane are classified as assets and liabilities held for sale, and the results associated these investments are presented as discontinued operations (seeNotes 1, 18 and21 to the TECO EnergyConsolidated Financial Statements).

Goodwill and Other Intangible Assets

In accordance with FAS 142,Goodwill and Other Intangible Assets, we review goodwill and intangibles for each reporting unit at least annually for impairment. Reporting units are generally determined as one level below the operating segment level; however, reporting units with similar characteristics may be grouped under the accounting standard for the purpose of determining the impairment, if any, of goodwill and other intangible assets. The goodwill impairment test is a two-step process, which requires management to make judgments in determining what assumptions to use in the calculation. The first step of the process consists of estimating the fair value of each reporting unit based on a discounted cash flow model using revenue and profit forecasts and comparing those estimated fair values with the carrying values, which include the goodwill. If the estimated fair value is less than the carrying value, a second step is performed to compute the amount of the impairment by determining an implied fair value of goodwill. Estimating the reporting unit’s implied fair value of goodwill requires the Company to allocate the estimated fair value of the reporting unit to the assets and liabilities of the reporting unit. Any unallocated fair value represents the implied fair value of goodwill, which is compared to its corresponding carrying value. During the fourth quarter of 2004, as a result of current conditions in the energy services market, we were required to recognize an impairment charge for the goodwill related to the BCH reporting unit. This $11.8 million pretax impairment charge completely eliminated the goodwill associated with that investment. This impairment charge is reflected in discontinued operations as we subsequently sold this unit.

The company had $59.4 million of goodwill remaining on its balance sheet at Dec. 31, 2004, which was related to its Guatemalan reporting unit. Assuming a 9% discount rate, which management believes is appropriate since these projects have long-term power purchase agreements, the goodwill was not impaired. Assuming a 1% increase in the discount rate would not reduce the implied fair value of the goodwill to an extent that an impairment charge would be necessary. Increasing the discount rate 3%, to 12%, to calculate the implied fair value of the goodwill would have resulted in an approximate $1 million pretax impairment charge (seeNote 17 to the TECO EnergyConsolidated Financial Statements).

Equity Investments

In accordance with APB No. 18,The Equity Method of Accounting for Investments in Common Stock, we only record an impairment of an equity investment when a decline in the fair value below the carrying value of the investment is determined to be other than temporary. The accounting estimate of impairment of equity investments is critical, since management must assess other than temporary impairments based on: 1) the magnitude of the difference of the fair value below the carrying value; 2) the period of time in which the decline in the fair value is less than the carrying value; and 3) other reasonably available qualitative or quantitative information that provides evidence to indicate that a decline in fair value is temporary. During the year ended Dec. 31, 2004, the company recorded an impairment of an equity investment in Texas Independent Energy, (TIE). This impairment charge was driven by management’s decision to not make additional investments in this project, which materially impacted the impairment assessment (seeNote 16 to the TECO EnergyConsolidated Financial Statements).

Deferred Income Taxes

We use the liability method in the measurement of deferred income taxes. Under the liability method, we estimate our current tax exposure and assess the temporary differences resulting from differing treatment of items, such as depreciation for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward looking information, to determine if it is more likely than not that some or all of the deferred tax asset will not be realized. If we determine that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.

At Dec. 31, 2004, we had net deferred income tax assets of $875.0 million attributable primarily to losses or expected losses on asset dispositions, property related items, alternative minimum tax credit carryover of Section 29 non-conventional fuel tax credits and operating loss carry forwards. Based primarily on historical income levels and the steady growth expectations for future earnings of the company’s core utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2004 will be realized in future periods.

We believe that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: 1) realization of the deferred tax asset is dependent upon the generation of sufficient taxable income in future periods; 2) a change in the estimated valuation reserves could have a material impact on reported assets and results of operations; and 3) administrative actions of the IRS or the U.S. Treasury or changes in law or regulation could change our deferred tax levels, including the potential for elimination or reduction of our ability to utilize the deferred tax assets (seeNote 4 to the TECO EnergyConsolidated Financial Statements).

Accounting for Contingencies

In accordance with FAS 5,Accounting for Contingencies, we make estimates at the end of each reporting period to record the probable loss related to contingent liabilities. Examples of such expected losses and respective contingent liabilities would include legal contingencies and incurred but not reported medical and general liability claims. We consider these estimates of liabilities to be critical since the company must first determine the likelihood that the known claims or legal events will result in a future loss to the company. Then we must determine if the future amount of expected loss can be reasonably estimated.

For a known claim, if the company determines that it is probable that future events will result in a loss and that loss can be reasonably estimated, the expected loss and respective liability are recorded. If we determine that the likelihood is remote that those future events will develop in a manner that will result in a loss to the company, no loss or liability is recorded. If there is more than a remote possibility but it is less than likely that future events will result in a loss to the company, we disclose the specific claim or situation if it is material.

For medical and general liability claims that have been incurred but not reported, we rely on a third-party actuary to advise us as to probable liabilities that will become known in the future but were incurred in the current reporting period, and we record the expected loss and liability accordingly.

Many of the material claims that have been made or could be made against the company in the future are covered by insurance. Accounting for the expected loss and liability under FAS 5 has different recognition criteria than expected insurance recoveries such that it is possible that the company could have to report a loss and respective liabilities in accounting periods before the offsetting gain from the insurance recovery could be reported.

While the company carefully evaluates all known claims and cases to record the most probable outcome, future events could develop in an unexpected manner that could have a material impact on future financial statements (seeNote 12 toConsolidated Financial Statements for a complete discussion of certain legal contingencies that existed at Dec. 31, 2004).

Employee Postretirement Benefits

We sponsor a defined benefit pension plan that covers substantially all of our employees. In addition, we have unfunded non-qualified, non-contributory supplemental executive retirement benefit plans available to certain senior management. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to these plans. Key factors include assumptions about the expected rates of return on plan assets, discount rates and health care cost trend rates. These factors are determined by us within certain guidelines, with the help of external experts. We consider market conditions, including changes in investment returns and interest rates, in making these assumptions.

Plan assets are invested in a mix of equity and fixed income securities. The assumptions for the expected return on plan assets are developed based on an analysis of historical market returns, the plan’s actual past experience and current market conditions. The expected rate of return on plan assets is a long-term assumption and is not intended to change annually. The discount rate assumption is based on a cash flow matching technique developed by our outside actuaries, and this assumption is subject to change each year. The salary increase assumption is a rate based on current expectations of future pay increases and is linked with our discount rate assumption. Holding all other assumptions constant, a 1% increase or decrease in the assumed rate of return on plan assets would decrease or increase, respectively, 2004 net periodic expense by approximately $4.5 million. Likewise, a 0.25% increase or decrease in the discount rate and the related change in the rate of salary increase would not result in a significant decrease or increase in net periodic pension expense.

Unrecognized actuarial gains and losses are being recognized over approximately a 15-year period, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with FASB Statement No. 87,Employer’s Accounting for Pensions. Our policy is to fund the plan based on the required contribution determined by our actuaries within the guidelines set by the Employee Retirement Income Security Act of 1974 (ERISA), as amended.

In addition, we currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 who meet certain service requirements. The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under FAS 106,Employers’ Accounting for Postretirement Benefits Other Than Pensions, include the assumed discount rate and the assumed rate of increases in future health care costs. The discount rate used to determine the obligation for these benefits has matched the discount rate used in determining our pension obligation in each year presented. In estimating the health care cost trend rate,

we consider our actual health care cost experience, future benefit structures, industry trends and advice from our outside actuaries. We assume that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industry-wide cost containment initiatives. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) was enacted. The Act established a prescription drug benefit under Medicare, known as “Medicare Part D,” and a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription benefit which is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FASB Staff Position No. FSP 106-2 which required 1) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and 2) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

We adopted FSP 106-2 retroactive to the second quarter of 2004 for benefits provided that we believe to be actuarially equivalent to Medicare Part D. This initial recognition reduced the accumulated postretirement benefit obligations (ABPO) at Jan. 1, 2004 by $27.0 million and net periodic cost for 2004 by $2.8 million. Although additional guidance on actuarial equivalence is scheduled for release in early 2005, we do not anticipate that it will materially impact the amounts provided in this disclosure. The assumed health care cost trend rate for medical costs was 10.5% in 2004 and decreases to 5.0% in 2013 and thereafter.

A 1% increase in the health care trend rates would produce an 8% ($1.2 million) increase in the aggregate service and interest cost for 2004 and a 5% ($8.5 million) increase in the accumulated postretirement benefit obligation as of Sep. 30, 2004.

A 1% decrease in the health care trend rates would produce a 6% ($0.9 million) decrease in the aggregate service and interest cost for 2004 and a 3% ($6.3 million) decrease in the accumulated postretirement benefit obligation as of Sep. 30, 2004.

The actuarial assumptions we used in determining our pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations.

Depreciation Expense

As of Dec. 31, 2004, approximately 71% of our total gross property, plant and equipment was comprised of regulated electric utility assets. We provide 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. For the year ended Dec. 31. 2003, Tampa Electric recognized depreciation expense of $36.6 million related to accelerated depreciation of certain Gannon power station coal-fired assets, in accordance with a regulatory order. We believe the estimated service life corresponds to the anticipated physical life for most assets. However, our estimation of service life is a critical estimate for the following reasons: 1) forecasting the salvage value for long-lived assets over a long timeframe is subjective; 2) changes may take place that could render a technology obsolete or uneconomical; and 3) a change in the useful life of a long-lived asset could have a material impact on reported results of operations and reported assets. A 10% decrease, on a weighted average basis, in the service lives of our overall utility plant in service would increase pretax depreciation approximately $24.8 million per year (seeNote 1 to the TECO EnergyConsolidated Financial Statements).

Regulatory Accounting

Tampa Electric’s and PGS’ retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the Federal Energy Regulatory Commission (FERC). As a result, the regulated utilities qualify for the application of FAS 71,Accounting for the Effects of Certain Types of Regulation. This statement recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between generally accepted accounting principles and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.

We periodically assess the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on reported assets and the results of operations (seethe Regulation Section andNotes 1 and3 to the TECO EnergyConsolidated Financial Statements).

Revenue Recognition

Except as discussed below, we recognize revenues on a gross basis when the risks and rewards of ownership have transferred to the buyer and the products are physically delivered or services provided. Revenues for any financial or hedge transactions that do not result in physical delivery are reported on a net basis.

The determination of the physical delivery of energy sales to individual customers is based on the reading of meters, which occurs on a regular basis. At the end of each month, amounts of energy delivered to customers since the date of the last

meter reading may be estimated, and the corresponding unbilled revenue is estimated. Unbilled revenue is estimated each month primarily based on historical experience, customer specific factors, customer rates, and daily generation volumes, as applicable. These revenues are subsequently adjusted to reflect actual results. Revenues for regulated activities at Tampa Electric and PGS are subject to the actions of regulatory agencies.

The percentage-of-completion method is used to recognize revenues for certain transportation services at TECO Transport. The percentage-of-completion method requires management to make estimates regarding the distance traveled and/or time elapsed. Revenue is recognized by comparing the estimated current total distance traveled with the total distance required. Each month revenue recognition and realized profit are adjusted to reflect only the percentage of distance traveled.

Revenues for merchant power sales and expenses for fuel purchases at TWG are reported on a gross basis, except for derivative gains or losses related to hedge accounting, which are reported net of the hedged item or transaction. Likewise, expenses arising from purchased power or revenues arising from sales at TWG are reported net of power revenues and expenses, respectively.

We estimate certain amounts related to revenues on a variety of factors, as described above. Actual results may be different from these estimates (seeNote 1 to the TECO EnergyConsolidated Financial Statements).

RECENTLY ISSUED ACCOUNTING STANDARDS

In accordance with recently issued accounting pronouncements, we will be required to comply with certain changes in accounting rules and regulations (seeNote 2 to the TECO EnergyConsolidated Financial Statements).

FASB Statement No. 123 (revised 2004), Share-Based Payment, will become effective for periods after June 15, 2005. The revision to FAS 123 will require financial statement cost recognition for certain share-based payment transactions that are made after the effective date in return for goods and services. Additionally, the revision will require financial statement cost recognition for certain share-based payment transactions that have been made prior to the effective date but for which the requisite service is provided after the effective date (seeNote 9 to the TECO EnergyConsolidated Financial Statements, which includes proforma information to assess the impact of implementing the revised statement).

FASB Statement No. 151,Inventory Costs, an amendment to ARB No. 43, Chapter 4, sets forth certain costs related to inventory that must be included as current period costs. This Statement became effective June 2004 and did not materially impact the company.

FASB Statement No. 153,Exchanges of Non-monetary Assets, an amendment of APB Opinion No. 29, became effective June 2004 and did not materially impact the company.

OTHER ITEMS IMPACTING NET INCOME

2004 Items

In 2004, our results from continuing operations included $508.6 million of charges and gains related primarily to valuation adjustments on merchant power assets, refinancing costs and the associated taxes on the cash repatriated from the San José Power Station in Guatemala, the gain on the sale of our interest in our propane business, corporate restructuring charges, and tax credit true-ups (see theResults Summary section).

2003 Items

In 2003, our results from continuing operations included $75.9 million of charges and gains related to valuation adjustments, project cancellation costs, turbine valuation adjustments, tax credit reversals, and corporate restructuring at the various operating companies and $42.9 million related to the sale of HPP and its operating net income through the date of the sale (see theResults Summary section). In addition, we recognized $1.1 million in after-tax charges related to a change in accounting principle for the implementation of FAS 143,Accounting for Asset Retirement Obligations, and a $3.2 million after-tax charge for the implementation FAS 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.

2002 Items

In 2002, our results included a $3.0 million after-tax charge at TECO Investments related to an aircraft leased to US Airways, which filed for bankruptcy. Results at TWG included a $5.8 million after-tax asset valuation charge for the sale of its interests in generating facilities in the Czech Republic. Results at TECO Energy included a $34.1 million pretax ($20.9 million after-tax) charge related to a debt refinancing.

OTHER INCOME (EXPENSE)

In 2004, Other income (expense) of $29.7 million reflects the income related to the gain on the sale of the Hamakua Power Station, the sale of our interest in the propane business and the per-ton installment sale of the 90% interest in the synthetic fuel production facilities at TECO Coal.

Results in 2003 included the gain on the final installment of the sale of TECO Coalbed Methane, the sale of Hardee Power Partners, and the sale of 49.5% interest in the synthetic fuel production facilities.

In 2002, Other income (expense) of $15.6 million included $60.7 million from construction related and loan agreements with Panda Energy and earnings on the equity investment in EEGSA at TWG, and income from the investment in TECO Propane Ventures, partially offset by the $9.4 million pretax ($5.8 million after-tax) asset valuation charge for TWG’s sale of its minority interest in generating facilities in the Czech Republic and a $34.1 million pretax ($20.9 million after-tax) charge related to a TECO Energy debt refinancing completed in 2002.

AFUDC equity at Tampa Electric, which is included in Other income (expense), was $0.7 million in 2004, $19.8 million in 2003 and $24.9 million in 2002. AFUDC is expected to remain a minimal amount in 2005, but increase slightly in 2006 due to the installation of NOx control at the Big Bend Station at Tampa Electric (see theEnvironmental Compliance section).

Earnings from equity investments (which is included in Other income) include a $45.5 million benefit from the Guatemalan operations included in the Other Unregulated Companies, partially offset by a $9.2 million loss from the TIE projects prior to their sale in July.

INTEREST CHARGES

Total Interest charges were $321.6 million in 2004, compared to $318.0 million in 2003 and $169.3 million in 2002. Interest expense in 2004 reflects no capitalized interest and the effect of debt issues in mid-2003, largely offset by the early settlement of the trust preferred securities, lower cost of short-term borrowings, the deconsolidation of the Guatemalan power facilities, and the sale of Hardee Power Partners. In 2003, capitalized interest on the debt of TECO Energy was $17.3 million and capitalized interest (AFUDC-borrowed funds) at Tampa Electric was $7.6 million. Capitalization of interest ended with commercial operation of the final phase of the Gila River Power Station in July 2003 and the Bayside Power Station in January 2004.

Interest expense increased in 2003 reflecting higher debt balances at both Tampa Electric and TECO Energy associated with the completion of major construction programs. In addition, capitalized interest was $45 million lower in 2003 than in 2002 as a result of the completion of the Union and Gila River construction and the suspension of construction of Dell and McAdams.

INCOME TAXES

Income taxes decreased in 2004 as we incurred net operating losses primarily as a result of losses on the disposition of merchant power generating assets. Income tax decreased in 2003, as the result of a loss from continuing operations, continuing non-taxable AFUDC equity, and substantial tax credits associated with the production of non-conventional fuels. Income tax expense as a percentage of income from continuing operations before taxes was 40.8% in 2004, (207.0%) in 2003 and (28.5%) in 2002. In 2005, we expect the effective tax rate to be in the range of 30% to 35%.

The cash payment for income taxes, as required by the Alternative Minimum Tax Rules (AMT), state income taxes and payments related to prior years’ audits was $22.4 million, $58.8 million and $71.9 million in 2004, 2003 and 2002, respectively.

Due to the generation of deferred income tax assets related to the net operating loss (NOL) carryforward from the disposition of the merchant generating assets and the additional NOL that we expect to generate upon the disposition of the Union and Gila River projects, we expect future cash tax payments for income taxes to be limited to approximately 10% of the AMT rate and various state taxes. We currently expect to utilize these NOL through 2010. Beyond 2010, we expect to use the more than $200 million of AMT carryforward to limit future cash tax payments for federal income taxes to the level of AMT. Our current projection of cash income tax payments in 2005 is about $35 million, including amounts for payments related to the prior year’s audit. For the 2006-2009 period, we estimate this amount to be approximately $10 million annually.

Total income tax expense in years prior to 2004 was reduced by the federal tax credits related to the production of non-conventional fuels under Section 29 of the Internal Revenue Code. The recognized tax credit totaled $73.0 million in 2003 and $107.3 million in 2002. These tax credits are generated annually on qualified production at TECO Coal through Dec. 31, 2007, subject to changes in law, regulation or administration that could impact the qualification of Section 29 tax credits. We were unable to utilize any Section 29 tax credits in 2004 due to our net tax loss position for the year and expect to be unable to utilize Section 29 tax credits through 2007, when the tax credit expires (see theTECO Coal section).

The tax credit is determined annually and is estimated to be $1.12 per million Btu for 2004, $1.10 per million Btu in 2003 and $1.09 per million Btu in 2002. This rate escalates with inflation but could be limited by domestic oil prices. In 2004, domestic oil prices, as measured by a DOE index, would have had to exceed $51 per barrel for this limitation to have been effective. If the oil price limitation is reached, the level of the tax credits starts to decline. In 2004, it was estimated that the tax credit would have been eliminated at an average oil price of $64 per barrel. The DOE index is based on the “Domestic First Purchase Prices” not the NYMEX quoted oil futures prices and typically averages $3.00 per barrel less than the NYMEX price. The 2004 oil price limits are the equivalent to $54 and $67 per barrel on NYMEX.

In 2004, 2003, and 2002, the decreased income tax expense also reflected the impact of increased overseas operations with deferred U.S. tax structures. The decrease related to these deferrals was $10.5 million, $12.3 million and $8.1 million for 2004, 2003, and 2002, respectively.

The income tax effect of gains and losses from discontinued operations is shown as a component of results from discontinued operations.

DISCONTINUED OPERATIONS

Discontinued Operations

(millions)	2004			2003			2002
Union & Gila River operations	$	(96.0	)	$	(61.9	)	$	16.8
Union & Gila River write-off		—			(762.0	)		—
Union & Gila River joint venture termination		—			(94.7	)		—
Frontera goodwill write-off		—			(44.9	)		—
Frontera write-off		(25.6	)		—			—
Frontera operations		(5.8	)		(3.0	)		7.8
Commonwealth Chesapeake operations		2.5			(22.7	)		3.1
Commonwealth Chesapeake write-off		(51.3	)		(16.3	)		—
TECO Solutions / other		(20.3	)		(23.1	)		5.6
TECO Coalbed Methane		—			22.8			31.4
Total discontinued operations	$	(196.5	)	$	(1,005.8	)	$	64.7

The net loss from discontinued operations for 2004 was $196.5 million. Discontinued operations in 2004 reflect the operating losses for the Union and Gila River power stations, the write-off and losses from operations at the Frontera and Commonwealth Chesapeake power stations, and the write-offs and losses from operations associated with certain TECO Solutions companies that are now reported in discontinued operations.

Discontinued operations in 2003 included the write-off of the investment and the operating results from the Union and Gila River power stations; operating results from Prior Energy, which was sold in March 2004; the gain on the final installment of the sale of the coalbed methane gas production assets in January 2003; and the write-off and losses from operations at the Commonwealth Chesapeake Power Station.

INFLATION

The effects of inflation on our results have not been significant for the past several years. The annual rate of inflation, as measured by the Consumer Price Index (CPI), all items, all urban consumers as reported by the U.S. Department of Labor, was 2.7%, 2.3% and 1.6% in 2004, 2003 and 2002, respectively. Published forecasts by economists and by several agencies of the U.S. government indicate that inflation is expected to be relatively modest again in 2005 with a 2.5% increase expected.

Prices for certain products and services used by TECO Energy’s operating companies increased at rates above the CPI in 2004, including prices for steel products and petroleum-based products used extensively in all of our operating companies, and for subcontracted mining services used by TECO Coal, and these prices are expected to continue to rise in 2005. In the case of TECO Transport, a portion of the increased cost of petroleum products is passed through to its customers through contract fuel adjustment clauses, and Tampa Electric and PGS recover the cost of commodity fuel through the respective FPSC approved fuel adjustment clauses. In those cases where the higher costs can not be passed directly to the customers, higher costs could reduce the profit margins at the operating companies.

ENVIRONMENTAL COMPLIANCE

Consent Decree

Tampa Electric, in cooperation with the Environmental Protection Agency (EPA) and the U.S. Department of Justice, signed a Consent Decree which became effective Oct. 5, 2000, and a Consent Final Judgment with the Florida Department of Environmental Protection (FDEP) on Dec. 7, 1999. Pursuant to these agreements, allegations of violations of New Source Review requirements of the Clean Air Act were resolved, provision was made for environmental controls and pollution reductions, and Tampa Electric began implementing a comprehensive program to dramatically decrease emissions from its power plants.

The emission reduction requirements included specific detail with respect to the availability of flue gas desulfurization systems (scrubbers) to help reduce sulfur dioxide (SO2), projects for nitrogen oxides (NOx) reduction efforts on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Station to natural gas. The commercial operation dates for the two repowered Bayside units were Apr. 24, 2003 and Jan. 15, 2004. The completed station has total station capacity of about 1,800 megawatts (nominal) of natural gas-fueled electric generation.

In 2004, Tampa Electric decided to install selective catalytic reduction (SCR) for NOx control on Big Bend Unit 4, with an expected in-service date by June 1, 2007. Tampa Electric has also decided to install SCRs on Big Bend Units 1, 2 and 3 with in-service dates for Unit 3 by May 1, 2008, Unit 2 by May 1, 2009 and Unit 1 by May 1, 2010. Tampa Electric has begun the detailed engineering and design of the SCR system. Tampa Electric’s capital investment forecast includes amounts in the 2005 through 2009 period for compliance with the NOx, SO2 and particulate matter reduction requirements (see the Capital Investments section).

The FPSC has determined that it is appropriate for Tampa Electric to recover the operating costs of and earn a return on the investment in the first SCR to be installed at the Big Bend Power Station and pre-SCR projects on Big Bend units 1–3 (which are plant improvements to reduce NOx emissions prior to installing the SCRs) through the Environmental Cost Recovery Clause (ECRC) (see theRegulation section). The first SCR (Big Bend Unit 4) is scheduled to enter service by June 1, 2007 and cost recovery, which is dependent on filings to be made in 2007, is expected to start in 2008.

Emission Reductions

Projects committed to under the Consent Decree and Consent Final Judgment will result in significant reductions in emissions. Since 1998, Tampa Electric has reduced annual SO2, NOx and particulate matter (PM) from its facilities by 161,642 tons, 39,066 tons, and 9,285 tons, respectively.

Reductions in SO2 emissions were accomplished through the installation of scrubber systems on Big Bend Units 1 and 2 in 1999. Big Bend Unit 4 was originally constructed with a scrubber. The Big Bend Unit 4 scrubber system was modified in 1994 to allow it to scrub emissions from Big Bend Unit 3 as well. Currently the scrubbers at Big Bend Station remove more than 95% of the SO2 emissions from the flue gas streams.

The repowering of Gannon Station to Bayside Power Station in April 2003 (Bayside Unit 1) and January 2004 (Bayside Unit 2) has resulted in a significant reduction in emissions of all pollutant types. Tampa Electric’s decision to install additional NOx emissions controls on all Big Bend units will result in the further reduction of emissions. By 2010, the SCR projects will result in the phased reduction of NOx by 59,652 tons per year from 1998 levels. In total, Tampa Electric’s emission reduction initiatives will result in the reduction of SO2, NOx and PM emissions by 89%, 87%, and 70%, respectively, below 1998 levels. With these improvements in place, Tampa Electric’s facilities will meet the same standards required of new power generating facilities and help to significantly enhance the quality of the air in the community. Due to pollution control co-benefits from the Consent Final Judgment and Consent Decree, reductions in mercury emissions have occurred due to the repowering of Gannon Station to Bayside Station. At Bayside, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions are also anticipated from the installation of NOx controls at Big Bend Station, which would lead to a mercury removal efficiency of approximately 70%.

The repowering of Gannon Station to Bayside will also lead to a significant reduction in carbon dioxide (CO2) emissions. It is expected that in 2005, the repowering will result in a decrease in CO2 emissions of approximately 5.2 million tons below 1998 levels. With this reduction, the Tampa Electric system CO2 emissions will be in line with its 1990 CO2 emission levels. As a result of all its already completed emission reduction actions, and upon completion of the SCR projects, Tampa Electric will have achieved emission reduction levels called for in Clean Air Act proposals including the Bush Administration’s “Clear Skies” proposal.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas 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, as of Dec. 31, 2004, Tampa Electric Company has estimated its ultimate financial liability to be approximately $17 million, and this amount has been reflected in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices. The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work, adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each parties’ relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered credit worthy.

Factors that could impact these estimates include the ability of other PRPs to pay their pro rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These additional costs would be eligible for recovery through customer rates.

REGULATION

Tampa Electric Rate Strategy

Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75% to 12.75%, with a midpoint of 11.75%, are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties. Tampa Electric expects to continue earning within its allowed ROE range even with the rate base additions associated with the repowering of Bayside. Tampa Electric has not sought a base rate increase to recover the investment in Bayside.

Cost Recovery Clauses – Tampa Electric

In September 2004, Tampa Electric filed with the FPSC for approval of cost recovery rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2005. In November, the FPSC approved Tampa Electric’s requested changes. The rates include the impacts of increased natural gas and coal prices, the collection of $30.9 million for underestimated 2003 & 2004 fuel expenses, the proceeds from the sale of SO2 emissions allowances associated with Hookers Point Station and the O&M costs associated with the Big Bend units 1–3 pre-SCR projects required by the EPA Consent Decree and FDEP Consent Final Judgment (see theEnvironmental Compliance section). In addition, the rates also reflect the FPSC’s September 2004 decision to reduce the annual cost recovery amount for water transportation services for coal and petroleum coke provided under Tampa Electric’s contract with TECO Transport Company discussed below. Accordingly, Tampa Electric’s residential customer rate per 1,000 kilowatt-hours decreased $0.94 from $99.01 in 2004 to $98.07 in 2005.

In October 2004, the FPSC determined that it was appropriate for Tampa Electric to recover through the ECRC the operating costs of and earn a return on the investment in the SCR to be installed on Big Bend Unit 4 for NOx control in compliance with the environmental consent decree. The SCR is scheduled to enter service by Jun. 1, 2007 and cost recovery, which is dependent on filings to be made in 2007, is expected to start in 2008.

Coal Transportation Contract

Tampa Electric’s contract for coal transportation and storage services with TECO Transport expired on Dec. 31, 2003. TECO Transport had been providing river and cross-gulf transportation services and storage services under that contract since 1999, and under a series of contracts for more than 40 years. Following a Request For Proposal (RFP) process, Tampa Electric executed a new five-year contract with TECO Transport, effective Jan. 1, 2004, for waterborne coal transportation and storage services at market rates supported by the results of the RFP and an independent expert in maritime transportation matters. The prudence of the RFP process and final contract were originally scheduled to be reviewed by the FPSC in the course of the normal fuel cost recovery hearings in November 2003. The hearing was deferred due to protests from other parties seeking more time to evaluate the contract information.

Three days of hearings were held in late May and early June of 2004 and a final order on the matter issued in October 2004. The order reduced the annual amount Tampa Electric can recover from its customers through the fuel adjustment clause for the water transportation services for coal and petroleum coke provided by TECO Transport. The annual after-tax disallowance is estimated to be $8 million to $10 million, depending on the volumes and origination points of the coal shipments, for as long as the contract is in effect. The order neither required Tampa Electric to rebid nor prohibit Tampa Electric from rebidding the contract, which expires Dec. 31, 2008.

In October 2004, Tampa Electric filed a motion for clarification and reconsideration of the order. In the motion, Tampa Electric stated that the FPSC had failed to take into account information that was available that could have changed the outcome. Had the FPSC considered all of the relevant facts, including the rate approved for Progress Energy Florida’s waterborne transportation needs, Tampa Electric believes that the FPSC would have arrived at a rate that is comparable to the contract rate. Tampa Electric also asked the FPSC for clarification on the ruling specifically regarding the bidding guidelines provided in the order and the FPSC process associated with the rebidding.

On Mar. 1, 2005, the FPSC heard oral arguments on the motion and denied Tampa Electric’s request for reconsideration and clarification. Although the Commission’s order will not contain clarifying language, through extended Commission discussion it was clear to Tampa Electric that if it decided to rebid waterborne transportation services and if it followed bid procedures approved by the FPSC, the results would likely be deemed appropriate for full cost recovery.

Storm Damage Cost Recovery

Following Hurricane Andrew in 1992, Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage for hurricanes, tornados or other damage due to destructive acts of nature. Tampa Electric and other IOUs were permitted to implement a self-insurance program effective Jan. 1, 1994 for such costs of restoration, and the FPSC authorized Tampa Electric to accrue $4 million annually to grow its unfunded storm damage reserve. Tampa Electric had never utilized its reserve before the 2004 hurricane season and would have had a reserve balance of $44 million at Dec. 31, 2004.

The costs for restoration associated with hurricanes Charley, Frances and Jeanne were estimated to be $72 million at Dec. 31, 2004, which exceeded the storm damage reserve by $28 million. These costs were charged against the storm damage reserve and therefore did not reduce earnings but did reduce cash flow from operations.

Tampa Electric filed for and received approval from the FPSC to defer prudently incurred storm damage restoration costs to the reserve until alternative accounting treatment is sought. At this time Tampa Electric is evaluating several options based upon recent FPSC actions taken with other Florida IOUs that have already filed for recovery of storm damage costs.

Cost Recovery Clauses – Peoples Gas

In November 2004, the FPSC approved rates under Peoples’ Gas Purchased Gas Adjustment (PGA) for the period January 2005 through December 2005 for the recovery of the costs of natural gas purchased for its distribution customers. The PGA is a factor that can vary monthly due to changes in actual fuel costs but is not anticipated to exceed the annual cap.

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 alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high quality service to retail customers.

Presently there is competition in Florida’s wholesale power markets, increasing largely as a result of the Energy Policy Act of 1992 and related federal initiatives. However, the state’s Power Plant Siting Act, which sets the state’s electric energy and environmental policy and governs the building of new generation involving steam capacity of 75 megawatts or more, requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits.

In 2003, the FPSC implemented rules modifying rules from 1994 that required IOUs to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 megawatts. The modified rules provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids, and provide more stringent standards for the IOUs to recover cost overruns in the event the self-build option is deemed the most cost-effective. The new rules became effective prospectively for requests for proposal for applicable capacity additions.

FERC Market Power Test

In November 2004, Tampa Electric and the market-based rate authorized entities within TECO Energy filed a triennial market power study update. On Mar. 2, 2005, after a review of that filing and supporting information, the FERC determined that Tampa Electric had failed certain tests for market power within two regions of peninsular Florida, primarily comprised of Tampa Electric Company’s own service territory. Tampa Electric Company currently only sells wholesale power within its own service territory at cost-based rates that have been previously approved by FERC. The FERC has instituted an investigation of Tampa Electric’s potential market power in those two regions and ordered that Tampa Electric make a compliance filing to provide documentation demonstrating that Tampa Electric does not have market power in any other region of the state. If it is ultimately determined that Tampa Electric does have market power in the two already-identified regions, it could lose its market-based rate authorization for only those regions. The Company could continue to make wholesale power sales at cost-based rates in those two regions, and at market-based rates throughout the rest of the state and the country. Tampa Electric intends to comply with all of the filing requirements and is evaluating the appropriate response to the FERC’s actions.

Regional Transmission Organization (RTO)

In December 1999, the FERC issued Order No. 2000, dealing with its continuing effort to effect open access to transmission facilities in large regional markets. In response, the peninsular Florida IOUs (Florida Power & Light, Progress Energy Florida and Tampa Electric) agreed to form an RTO to be known as GridFlorida LLC which would independently control the transmission assets of the filing utilities, as well as other utilities in the region that chose to join. In March 2001, the FERC conditionally approved GridFlorida.

Following challenges to the proposed structure by the FPSC in 2001 and subsequent modification of the plans by the three filing utilities, including modifying the proposal to develop a non-transmission owning RTO model, the FPSC voted to approve many of the compliance changes submitted in August 2002. The process was again delayed in 2002 when the Office of Public Counsel (OPC) filed an appeal with the Florida Supreme Court asserting that the FPSC could not relinquish its jurisdictional responsibility to regulate the IOUs and, by approving GridFlorida, they were doing just that. The Florida Supreme Court dismissed the OPC appeal in May 2003, citing that it was premature because certain portions of the FPSC GridFlorida order are not final.

Following a September 2003 joint meeting of the FERC and FPSC to discuss wholesale market and RTO issues related to GridFlorida and in particular federal/state interactions, deliberations by the FPSC were put on hold in 2004 to allow a consulting firm, engaged by the GridFlorida applicants, to conduct a cost/benefit study of the GridFlorida RTO. As a result, the FPSC held a series of collaborative meetings during the year with all interested parties to facilitate the development of the study methodology as well as participate in the submission of data required to complete the study. Upon conclusion of the study, which is expected to occur in the second quarter of 2005, the study results will be presented to the FPSC. The FPSC is then expected to make a determination as to whether to set the remaining items for hearing or to require the Florida IOUs to take other actions.

Peoples Gas 2002 Rate Proceeding

On Jun. 27, 2002, PGS filed a petition with the FPSC to increase its service rates. The requested rates would have resulted in a $22.6 million annual base revenue increase, reflecting a ROE mid- point of 11.75%.

PGS agreed to a settlement with all parties involved, and a final FPSC order was granted on Dec. 17, 2002. PGS received authorization to increase annual base revenues by $12.05 million. The new rates provide an allowed ROE range from 10.25% to 12.25% with an 11.25% midpoint, and a capital structure with 57.43% equity and were effective after Jan. 16, 2003.

Utility Competition – Gas

Although PGS 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, including electricity.

In Florida, gas service is unbundled for all non-residential customers. In November 2000, PGS implemented its “NaturalChoice” program offering unbundled transportation service to all eligible customers. This means that non-residential customers can purchase commodity gas from a third party but continue to pay PGS for the transportation of the gas.

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, by transporting gas through other facilities and thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation services at discounted rates.

In general, PGS faces competition from other energy source suppliers offering fuel oil, electricity and, in some cases, propane. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.

CORPORATE GOVERNANCE

In the last several years, the U.S. Congress, the U.S. Securities and Exchange Commission (SEC), the New York Stock Exchange (NYSE), and other interested groups have focused extensively on improving corporate accountability and corporate governance in an effort to restore investor confidence. The rules passed by the SEC and the listing standards adopted by the NYSE require, among other things, independence by the Board of Directors and various Board committees, a statement of governance guidelines and detailed committee charters, an internal audit function, a code of ethics for the CEO, senior financial officers and directors, adequate internal controls to detect fraud, increased oversight of financial disclosure by the Audit Committee, and certification by the CEO and CFO of the financial results.

The corporate culture of TECO Energy is based on integrity and sound business ethics. We have longstanding policies and practices that are designed to provide the framework for the ethical operation of the company, protect the shareholders’ interests, and ensure compliance with the law and requirements of the NYSE. For many years, the vast majority of our Board of Directors have been independent, and the required independent Board committees have been in place. In addition, we have had a rigorous internal audit and compliance function, including an anonymous reporting system which now has been expanded to cover matters required to be disclosed to the Audit Committee and the non-management directors, and a code of ethics for all employees and officers, called the Standards of Integrity. The code was expanded in 2002 to include directors and is posted on the company’s website. In addition, to ensure that our vendors are aware of our expectation that they conduct their business in an ethical and professional manner, we require that they comply, as we do, with the Principles and Standards of Ethical Supply Management Conduct published by the Institute for Supply Management.

At TECO Energy, we are committed to integrity and transparency in our financial reporting. Our existing controls and procedures for full and complete financial reporting and disclosure have been formalized into a comprehensive system of checks and balances that are reviewed quarterly for effectiveness. The CEO and CFO have filed with the SEC, as required by law, sworn statements certifying without exception the accuracy of the financial statements each quarter, and the annual certification is filed as an exhibit to our Annual Report on Form 10-K. Additionally, the CEO has signed and filed with the NYSE all of the required certifications as to compliance with the NYSE’s corporate governance listing standards.

The Board of Directors operates under a set of guidelines that clearly establish the Board’s responsibilities, and each committee has a charter that defines its purpose, duties and responsibilities. The Corporate Governance Guidelines and the committee charters are reviewed regularly to ensure that they comply with all of the relevant regulations and meet the needs of the Board. More information about the members of the Board of Directors, as well as copies of the Corporate Governance Guidelines, the various committee charters, and the Standards of Integrity, can be found in the corporate governance section of the Investor Relations page on our website,www.tecoenergy.com.

INTERNAL CONTROLS

Compliance with Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) and related rules of the Securities and Exchange Commission require management of public companies to assess the effectiveness of the company’s internal controls over financial reporting as of the end of each fiscal year. This includes disclosure of any material weaknesses in the company’s internal controls over financial reporting that have been identified by management. In addition, SOX 404 requires the company’s independent auditor to attest to and report on management’s annual assessment of the company’s internal controls over financial reporting. We have documented, tested and assessed our systems of internal control over financial reporting, as required under SOX 404 and Public Company Accounting Oversight Board Auditing Standard No. 2, An Audit of Internal Control Over Financial Reporting Performed in Conjunction With An Audit of Financial Statements (Standard No. 2), which was adopted in June 2004, to provide the basis for management’s report and our independent auditor’s attestation on the effectiveness of our internal control over financial reporting as of December 31, 2004. We estimate our SOX 404 compliance costs in 2004 were approximately $6.3 million, which include $4.0 million of external costs.

There are three levels of possible deficiencies in our internal controls over financial reporting that can be identified during our assessment phase, which are:

• an internal control deficiency, which exists when the design or the operation of a control does not allow management or employees, in the normal course of performing their functions, to prevent or detect misstatements on a timely basis;

• a significant deficiency, which exists when an internal control deficiency or a combination of internal controls deficiencies adversely affects our ability to initiate, authorize, record, process or report financial data in accordance with GAAP such that there is a more than remote likelihood that a misstatement of the annual or interim financial statements that is more than inconsequential will not be prevented or detected; and

• a material weakness, which exists when a significant deficiency or a combination of significant deficiencies results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

As a result, our assessment could result in two possible outcomes at our reporting date:

• we could conclude that our internal controls over financial reporting were designed and were operating effectively, or

• we could conclude that our internal controls over financial reporting were not properly designed or did not operate effectively. A material weakness that exists at the reporting date would require our assessment to be that our internal controls over financial reporting are not effective, and we would be required to disclose such material weaknesses.

Our independent auditor is now required to issue three opinions annually, beginning with our 2004 consolidated financial statements. First, the auditor must evaluate and opine regarding the process by which we assessed the effectiveness of our internal controls over financial reporting. A second opinion must be issued as to the effectiveness of our internal controls over financial reporting. Finally, as in the past, the independent auditor must issue an opinion, as to whether our consolidated financial statements are fairly presented in all material respects.

The scope of our assessment of our internal controls over financial reporting included all of our consolidated entities. We have completed the assessment of the effectiveness on our internal controls over financial reporting as of Dec. 31, 2004, and have concluded that our controls are operating effectively.

TRANSACTIONS WITH RELATED AND CERTAIN OTHER PARTIES

We have interests in unconsolidated affiliates, which are discussed in theOther Unregulated Companies andOff-Balance Sheet Financing sections.

In October 2003, Tampa Electric signed a five-year contract renewal with an affiliate company, TECO Transport Corporation, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008 (see theTampa Electric andRegulation sections).

NON-GAAP PRESENTATION

Many times in this Managements Discussion and Analysis of Financial Condition and Results of Operations, we present non-GAAP results which present financial results after elimination of the effects of certain identified gains and charges. We believe that the presentation of this non-GAAP financial performance provides investors a measure that reflects the company’s operations under our business strategy. We also believe that it is helpful to present a non-GAAP measure of performance that clearly reflects the ongoing operations of our business and allows investors to better understand and evaluate the business as it is expected to operate in future periods. Management and the Board of Directors use this non-GAAP presentation as a yardstick for measuring our performance, making decisions that are dependent upon the profitability of our various operating units and in determining levels of incentive compensation.

The non-GAAP measure of financial performance we use is not a measure of performance under accounting principles generally accepted in the United States and should not be considered an alternative to net income or other GAAP figures as an indicator of our financial performance or liquidity. Our non-GAAP presentation of net income may not be comparable to similarly titled measures used by other companies.

While each of the particular excluded items is not expected to recur, there may be true-ups to charges related to merchant power facilities or additional debt extinguishment activities. We recognize that there may be items that could be excluded in the future. Even though charges may occur, we believe the non-GAAP measure is important in addition to GAAP net income for assessing our potential future performance because excluded items are limited to those that we believe are not indicative of future performance.

INVESTMENT CONSIDERATIONS

The following are certain factors that could affect TECO Energy’s future results. They should be considered in connection with evaluating forward-looking statements made by or on behalf of TECO Energy because these factors could cause actual results and conditions to differ materially from those projected in those forward-looking statements.

Financing Risks

We have substantial indebtedness, which could adversely affect our financial condition and financial flexibility.

In recent years we have significantly increased our indebtedness, which has resulted in an increase in the amount of fixed charges we are obligated to pay. The level of our indebtedness and restrictive covenants contained in our debt obligations could limit our ability to obtain additional financing or refinance existing debt and could prevent the repayment of subordinated debt and the payment of dividends if those payments would cause a violation of the covenants.

TECO Energy and Tampa Electric must meet certain financial tests as defined in the applicable agreements to use our and its respective bank credit facilities. Also, we, Tampa Electric and other operating companies have certain restrictive covenants in specific agreements and debt instruments. The restrictive covenants of our subsidiaries could limit their ability to make distributions to us, which would further limit our liquidity (seethe Credit Facilities andCovenants in Financing Agreements sections andSignificant Financial Covenants table in theLiquidity, Capital Resources sections).

As of Dec. 31, 2004, we were not in compliance with the EBITDA-to-interest or debt-to-total capital financial covenants in our construction undertakings associated with TWG’s Gila River and Union projects, which, absent the pending sale or other transfer of the projects to the lenders, including through the previously announced pre-negotiated Chapter 11 cases filed by the project companies could result in the lenders seeking to accelerate the $1.395 billion of non-recourse construction debt. As of Dec. 31, 2004, we were otherwise in compliance with required financial covenants. We cannot assure you, however, that we will be in compliance with these financial covenants in the future. Our failure to comply with any of these covenants or to meet our payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. We may not have sufficient working capital or liquidity to satisfy our debt obligations in the event of an acceleration of all or a portion of our outstanding obligations. In addition, if we had to defer interest payments on our subordinated notes underlying the outstanding trust preferred securities, we would be prohibited from paying cash dividends on our common stock until all unpaid distributions on those subordinated notes were made.

We also incur obligations in connection with the operations of our subsidiaries and affiliates that do not appear on our balance sheet. These obligations take the form of guarantees, letters of credit and contractual commitments, as described in the sections titledLiquidity, Capital Resources andOff-Balance Sheet Financing. In addition, our unconsolidated affiliates from time to time incurred non-recourse debt to finance their power projects. Although we are not obligated on that debt, our investments in those unconsolidated affiliates are at risk if the affiliates default on their debt.

Our financial condition and ability to access capital may be materially adversely affected by further ratings downgrades.

On July 20, 2004, S&P lowered the ratings on our senior unsecured debt to BB with a stable outlook. It lowered the ratings on other of our securities, as well as those of TECO Finance, including lowering the rating of the trust preferred securities to B. S&P affirmed its rating of Tampa Electric Company’s senior secured and unsecured debt at BBB-with a stable outlook. In February 2004, Moody’s Investors Service lowered the ratings on our senior unsecured debt to Ba2 with a negative outlook. This followed actions in April 2003, when Moody’s and Fitch Ratings lowered their ratings on our senior unsecured debt to Ba1 and BB+, respectively, both with a negative outlook. Tampa Electric Company’s senior secured and unsecured debt ratings were lowered to Baa1 and Baa2, respectively, by Moody’s and to BBB+ for unsecured debt, by Fitch, with a negative outlook by Moody’s. These and any future downgrades may affect our ability to borrow, future collateral, or margin postings and may increase our financing costs, which may decrease our earnings. We are also likely to experience greater interest expense than we may have otherwise if, in future periods, we replace maturing debt with new debt bearing higher interest rates due to our lower credit ratings. In addition, such downgrades could adversely affect our relationships with customers and counterparties.

As a result of past rating actions, TECO EnergySource and other of our subsidiaries were required to post collateral with counterparties to transact in the forward markets for electricity and gas. At Dec. 31, 2004, because of our actions in 2004 to reduce our exposure to additional merchant power and to exit TECO Solutions’ businesses, we have minimal exposure to additional calls for collateral. At current ratings, Tampa Electric and PGS are able to purchase gas and electricity without providing collateral. If the ratings of Tampa Electric Company declined to below investment grade, Tampa Electric and Peoples Gas could be required to post collateral to support their purchases of gas and electricity.

If we are unable to limit capital expenditure levels as forecasted, our financial condition and results could be adversely affected.

Part of our plans includes capital expenditures at the operating companies at maintenance levels for the next several years. We cannot be sure that we will be successful in limiting capital expenditures to the planned amount. If we are unable to limit capital expenditures to the forecasted levels, we may need to draw on credit facilities, access the capital markets on unfavorable terms or ultimately sell additional assets to improve our financial position. We cannot be sure that we will be able to obtain additional financings or sell such assets, in which case our financial position, earnings and credit ratings could be adversely affected.

Because we are a holding company, we are dependent on cash flow from our subsidiaries, which may not be available in the amounts and at the times we need it.

We are a holding company and dependent on cash flow from our subsidiaries to meet our cash requirements that are not satisfied from external funding sources. Some of our subsidiaries have indebtedness containing restrictive covenants which, if violated, would prevent them from making cash distributions to us. In particular, certain long-term debt at PGS prohibits payment of dividends to us if Tampa Electric Company’s consolidated shareholders’ equity is lower than $500 million. At Dec. 31, 2004, Tampa Electric Company’s consolidated shareholders’ equity was approximately $1.7 billion. Also, our wholly owned subsidiary, TECO Diversified, Inc., the holding company for TECO Transport, TECO Coal and TECO Solutions, has a guarantee related to a coal supply agreement that could limit the payment of dividends by TECO Diversified to us.

Various factors could affect our ability to sustain our dividend.

Our ability to pay a dividend, or sustain it at current levels, could be affected by such factors as the level of our earnings and therefore our dividend payout ratio, and pressures on our liquidity, including unplanned debt repayments, unexpected capital, shortfalls in operating cash flow and negative retained earnings. These are in addition to any restrictions on dividends from our subsidiaries to us discussed above. The Public Utility Holding Company Act of 1935 (PUHCA) restricts the payment of distributions from capital for registered companies. However, we are not subject to such restrictions because we are exempt from registration under PUHCA.

We are vulnerable to interest rate changes and may not have access to capital at favorable rates, if at all.

Changes in interest rates and capital markets generally affect our cost of borrowing and access to these markets. We cannot be sure that we will be able to accurately predict the effect those changes will have on our cost of borrowing or access to capital markets.

Merchant Power Project Risks

We and the project companies have not yet completed the transfer of our ownership of the Union and Gila River projects to the lending group.

Our decision to exit from the ownership of the projects is not conditioned on reaching a consensual agreement with the lenders. If the pre-negotiated Chapter 11 cases of the project companies cannot be concluded as anticipated, there could be a delay in the ultimate forgiveness of the non-recourse debt and there could be a change in the accounting treatment from discontinued operations back to continuing operations in a future period.

The parties have retained the right to assert certain claims they may have against one another until the transfer is completed. Assertion of such claims and defense against them could be time consuming and costly and delay the ultimate disposition of our interest in the projects.

The remaining operating power plant owned by a subsidiary of TWG-Merchant is affected by market conditions until its sale is completed.

We have an agreement to sell our interest in the Commonwealth Chesapeake Power Station, and this transaction is expected to close by Mar. 31, 2005. However, this plant currently sells most of its power in the spot market, so we cannot predict with certainty:

• the amount or timing of revenue it may receive from power sales;

• the differential between the cost of operations and power sales revenue;

• the effect of competition from other suppliers of power;

• the demand for power in the market served by the plant relative to available supply; or

• the availability of transmission to accommodate the sale of power.

TWG-Merchant’s results could be adversely affected until the time that the sale of this power plant is completed.

The status of our investments in the suspended Dell and McAdams plants and the Commonwealth Chesapeake Power Station, which is in the process of being sold, is subject to uncertainties which could result in additional impairments.

Our investment in the Dell and McAdams power plants was written-down to reflect current fair market value as of Dec. 31, 2004 and we are pursuing the sale of these plants. Because the write-off was to estimated fair market value, there is a risk of further impairment should we be unable to sell them or otherwise obtain our estimated market value for them.

Likewise, we have entered into an agreement for the sale of our interest in the Commonwealth Chesapeake Power Station, which we expect to close near Mar. 31, 2005. Should this sale not be completed as planned, we would not receive the expected $86 million cash proceeds from this sale, and additional valuation adjustments could be required.

General Business and Operational Risks

General economic conditions may adversely affect our businesses.

Our businesses are affected by general economic conditions. In particular, the projected growth in Florida and Tampa Electric’s service area is important to the realization of Tampa Electric’s and PGS’ forecasts for annual energy sales growth. An unanticipated downturn in Florida’s or the local area’s economy could adversely affect Tampa Electric’s or PGS’ expected performance.

Our unregulated businesses particularly, TECO Transport, TECO Coal and the Guatemalan operations, are also affected by general economic conditions in the industries and geographic areas they serve, both nationally and internationally.

Potential competitive changes may adversely affect our regulated electricity and gas businesses.

The U.S. electric power industry has been undergoing 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. Though not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its performance.

The gas distribution industry has been subject to competitive forces for several years. Gas services provided by PGS are now unbundled for all non-residential customers. Because PGS earns margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS’ results. However, future structural changes that we cannot predict could adversely affect PGS.

Our gas and electricity businesses are highly regulated, and any changes in regulatory structures could lower revenues or increase costs or competition.

Tampa Electric and PGS 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 the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on Tampa Electric’s or PGS’ performance by, for example, increasing competition or costs, threatening investment recovery or impacting rate structure.

Our businesses are sensitive to variations in weather and have seasonal variations.

Most of our businesses are affected by variations in general weather conditions and unusually severe weather. Tampa Electric’s and PGS’ energy sales are particularly sensitive to variations in weather conditions. Those 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 like those experienced in 2004, could adversely affect operating costs and sales and cause damage to our facilities, which may require additional costs to repair.

PGS, which has a typically short but significant winter peak period that is dependent on cold weather, is more weather sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather in Florida can be expected to negatively impact results at PGS.

Variations in weather conditions also affect the demand and prices for the commodities sold by TECO Coal. TECO Transport is also impacted by weather because of its effects on the supply of and demand for the products transported. Severe weather conditions could interrupt or slow service and increase operating costs of those businesses.

Commodity price changes may affect the operating costs and competitive positions of our businesses.

Most of our businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes could affect the prices these businesses 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 affected primarily by the cost of coal and gas. 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.

The ability to make sales and the margins earned on wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS, 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 PGS relative to electricity, other forms of energy and other gas suppliers.

We rely on some transmission and distribution assets that we do not own or control to deliver wholesale electricity, as well as natural gas. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver power and natural gas may be hindered.

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell to the wholesale market, as well as the natural gas we purchase for use in our electric generation facilities. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual and service obligations may be hindered.

The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities. Likewise, unexpected interruption in upstream natural gas supply or transmission could affect our ability to generate power or deliver natural gas to local distribution customers.

The uncertain outcome regarding the creation of regional transmission organizations, or RTOs, may impact our operations, results or financial condition.

There continue to be proposals regarding development of RTOs, which would independently control the transmission assets of participating utilities in peninsular Florida. Given the regulatory uncertainty of the ultimate timing, structure and operations of any RTOs or an alternate combined transmission structure, we cannot predict what effect their creation will have on our future operations, results or financial condition.

We may be unable to take advantage of our existing tax credits, and our earnings from outside investors in the non-conventional fuels production facilities may be impacted by domestic oil prices.

We derive a portion of our net income from Section 29 tax credits related to the production of non-conventional fuels. Although we have sold more than 90% of our interest in the synthetic fuel production facilities in 2004 and 2005, the amounts we realize from the sales and our continuing operations of the facilities on behalf of the third-party owners are dependent on the continued availability to the purchaser of the tax credits, and our use of any remaining tax credits is dependent on our generating sufficient taxable income against which to use the credits. The availability of the Section 29 tax credits, both to those purchasers and us, could be negatively impacted by administrative actions of the Internal Revenue Service or the U.S. Treasury or changes in law, regulation or administration. In addition, although we have partially hedged against it, the tax credits to the purchasers of our non-conventional fuels production facilities could be limited if annual average domestic oil prices in 2005, as measured by the Department of Energy reference price, exceed an estimated $52 per barrel, which is the equivalent of $55 per barrel on NYMEX, and any such limitation could adversely affect our earnings and cash flows.

Impairment testing of certain long-lived assets and goodwill could result in impairment charges.

The company tests its long-lived assets and goodwill for impairment annually or more frequently if certain triggering events occur. Should the current carrying values of any of these assets not be recoverable, the company would incur charges to write down the assets to fair market value.

Problems with operations could cause us to incur substantial costs.

Each of our subsidiaries is subject to various operational risks, including accidents, or equipment failures and operations below expected levels of performance or efficiency. As operators of power generation facilities, Tampa Electric and TWG could incur problems such as the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes that would result in performance below assumed levels of output or efficiency. Our outlook assumes normal operations and normal maintenance periods for our operating companies’ facilities.

Our international projects and the operations of TECO Transport are subject to risks that could result in losses or increased costs.

Our other unregulated companies are involved in certain international projects. 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 international subsidiaries attempt to manage these risks through a variety of risk mitigation measures, including specific contractual provisions, obtaining non-recourse financing and obtaining political risk insurance where appropriate.

TECO Transport is exposed to operational risks in international ports, primarily due to its need for suitable labor and equipment to safely discharge its cargoes in a timely manner. TECO Transport attempts to manage these risks through a variety of risk mitigation measures, including retaining agents with local knowledge and experience in successfully discharging cargoes and vessels similar to those used by TECO Transport.

Changes in the environmental laws and regulations affecting our businesses could increase our costs or curtail our activities.

Our businesses are subject to 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 us or require us to curtail some of our businesses’ activities.

We are currently defending lawsuits in which we could be liable for damages and responding to an informal inquiry of the SEC.

A number of securities class action lawsuits were filed in August, September and October 2004 against us and certain of our current and former officers by purchasers of our securities. These suits, which were filed in the U.S. District Court for the Middle District of Florida, allege disclosure violations under the Securities Exchange Act of 1934. These actions were consolidated but remain at the initial pleading stage. In addition, in connection with the previously disclosed SEC informal inquiry resulting from a letter from the former non-equity member in the Commonwealth Chesapeake Project raising issues related to the arbitration proceeding involving that project, the SEC has requested additional information primarily related to the allegations made in these securities class action lawsuits, focusing on various merchant plant investments and related matters.

In March 2001, TWG (under its former name of TECO Power Services Corporation) was served with a lawsuit filed in Hillsborough County Florida, by a Tampa-based firm named Grupo Interamerica, LLC (Grupo) in connection with a potential investment in a power project in Colombia in 1996. Grupo alleged, among other things, that TWG breached an oral contract with Grupo. On Aug. 3, 2004, the trial court granted TWG’s motion for summary judgment, leaving only one count remaining in the lawsuit. On Oct. 18, 2004, TWG’s motion for summary judgment on the remaining count was granted. The plaintiffs have appealed, and we expect the appellate court to render a decision by the end of 2005.

On Aug. 30, 2004, a Colombian trade union, which was to have been the owner/lessor of the power plant if the transaction had been consummated, filed a demand for arbitration in Colombia pursuant to provisions of a confidentiality and exclusivity agreement (the “confidentiality agreement”) between the trade union and a subsidiary of TWG, TPS International Power, Inc., alleging breach of contract and seeking damages in the amount of $48 million. TECO Energy, Inc. and TWG were also named, although those companies were not parties to the confidentiality agreement. This arbitration is being funded by Grupo pursuant to a contract under which Grupo will share in the recovery, if any. The arbitration is in its preliminary stages, and although the respondents have not been served, the arbitrators have been selected by the parties. There is greater uncertainty of the outcome of this proceeding due to the venue and rules of the arbitration being governed by a foreign jurisdiction.

We intend to vigorously defend all of these proceedings. We cannot predict the ultimate resolution of any of these matters at this time, and there can be no assurance that these matters will not have a material adverse impact on our financial condition or results of operations. From time to time, TECO Energy and its subsidiaries are involved in various other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with the appropriate accounting rules to provide for matters that are probable of resulting in an estimable, material loss. While we do not believe that the ultimate resolution of pending matters will have a material adverse effect on our results of operations or financial condition, the outcome of such proceedings is uncertain.