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

Exhibit 99.1

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

TECO ENERGY, INC.

	Page No.
Management’s Report on Internal Control Over Financial Reporting	2
Report of Independent Registered Certified Public Accounting Firm	2-3
Consolidated Balance Sheets, Dec. 31, 2004 and 2003	4-5
Consolidated Statements of Income for the years ended Dec. 31, 2004, 2003 and 2002	6
Consolidated Statements of Comprehensive Income for the years ended Dec. 31, 2004, 2003 and 2002	7
Consolidated Statements of Cash Flows for the years ended Dec. 31, 2004, 2003 and 2002	8
Consolidated Statements of Capital for the years ended Dec. 31, 2004, 2003 and 2002	9
Notes to Consolidated Financial Statements	10-55
Financial Statement Schedule I – Condensed Parent Company Financial Statements	56-59
Financial Statement Schedule II – Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2004, 2003 and 2002	60

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

TECO ENERGY, INC.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of our internal control over financial reporting as of Dec. 31, 2004 based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was effective as of Dec. 31, 2004.

PricewaterhouseCoopers LLP, an independent registered certified public accounting firm, has audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2004 as stated in their report appearing herein.

REPORT OF INDEPENDENT REGISTERED CERTIFIED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of TECO Energy, Inc.:

We have completed an integrated audit of TECO Energy, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of Dec. 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at Dec. 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended Dec. 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in theNote 2, 15,7 and17 to the consolidated financial statements, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 46-R, “Consolidation of Variable Interest Entities,” on Jan. 1, 2004, Financial Accounting Standards 143, “Accounting for Asset Retirement Obligations,” on Jan. 1, 2003, Financial Accounting Standard 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” on Jan. 1, 2003, and Financial Accounting Standard 142, “Goodwill and Other Intangible Assets,” on Jan. 1, 2002, respectively.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing above, that the Company maintained effective internal control over financial reporting as of Dec. 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of Dec. 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting,

evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

Mar. 1, 2005, except as to the effects of reclassifications of

2004, 2003 and 2002 amounts for reportable segments and

discontinued operations as discussed inNotes 14

and25, respectively, as to which the date is

May 11, 2005.

TECO ENERGY, INC.

Consolidated Balance Sheets

Assets (millions) Dec. 31,	2004			2003
Current assets
Cash and cash equivalents	$	96.7		$	108.2
Restricted cash		57.1			51.4
Receivables, less allowance for uncollectibles of $8.0 and $4.5 at Dec. 31, 2004 and 2003, respectively		286.8			280.4
Inventories, at average cost
Fuel		46.2			88.2
Materials and supplies		74.6			82.5
Current derivative assets		3.8			21.1
Prepayments and other current assets		43.6			68.6
Assets held for sale		128.8			169.4
Total current assets		737.6			869.8
Property, plant and equipment
Utility plant in service
Electric		4,857.9			5,245.6
Gas		810.8			778.1
Construction work in progress		207.1			1,151.1
Other property		847.6			865.4
Property, plant and equipment, at original cost		6,723.4			8,040.2
Accumulated depreciation		(2,065.5	)		(2,361.2	)
Total property, plant and equipment (net)		4,657.9			5,679.0
Other assets
Deferred income taxes		1,379.1			1,051.5
Other investments		8.0			16.5
Regulatory assets		200.9			188.3
Investment in unconsolidated affiliates		263.0			343.5
Goodwill		59.4			71.2
Deferred charges and other assets		111.5			165.1
Assets held for sale		2,059.1			2,077.4
Total other assets		4,081.0			3,913.5
Total assets	$	9,476.5		$	10,462.3

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

TECO ENERGY, INC.

Consolidated Balance Sheets –continued

Liabilities and capital (millions) Dec. 31,	2004			2003
Current liabilities
Long-term debt due within one year
Recourse	$	5.5		$	6.1
Non-recourse		8.1			25.5
Notes payable		115.0			37.5
Accounts payable		257.8			313.8
Customer deposits		105.8			101.4
Current derivative liabilities		11.5			12.0
Interest accrued		50.6			56.6
Taxes accrued		36.3			149.9
Liabilities associated with assets held for sale		1,631.8			1,544.4
Total current liabilities		2,222.4			2,247.2
Other liabilities
Deferred income taxes		504.1			498.0
Investment tax credits		20.0			22.8
Regulatory liabilities		539.0			560.2
Long-term derivative liability		0.5			—
Deferred credits and other liabilities		351.5			364.1
Liabilities associated with assets held for sale		672.2			697.8
Long-term debt, less amount due within one year
Recourse		3,588.9			3,660.3
Non-recourse		13.4			83.2
Junior subordinated		277.7			649.1
Minority interest		2.9			1.9
Total other liabilities		5,970.2			6,537.4
Commitments and contingencies (see Note 12)
Capital
Common equity (400 million shares authorized; par value $1; 199.7 million shares and 187.8 million shares outstanding at Dec. 31, 2004 and 2003, respectively)		199.7			187.8
Additional paid in capital		1,489.4			1,220.8
Retained earnings (deficit)		(357.6	)		339.5
Accumulated other comprehensive income		(43.8	)		(55.8	)
Common equity		1,287.7			1,692.3
Unearned compensation		(3.8	)		(14.6	)
Total capital		1,283.9			1,677.7
Total liabilities and capital	$	9,476.5		$	10,462.3

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

TECO ENERGY, INC.

Consolidated Statements of Income

(millions, except per share amounts) For the years ended Dec. 31,	2004			2003			2002
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $83.8 in 2004, $77.7 in 2003 and $73.8 in 2002)	$	2,101.0		$	1,991.1		$	1,867.0
Unregulated		538.4			571.8			620.3
Total revenues		2,639.4			2,562.9			2,487.3
Expenses
Regulated operations
Fuel		536.7			344.9			312.7
Purchased power		172.3			184.7			202.3
Cost of natural gas sold		226.2			224.0			148.9
Other		258.2			258.4			257.2
Other operations		590.5			595.7			568.7
Maintenance		137.4			144.8			159.8
Depreciation		275.9			313.4			290.6
Asset impairment		632.2			132.9			—
Goodwill and intangible asset impairment		4.8			6.7			—
Restructuring charges		1.2			24.6			17.8
Taxes, other than income		184.3			171.6			169.0
Total expenses		3,019.7			2,401.7			2,127.0
(Loss) income from operations		(380.3	)		161.2			360.3
Other (expense) income
Allowance for other funds used during construction		0.7			19.8			24.9
Other income		143.0			119.9			19.3
Loss on debt extinguishment		(4.4	)		—			(34.1	)
Impairment on TIE investment		(152.3	)		—			—
Income (loss) from equity investments		36.1			(0.4	)		5.5
Total other income (expense)		23.1			139.3			15.6
Interest charges
Interest expense		323.2			284.1			140.0
Distribution on preferred securities of subsidiary		—			40.0			38.9
Allowance for borrowed funds used during construction		(0.3	)		(7.6	)		(9.6	)
Total interest charges		322.9			316.5			169.3
(Loss) income from continuing operations before provision for income taxes		(680.1	)		(16.0	)		206.6
(Benefit) for income taxes		(245.1	)		(67.9	)		(58.8	)
Net (loss) income from continuing operations before minority interests		(435.0	)		51.9			265.4
Minority interest		79.5			48.8			—
Net (loss) income from continuing operations		(355.5	)		100.7			265.4
Discontinued operations
(Loss) income from discontinued operations		(294.0	)		(1,577.3	)		79.2
Income tax (benefit) provision		(97.5	)		(571.5	)		14.5
Total discontinued operations		(196.5	)		(1,005.8	)		64.7
Cumulative effect of change in accounting principle, net of tax		—			(4.3	)		—
Net (loss) income	$	(552.0	)	$	(909.4	)	$	330.1
Average common shares outstanding
– Basic		192.6			179.9			153.2
– Diluted		192.6			180.2			153.3
Earnings per share from continuing operations
– Basic	$	(1.85	)	$	0.56		$	1.73
– Diluted	$	(1.85	)	$	0.56		$	1.73
Earnings per share
– Basic	$	(2.87	)	$	(5.05	)	$	2.15
– Diluted	$	(2.87	)	$	(5.04	)	$	2.15
Dividends paid per common share outstanding	$	0.76		$	0.925		$	1.41

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

TECO ENERGY, INC.

Consolidated Statements of Comprehensive Income

(millions) For the years ended Dec. 31,	2004			2003			2002
Net (loss) income	$	(552.0	)	$	(909.4	)	$	330.1
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments		—			1.2			(1.2	)
Net unrealized gains (losses) on cash flow hedges		4.8			28.1			(13.2	)
Minimum pension liability adjustments		7.2			(43.9	)		(4.4	)
Other comprehensive income (loss), net of tax		12.0			(14.6	)		(18.8	)
Comprehensive (loss) income	$	(540.0	)	$	(924.0	)	$	311.3

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

TECO ENERGY, INC.

Consolidated Statements of Cash Flows

(millions) For the years ended Dec. 31,	2004			2003			2002
Cash flows from operating activities
Net income (loss)	$	(552.0	)	$	(909.4	)	$	330.1
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation		289.6			382.0			303.2
Deferred income taxes		(355.3	)		(709.4	)		(96.6	)
Investment tax credits, net		(2.9	)		(4.7	)		(4.8	)
Allowance for funds used during construction		(1.0	)		(27.4	)		(34.5	)
Amortization of unearned compensation		13.6			18.3			13.9
Cumulative effect of change in accounting principle, pretax		—			7.1			—
Gain on sales of business/assets, pretax		(92.9	)		(147.5	)		(15.1	)
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		(34.3	)		13.8			15.3
Minority loss		(79.5	)		(48.8	)		—
Asset impairment, pretax		876.7			1,330.7			—
Goodwill and intangible asset impairment, pretax		16.6			122.7			—
TMDP arbitration (recovery) reserve, pretax		(5.6	)		32.0			—
Loss on joint venture termination, pretax		—			153.9			—
Deferred recovery clause		20.2			(27.3	)		72.2
Refunded to customers		—			—			(6.4	)
Receivables, less allowance for uncollectibles		32.1			96.4			(64.1	)
Inventories		41.9			7.0			(39.4	)
Prepayments and other deposits		(0.8	)		(16.5	)		6.3
Taxes accrued		(82.0	)		34.5			24.1
Interest accrued		76.7			(60.7	)		14.2
Accounts payable		(69.2	)		(17.5	)		98.3
Other		47.7			82.1			39.0
Cash flows from operating activities		139.6			311.3			655.7
Cash flows from investing activities
Capital expenditures		(273.2	)		(590.6	)		(1,065.2	)
Allowance for funds used during construction		1.0			27.4			34.5
Purchase of minority interest		—			—			(9.9	)
Net proceeds from sales of business/assets		349.5			296.5			103.3
Net cash reduction from deconsolidation		(22.7	)		—			—
Restricted cash		(34.3	)		(46.2	)		—
Distributions from (investment in) unconsolidated affiliates		45.4			(30.6	)		(7.6	)
Other non-current investments		24.7			(32.4	)		(715.6	)
Cash flows from investing activities		90.4			(375.9	)		(1,660.5	)
Cash flows from financing activities
Dividends		(145.2	)		(165.2	)		(215.8	)
Common stock		10.2			136.6			572.6
Proceeds from long-term debt		—			655.1			1,758.4
Repayment of long-term debt		(225.0	)		(526.5	)		(949.7	)
Minority interest		76.1			44.4			—
Restricted cash		—			(5.9	)		—
Early exchange of equity units		(17.7	)		—			—
Settlement of joint venture termination obligation		—			(33.5	)		—
Net increase (decrease) in short-term debt		77.5			(323.0	)		(278.4	)
Issuance of preferred securities		—			—			435.6
Equity contract adjustment payments		(17.4	)		(20.3	)		(15.3	)
Cash flows from financing activities		(241.5	)		(238.3	)		1,307.4
Net (decrease) increase in cash and cash equivalents		(11.5	)		(302.9	)		302.6
Cash and cash equivalents at beginning of the year		108.2			411.1			108.5
Cash and cash equivalents at end of the year	$	96.7		$	108.2		$	411.1
Supplemental disclosure of cash flow information
Cash paid during the year for:
Interest (net of amounts capitalized)(1)	$	372.1		$	493.1		$	160.2
Income taxes	$	22.4		$	58.8		$	71.9

(1) Included in interest paid during the year is interest paid on debt obligation for discontinued operations of $51.5 million and $166.6 million for 2004 and 2003, respectively. There was no interest paid on debt obligations for discontinued operations in 2002.

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

TECO ENERGY, INC.

Consolidated Statements of Capital

(millions)	Shares(1)	Common Stock		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Unearned Compensation			Total Capital
Balance, Dec. 31, 2001	139.6	$	139.6	$	600.7		$	1,298.0		$	(22.4	)	$	(44.3	)	$	1,971.6
Net income for 2002								330.1									330.1
Other comprehensive (loss), after tax											(18.8	)					(18.8	)
Common stock issued	36.2		36.2		544.4									(8.0	)		572.6
Cash dividends declared								(215.8	)								(215.8	)
Amortization of unearned compensation														13.9			13.9
Convertible preferred stock – present value of contract adjustment payments					(53.1	)											(53.1	)
Tax benefits — ESOP dividends and stock options					2.5			1.4									3.9
Performance shares														7.3			7.3
Balance, Dec. 31, 2002	175.8	$	175.8	$	1,094.5		$	1,413.7		$	(41.2	)	$	(31.1	)	$	2,611.7
Net (loss) for 2003								(909.4	)								(909.4	)
Other comprehensive (loss), after tax											(14.6	)					(14.6	)
Common stock issued	12.0		12.0		125.0									(0.4	)		136.6
Cash dividends declared								(165.2	)								(165.2	)
Amortization of unearned compensation														18.3			18.3
Tax benefits — ESOP dividends and stock options					1.3			0.4									1.7
Performance shares														(1.4	)		(1.4	)
Balance, Dec. 31, 2003	187.8	$	187.8	$	1,220.8		$	339.5		$	(55.8	)	$	(14.6	)	$	1,677.7
Net (loss) for 2004								(552.0	)								(552.0	)
Other comprehensive income, after tax											12.0						12.0
Common stock issued	0.9		0.9		7.8									1.5			10.2
Cash dividends declared								(145.2	)								(145.2	)
Early exchange of equity security units	10.2		10.2		251.6												261.8
Settlement of claim	0.8		0.8		9.2												10.0
Amortization of unearned compensation														13.6			13.6
Tax benefits — ESOP dividends								0.1									0.1
Performance shares														(4.3	)		(4.3	)
Balance, Dec. 31, 2004	199.7	$	199.7	$	1,489.4		$	(357.6	)	$	(43.8	)	$	(3.8	)	$	1,283.9

(1) TECO Energy had a maximum of 400 million shares of $1 par value common stock authorized as of Dec. 31, 2004, 2003 and 2002.

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

TECO ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

The significant accounting policies for both utility and diversified operations are as follows:

Principles of Consolidation

The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries (TECO Energy or the company). All significant inter-company balances and inter-company transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiary companies do not have majority ownership or exercise control.

TECO Energy adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46 (FIN 46),Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, as of Oct. 1, 2003 with no material impact. Effective Jan. 1, 2004 the company adopted Financial Accounting Standards Board Interpretation No. 46R,Consolidation of Variable Interest Entities, an interpretation of ARB No. 51,(FIN 46R) which impacted the consolidation principles applied to certain entities. For entities that are determined to meet the definition of a variable interest entity (VIE), the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest. FIN 46R impacted the consolidation policy for the subsidiaries that hold interests in San José and Alborada power stations in Guatemala, the funding companies involved in the issuance of the trust preferred securities, TECO AGC., Ltd., and Hernando Oaks, LLC (seeNote 2). For all other entities, the general consolidation principles described above apply.

Results of operations for the proportional share of expenses, revenues and assets reflecting TECO Coalbed Methane’s undivided interest in joint venture property are included in the consolidated financial statements through Dec. 31, 2002 (seeNote 16).

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates.

Revised Segment Reporting

In 2003, the company, as part of its renewed focus on core utility and profitable unregulated operations, revised internal reporting information used for decision making purposes. With this change, management focused on the results and performance of TECO Wholesale Generation, Inc. (formerly TECO Power Services Corporation), or TWG-Merchant, as a segment comprised of all merchant operations, from which the Frontera, Union, and Gila River projects’ operations have been reclassified to discontinued operations. TWG-Merchant includes the results of operations for the Dell and McAdams power plants, as well as the equity investment in the Texas Independent Energy (TIE) projects up to the date of sale (seeNote 16 for details), held through PLC Development Holdings, LLC (PLC), and TECO EnergySource (TES), the energy marketing operation for the merchant plants.

The non-merchant operations, formerly included in the TECO Power Services operating segment, are comprised of the results from Hardee Power Partners, Ltd. (HPP) and the equity investment in the Hamakua power plant in Hawaii, up to the date of sale (see Note 16 for details), the Guatemalan operations which include equity investments in the San José and Alborada power plants and an equity investment in the Guatemalan distribution company, EEGSA, and other non-merchant activities. These non-merchant power operations were reported in the Other Unregulated segment.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Restricted Cash

Restricted cash at Dec. 31, 2004 and Dec. 31, 2003 includes $50.0 million and $15.4 million, respectively, of cash held in escrow related to the 2003 sale of TECO Coal Corporation’s (TECO Coal) indirectly owned synthetic fuel production facilities (to provide credit support for the company’s current credit rating). The $50.0 million of cash from the synthetic fuel facility sale will be retained in escrow to support the company’s obligation under the sale agreement, until the expiration of the agreement or TECO Energy achieves an investment-grade credit rating. Restricted cash at Dec. 31, 2004 and Dec. 31, 2003 also includes $7.1 million and $36.0 million, respectively, of cash held in escrow related to the 2003 sale of Hardee Power Partners (seeNote 16).

Cost Capitalization

Development costs – TECO Energy capitalizes the external costs of construction-related development activities after achieving certain project-related milestones that indicate that completion of a project is probable. Such costs include direct incremental amounts incurred for professional services (primarily legal, engineering and consulting services), permits, options and deposits on land and equipment purchase commitments, capitalized interest and other related costs. In accordance with Statement of Position (SOP) 98-5,Reporting on the Costs of Start-up Activities, start-up costs and organization costs are expensed as incurred.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt.

Capitalized interest expense – Interest costs for the construction of non-utility facilities are capitalized and depreciated over the service lives of the related property. TECO Energy capitalized $0.7 million, $17.3 million and $63.2 million of interest costs in 2004, 2003, and 2002, respectively.

Planned Major Maintenance

TECO Energy accounts for planned maintenance projects by expensing the costs as incurred. Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.

Tampa Electric, Peoples Gas System (PGS) and TWG-Merchant expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with Florida Public Service Commission (FPSC) and Federal Energy Regulatory Commission (FERC) regulations.

The San José and Alborada plants in Guatemala each have a long-term power purchase agreement (PPA) with Empresa Eléctrica de Guatemala, S.A. (EEGSA). A major maintenance revenue recovery component is implicit in the capacity payment portion of the PPA for each plant. Accordingly, a portion of each monthly fixed capacity payment is deferred to recognize the portion that reflects recovery of future planned major maintenance expenses. Actual maintenance costs are expensed when incurred with a like amount of deferred recovery revenue recognized at the same time.

Depreciation

TECO Energy provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over its estimated service life. Unregulated electric generating, pipeline and transmission facilities are depreciated over the expected useful lives of the related equipment, a period of up to 40 years. The provision for total regulated and unregulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.9% for 2004, 4.5% for 2003 and 4.2% for 2002. 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 issued by the FPSC. Construction work-in-progress is not depreciated until the asset is completed or placed in service.

The implementation of FAS 143,Accounting for Asset Retirement Obligations, in 2003 resulted in an increase in the carrying amount of long-lived assets and the reclassification of the accumulated reserve for cost of removal as “Regulatory liabilities” for all periods presented. The adjusted capitalized amount is depreciated over the remaining useful life of the asset. SeeNote 15.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 7.79% for 2004, 2003 and 2002. Total AFUDC for 2004, 2003 and 2002 was $1.0 million, $27.4 million and $34.5 million, respectively. The base on which AFUDC is calculated excludes construction work-in-progress which has been included in rate base.

Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates are accounted for using the equity method of accounting. The percentage ownership interest for each investment at Dec. 31, 2004 and 2003 is presented in the following table:

TECO Energy and Subsidiaries’ Percent Ownership in Unconsolidated Affiliates

Dec. 31,	2004		2003
TECO Wholesale Generation (TWG)
Texas Independent Energy, L.P. (TIE)(1)	—		50	%
TECO Transport
Ocean Dry Bulk, LLC	50	%	—
TECO Guatemala
Empresa Eléctrica de Guatemala, S.A. (EEGSA)	24	%	24	%
Central Generadora Electrica San José, Limitada (San José or CGE)(2)	100		—
Tampa Centro Americana de Electricidad, Limitada (Alborada or TCAE)(2)	96		—
Hamakua Energy Partners, L.P. (3)	—		50
Hamakua Land Partnership, LLP(3)	—		50
Other unregulated
US Propane, LLC (4)	—		38	%
TECO AGC, Ltd. (5)(7)	—		50
Litestream Technologies, LLC (6)	36		36
Hernando Oaks, LLC (7)	—		50
Brandon Properties Partners, Ltd. (8)	—		50
Walden Woods Business Center, Ltd.	50		50
TECO Capital Funding LLC I(9)	100		—
TECO Capital Funding LLC II(9)	100		—

(1) In August 2004, a TWG-Merchant subsidiary completed the sale of its 50% indirect interest in TIE (the holding company for the Odessa and Guadalupe project entities). SeeNote 16 for additional information about this sale.

(2) As of Jan. 1, 2004, in accordance with the interpretation and application of the consolidation guidance established in FIN 46R to long-term power purchase agreements, TECO Energy can no longer consolidate CGE or TCAE, the project companies for the San José and Alborada power plants, respectively, in Guatemala. The percent ownership is unchanged from Dec. 31, 2003. SeeNote 2 for additional details.

(3) SeeNote 16 for information about the sale in July 2004 of TECO Energy’s indirect interest in Hamakua.

(4) The sale of U.S. Propane, LLC assets was completed in the second quarter of 2004 (seeNote 16).

(5) The sale of TECO AGC, Ltd. assets was completed in November 2004.

(6) During the second quarter of 2004, the assets of Litestream Technologies, LLC were sold in bankruptcy. The company still indirectly owned a 36% interest in Litestream Technologies, LLC as of Dec. 31, 2004.

(7) As of Jan. 1, 2004, in accordance with FIN 46R, the company determined that it is the primary beneficiary of this entity. As a result, this entity is included in the consolidated financial statements of the company as a fully consolidated entity with a significant minority interest. The percent ownership is unchanged from Dec. 31, 2003. SeeNote 2 for additional details.

(8) Brandon Properties was dissolved in 2004.

(9) As of Jan. 1, 2004, in accordance with the interpretation and application of the consolidation guidance established in FIN 46R, TECO Energy can no longer consolidate Capital Funding I & II. SeeNote 7 andNote 2 for additional details. The percent ownership is unchanged from Dec. 31, 2003.

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to the provisions of FASB statement No. 71,Accounting for the Effects of Certain Types of Regulation (seeNote 3 for additional details).

Deferred Income Taxes

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

Investment Tax Credits

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

Revenue Recognition

TECO Energy recognizes revenues consistent with the Securities and Exchange Commission’s Staff Accounting Bulletin (SAB) 104,Revenue Recognition in Financial Statements. The interpretive criteria outlined in SAB 104 are that 1) there is persuasive evidence that an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the fee is fixed and determinable; and 4) collectibility is reasonably assured. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer. Revenues for any financial or hedge transactions that do not result in physical delivery are reported on a net basis.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by FERC. SeeNote 3 for a discussion of significant regulatory matters and the applicability of Financial Accounting Standard No. (FAS) 71,Accounting for the Effects of Certain Types of Regulation, to the company.

Revenues for certain transportation services at TECO Transport are recognized using the percentage of completion method, which includes estimates of the distance traveled and/or the time elapsed, compared to the total estimated contract.

Revenues and Fuel Costs

Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses. SeeNote 3.

As of Dec. 31, 2004 and 2003, unbilled revenues of $46.3 million and $45.7 million, respectively, are included in the “Receivables” line item on the balance sheet.

Purchased Power

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. As a result of the sale of HPP in October 2003 (seeNote 16), power purchases from HPP, subsequent to the sale, are reflected as non-affiliate purchases by Tampa Electric. Tampa Electric’s long-term power purchase agreement from HPP was not affected by the sale of HPP. Under the existing purchase power agreement, which has been approved by the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission (FPSC), Tampa Electric has full entitlement to the output of the CT2B unit at all times and full entitlement to the output of the remaining units at the Hardee power station at all times except when Seminole Electric Cooperative has entitlement due to outages and/or durations on a specified portion of its generating units. Tampa Electric purchased power from non-TECO Energy affiliates, including purchases from HPP, at a cost of $172.3 million, $234.9 million and $253.7 million, respectively, for the years ended Dec. 31, 2004, 2003 and 2002. The associated revenue at HPP from power sold to Tampa Electric of $50.1 million and $51.4 million for 2003 and 2002, respectively, is offset against “Regulated operations — Purchased power” in the income statement. The purchased power costs at Tampa Electric are recoverable through an FPSC-approved cost recovery clause.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TECO Coal and TECO Transport incur most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.

The regulated utilities are allowed to recover certain costs incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. These amounts totaled $83.8 million, $77.7 million and $73.8 million for the years ended Dec. 31, 2004, 2003 and 2002, respectively. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income.” For the years ended Dec. 31, 2004, 2003 and 2002, these totaled $83.6 million, $77.5 million and $73.7 million, respectively.

Asset Impairments

Effective Jan. 1, 2002, TECO Energy and its subsidiaries adopted FAS 144,Accounting for the Impairment or Disposal of Long-Lived Assets, which superseded FAS 121,Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a component of a business.

In accordance with FAS 144, the company assesses whether there has been an impairment of its long-lived assets and certain intangibles held and used by the company when such impairment indicators exist. Indicators of impairment existed for certain asset groups, triggering a requirement to ascertain the recoverability of these assets using undiscounted cash flows before interest expense. SeeNote 18 for specific details regarding the results of these assessments.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued post-retirement benefit liability, the pension liability, incurred but not reported medical and general liability claims, and deferred gains on sale-lease back transactions involving marine assets.

Stock-Based Compensation

TECO Energy has adopted the disclosure-only provisions of FAS 123,Accounting for Stock-Based Compensation, but applies Accounting Principles Board Opinion No. (APB) 25,Accounting for Stock Issued to Employees, and related interpretations in accounting for its stock-based compensation plans. Effective Jan. 1, 2003, the company adopted FAS 148,Accounting for Stock-Based Compensation–Transition and Disclosure, an amendment of FASB Statement No. 123. This standard amends FAS 123 to provide alternative methods of transition for companies that voluntarily change to the fair value-based method of accounting for stock-based employee compensation. It also requires prominent disclosure about the effects on reported net income of the company’s accounting policy decisions with respect to stock-based employee compensation in both annual and interim financial statements.

Stock options are granted with an option price greater than or equal to the fair value on the grant date, therefore no compensation expense has been recognized for stock options granted under the Equity Plans and Director Equity Plans (seeNote 9 for a description of the plans). If the company had elected to recognize compensation expense for stock options based on the fair value at grant date, consistent with the method prescribed by FAS 123, net income and earnings per share would have been reduced to the pro forma amounts as follows. These pro forma amounts were determined using the Black-Scholes valuation model with weighted average assumptions set forth below:

Pro Forma Stock-Based Compensation Expense

(millions, except per share amounts) For the years ended Dec. 31,	2004			2003			2002
Net (loss) income from continuing operations
As reported	$	(355.5	)	$	100.7			265.4
Add: Unearned compensation expense(1)		3.2			1.0			1.0
Less: Pro forma expense(2)		7.1			3.7			6.1
Pro forma	$	(359.4	)	$	98.0		$	260.3
Net (loss) income
As reported	$	(552.0	)	$	(909.4	)	$	330.1
Add: Unearned compensation expense(1)		3.2			1.0			1.0
Less: Pro forma expense(2)		7.1			3.7			6.1
Pro forma	$	(555.9	)	$	(912.1	)	$	325.0
Net (loss) income from continuing operations — EPS, basic
As reported	$	(1.85	)	$	0.56		$	1.73
Pro forma	$	(1.87	)	$	0.55		$	1.70
Net (loss) income from continuing operations — EPS, diluted
As reported	$	(1.85	)	$	0.56		$	1.73
Pro forma	$	(1.87	)	$	0.55		$	1.70
Net (loss) income — EPS, basic
As reported	$	(2.87	)	$	(5.05	)	$	2.15
Pro forma	$	(2.89	)	$	(5.07	)	$	2.12
Net (loss) income — EPS, diluted
As reported	$	(2.87	)	$	(5.04	)	$	2.15
Pro forma	$	(2.89	)	$	(5.06	)	$	2.12
Assumptions
Risk-free interest rate		4.04	%		3.52	%		5.09	%
Expected lives (in years)		7			7			6
Expected stock volatility		34.09	%		32.68	%		25.92	%
Dividend yield		5.67	%		6.87	%		5.47	%

(1) Unearned compensation expense reflects the compensation expense of restricted stock awards, after-tax.

(2) Compensation expense for stock options determined using the fair-value based method, after tax, plus compensation expense associated with restricted stock awards, after tax.

Restrictions on Dividend Payments and Transfer of Assets

Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends on TECO Energy’s common stock are dividends and other distributions from its operating companies. TECO Energy’s $380 million note indenture contains a covenant that requires the company to achieve certain interest coverage levels in order to pay dividends. TECO Energy’s credit facility contains a covenant that could limit the payment of dividends exceeding $50 million in any quarter under certain circumstances. In March 2004 Tampa Electric repaid $75 million of 7.75% first mortgage bonds issued under an indenture that included a limitation on dividends covenant. This covenant is no longer operative since there are no bonds outstanding under the indenture. Certain long-term debt at PGS contains restrictions that limit the payment of dividends and distributions on the common stock of Tampa Electric. Tampa Electric’s $125 million credit facility, which included a covenant limiting cumulative distributions and outstanding affiliate loans, was amended in 2004 resulting in the elimination of this covenant.

In addition, TECO Diversified, Inc., a wholly-owned subsidiary of TECO Energy and the holding company for TECO Transport, TECO Coal and TECO Solutions, has a guarantee related to a coal supply agreement that limits the payment of dividends to its common shareholder, TECO Energy, but does not limit loans or advances.

SeeNotes 6, 7 and12 for a more detailed description of significant financial covenants.

TECO Energy holds the right to defer payments on its subordinated notes issued in connection with the issuance of trust preferred securities by TECO Capital Trust I and TECO Capital Trust II. Should the company exercise this right, it would be prohibited from paying cash dividends on its common stock until the unpaid distributions on the subordinated notes are made. TECO Energy has not exercised that right.

Foreign Operations

The functional currency of the company’s foreign investments is primarily the U.S. dollar. Transactions in the local currency are re-measured to the U.S. dollar for financial reporting purposes. The aggregate re-measurement gains or losses included in net income in 2004, 2003, and 2002 were not significant. The foreign investments are generally protected from any significant currency gains or losses by the terms of the power sales agreements and other related contracts, in which payments are defined in U.S. dollars.

Reclassifications

Certain prior year amounts were reclassified to conform to the current year presentation. Results for all prior periods have been reclassified from continuing operations to discontinued operations as appropriate for each of the entities as discussed inNote 21.

2. New Accounting Pronouncements

Gains and Losses on Energy Trading Contracts

On Oct. 25, 2002, the Emerging Issues Task Force released EITF 02-3,Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, which 1) precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to FAS 133, 2) requires that gains and losses on all derivative instruments within the scope of FAS 133 be presented on a net basis in the income statement if held for trading purposes, and 3) limits the circumstances in which a reporting entity may recognize a “day one” gain or loss on a derivative contract. The measurement provisions of the issue are effective for all fiscal periods beginning after Dec. 15, 2002. The net presentation provisions are effective for all financial statements issued after Dec. 15, 2002. The adoption of the measurement provisions on Jan. 1, 2003 did not have a material impact. SeeNote 21 for additional details of amounts presented on a net basis.

Consolidation of Variable Interest Entities

The equity method of accounting is generally used to account for significant investments in arrangements in which we or our subsidiary companies do not have a majority ownership interest or exercise control. A new approach for determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as VIEs was developed and later revised under FIN 46 (FIN 46R),Consolidation of Variable Interest Entities, an interpretation of ARB No. 51.

A legal entity is considered a VIE, with some exemptions if specific criteria are met, if it does not have sufficient equity at risk to finance its own activities without relying on financial support from other parties. Additional criteria must be applied to determine if this condition is met or if the equity holders, as a group, lack any one of three stipulated characteristics of a controlling financial interest. If the legal entity is a VIE, then the reporting entity determined to be the primary beneficiary of the VIE must consolidate it. Even if a reporting entity is not obligated to consolidate a VIE, then certain disclosures must be made about the VIE if the reporting entity has a significant variable interest.

TECO Energy adopted the provisions of FIN 46 as of Oct. 1, 2003 with no material impact. As of Jan. 1, 2004, FIN 46R was adopted for the remaining VIEs as described below.

The company formed TCAE to own and construct the Alborada Power Station in Guatemala in 1995. The company formed CGE to own and commence construction of the San José Power Station in Guatemala in 1998. The San José Power Station was completed in 2000. Both projects obtained a long-term power purchase agreement (PPA) with EEGSA, a distribution utility in Guatemala. The terms of the two separate PPAs include EEGSA’s right to the full capacity of the plants for 15 years, U.S. dollar based capacity payments, certain terms for providing fuel and certain other terms including the right to extend the Alborada and San José contracts. Management believes that EEGSA is the primary beneficiary of the variable interests in TCAE and CGE due to the terms of the PPA. Accordingly, both entities were deconsolidated as of Jan. 1, 2004. The TCAE deconsolidation resulted in the initial removal of $25 million of debt and $15.1 million of net assets from the balance sheet. The San José deconsolidation resulted in the initial removal of $65.5 million of debt and $106.6 million of net assets from the balance sheet. The results of operations for the two projects are classified as “Income from Equity Investments” in the Consolidated Statements of Income since the date of deconsolidation.

TECO Funding I, LLC and TECO Funding II, LLC are limited liability, wholly-owned subsidiaries of TECO Energy. These funding companies sold preferred securities to Capital Trust I and Capital Trust II (seeNote 7 for additional details of the activities of the trusts). The funding companies used those proceeds to purchase junior subordinated notes from TECO Energy. The funding companies are considered VIEs in accordance with FIN 46R. Since management does not believe the company has any material exposure to losses as a result of its involvement with TECO Funding I and II, these entities were deconsolidated as of Jan. 1, 2004 reflecting that the company is not the primary beneficiary of the funding companies. The Funding companies are presented as equity investments in the balance sheet. The impact of the deconsolidation was an increase in liabilities of $20.2 million and a corresponding increase in assets.

Pike Letcher Synfuel, LLC was established as part of the Apr. 1, 2003, sale of TECO Coal’s synthetic fuel production facilities. TECO Energy’s maximum loss exposure in this entity is its equity investment of approximately $10.9 million and losses related to the production costs for the future production of synthetic fuel, in the event that such production creates Section 29 non-conventional fuel tax credits in excess of TECO Energy’s or the other buyers’ capacity to generate sufficient taxable income to use such credits. Management believes that the company is the primary beneficiary of this VIE and continues to consolidate the entity under the guidance of FIN 46R.

TECO Transport entered into two separate sale leaseback transactions for certain vessels which were recognized as sales in December 2001 and December 2002, and are currently recognized as operating leases for use of the assets. The sale leaseback transactions were entered into with separate third parties that the company believes meet the definition of a VIE. TECO Transport currently leases two ocean going tugboats, four ocean going barges, five river towboats and 49 river barges through these two trusts. The estimated maximum loss exposure faced by TECO Transport is the incremental cost of obtaining suitable equipment to meet the company’s contractual shipping obligations. In accordance with the guidance of FIN 46R, management has concluded that the company is not the primary beneficiary of the lessor trusts and continues to report only the impacts of the operating leases and any other required cash contributions.

TECO Properties formed a limited liability company with a project developer which meets the definition of a VIE. Hernando Oaks, LLC was formed by TECO Properties with the Pensacola Group to buy and develop 627 acres of land in Hernando County, Florida into a residential golf community comprised of an 18 hole golf course and 975 single family lots for sale to homebuilders. The company has provided subordinated financial support in the form of a guarantee on behalf of the limited liability company and determined that it is the primary beneficiary of Hernando Oaks. The company consolidated Hernando Oaks, LLC as of Jan. 1, 2004, resulting in an increase in assets of $18.5 million and a corresponding increase in liabilities.

A subsidiary of TECO Solutions formed a partnership to construct, own and operate a water cooling plant to produce and distribute chilled water to customers via a local distribution loop primarily for use in air conditioning systems. The partnership, TECO AGC, Ltd., meets the definition of a VIE. The company is the primary beneficiary, in accordance with FIN 46R, due to subordinated financing of $3.3 million provided to the partnership as of Dec. 31, 2003, in addition to the company’s equity investment. This note receivable from the partnership is collateralized by the assets in the partnership. The company consolidated TECO AGC, Ltd. as of Jan. 1, 2004 with no material increase in assets or liabilities.

In 1992, a subsidiary of the company, Hardee Power Partners, Ltd. (HPP) commenced construction of the Hardee Power Station in central Florida. HPP obtained dual 20-year PPAs with Tampa Electric and another Florida utility company to provide peaking capacity. The company sold its interest in HPP to an affiliate of Invenergy LLC and GTCR Golder Rauner LLC in 2003. Under FIN 46R, the company is required to make an exhaustive effort to obtain sufficient information to determine if HPP is a VIE and which holder of the variable interests is the primary beneficiary. The new owners of HPP are not willing to provide the information necessary to make these determinations and have no obligation to do so. The information is not available publicly. As a result, the company is unable to determine if HPP is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. The maximum exposure for the company is the ability to purchase electricity under terms of the PPA with HPP at rates unfavorable to the wholesale market. For a description and measure of the purchases of electricity under the HPP PPA, seeNote 1 –Purchased Power.

Amendment to Derivatives Accounting

In April 2003, the FASB issued FAS 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which clarifies the definition of a derivative and modifies, as necessary, FAS 133 to reflect certain decisions made by the FASB as part of the Derivatives Implementation Group (DIG) process. The majority of the guidance was already effective and previously applied by the company in the course of the adoption of FAS 133.

In particular, FAS 149 incorporates the conclusions previously reached in 2001 under DIG Issue C10,Can Option Contracts and Forward Contracts with Optionality Features Qualify for the Normal Purchases and Normal Sales Exception?, and DIG Issue C15,Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity. In limited circumstances when the criteria are met and documented, TECO Energy designates option-type and forward contracts in electricity as a normal purchase or normal sale (NPNS) exception to FAS 133. A contract designated and documented as qualifying for the NPNS exception is not subject to the measurement and recognition requirements of FAS 133. The incorporation of the conclusions reached under DIG Issues C10 and C15 into the standard did not and will not have a material impact on the consolidated financial statements of TECO Energy.

FAS 149 establishes multiple effective dates based on the source of the guidance. For all DIG Issues previously cleared by the FASB and not modified under FAS 149, the effective date of the issue remains the same. For all other aspects of the standard, the guidance is effective for all contracts entered into or modified after Jun. 30, 2003. The adoption of the additional guidance in FAS 149 did not have a material impact on the consolidated financial statements.

Financial Instruments with Characteristics of both Liabilities and Equity

In May 2003, the FASB issued FAS 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which requires that an issuer classify certain financial instruments as a liability or an asset. Previously, many financial instruments with characteristics of both liabilities and equity were classified as equity. Financial instruments subject to FAS 150 include financial instruments with any of the following features:

• An unconditional redemption obligation at a specified or determinable date, or upon an event that is certain to occur;

• An obligation to repurchase shares, or indexed to such an obligation, and may require physical share or net cash settlement;

• An unconditional, or for new issuances conditional, obligation that may be settled by issuing a variable number of equity shares if either (a) a fixed monetary amount is known at inception, (b) the variability is indexed to something other than the fair value of the issuer’s equity shares, or (c) the variability moves inversely to changes in the fair value of the issuer’s shares.

The standard requires that all such instruments be classified as a liability, or an asset in certain circumstances, and initially measured at fair value. Forward contracts that require a fixed physical share settlement and mandatorily redeemable financial instruments must be subsequently re-measured at fair value on each reporting date.

This standard is effective for all financial instruments entered into or modified after May 31, 2003, and for all other financial instruments, at the beginning of the first interim period beginning after Jun. 15, 2003. SeeNote 7 for a discussion of the impact of the adoption of this standard on Jul. 1, 2003.

Reporting Discontinued Operations

Emerging Issues Task Force (EITF) Issue No. 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations. The company has adopted the guidance provided by the EITF as related to assessing the actual or projected direct and indirect cash flows of a disposal component to assess the extent or lack of continuing involvement. As a result of this assessment, the sale of Frontera and the expected sale of BCH will be reported as “Assets and Liabilities Held for Sale” and the results for both disposal components are reported as “Discontinued Operations”.

Stock-Based Compensation

FASB Statement No. 123 (revised 2004),Share-Based Payment, will become effective for periods after Jun. 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 1 to the Consolidated Financial Statements, which includes proforma information to assess the impact of implementing the revised statement.)

Inventory Costs

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 becomes effective for periods beginning after Jun. 15, 2005 and is not expected to materially impact the company.

Nonmonetary Assets

FASB Statement No. 153,Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, becomes effective for periods beginning after Jun. 15, 2005 and is not expected to materially impact the company.

3. Regulatory

As discussed inNote 1, Tampa Electric’s and PGS’ retail business are regulated by the FPSC.

Base Rate – Tampa Electric

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 maintaining earnings within its allowed ROE range for the foreseeable future.

Tampa Electric has not sought a base rate increase to recover significant plant investment, including the Bayside Power Station, which entered service in 2003 and 2004.

Cost Recovery – Tampa Electric

2004 Proceedings

In September 2004, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery rates 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 underestimated 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 Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment required Big Bend Units 1 — 3 Pre-SCR projects (seeNote 12 for additional details regarding projected environmental expenditures). 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 described below (SeeNote 13). The 2004 costs associated with this disallowance were recognized in 2004.

As part of the regulatory process, it is reasonably likely that third parties may intervene on similar matters in the future. The company is unable to predict the timing, nature or impact of such future actions.

Base Rate – PGS

As a result of a base rate proceeding, effective Jan. 16, 2003 PGS’ allowable ROE range is 10.25% to 12.25% with an 11.25% midpoint. PGS expects to continue earning within its allowed ROE range for the foreseeable future.

Cost Recovery – PGS

In November 2004, the FPSC approved the annual cap on rates under PGS’ Purchased Gas Adjustment (PGA) cap factor for the period January 2005 through December 2005. 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.

Other Items

Regional Transmission Organization (RTO)

In October 2002, the RTO process involving the proposed formation of GridFlorida, LLC, as initiated in response to the Federal Energy Regulatory Commission’s (FERC’s) continuing efforts to affect open access to transmission facilities in large regional markets, was delayed 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 investor-owned electric utilities (IOUs) and the approval of GridFlorida would result in such a relinquishment. Oral arguments occurred in May 2003, and the Florida Supreme Court dismissed the OPC appeal citing that it was premature because certain portions of the FPSC GridFlorida order were not final.

In September 2003, a joint meeting of the FERC and FPSC took place to discuss wholesale markets and RTO issues related to GridFlorida and, in particular, federal/state interactions. During 2004, deliberations by the FPSC were put on hold 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 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 first quarter of 2005, the study results will be presented to the FPSC. The FPSC is then expected to set the remaining items for hearing and establish a hearing schedule.

Storm Damage Cost Recovery

Following Hurricane Andrew in 1992, Florida’s IOUs were unable to obtain transmission and distribution insurance coverage in the event of 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 year-end, which exceeded the storm damage reserve by $28 million. These excess costs over the reserve amounts were charged against the reserve and are reflected as a regulatory asset at Dec. 31, 2004. The storm costs 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 other Florida public utilities’ proceedings before the FPSC.

Coal Transportation Contract

In September 2004, the FPSC voted to disallow certain costs that Tampa Electric can recover from its customers for waterborne fuel transportation services under a contract with TECO Transport (seeNote 13 andNote 23 for additional details).

Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the FERC. These policies conform with GAAP in all material respects.

Tampa Electric and PGS apply the accounting treatment permitted by FAS 71,Accounting for the Effects of Certain Types of Regulation. Areas of applicability include deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel; purchased power, conservation and environmental costs; and deferral of costs as regulatory assets, when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Dec. 31, 2004 and 2003 are presented in the following table:

Regulatory Assets and Liabilities

(millions) Dec. 31,	2004		2003
Regulatory assets:
Regulatory tax asset(1)	$	57.6	$	63.3
Other:
Cost recover clauses		48.2		59.7
Coal contract buy-out(2)		—		2.7
Deferred bond refinancing costs(3)		32.5		32.2
Environmental remediation		16.9		20.7
Competitive rate adjustment		6.1		5.3
Transmission and distribution storm reserve		28.0		—
Other		11.6		4.4
		143.3		125.0
Total regulatory assets	$	200.9	$	188.3
Regulatory liabilities:
Regulatory tax liability(1)	$	29.5	$	29.9
Other:
Deferred allowance auction credits		2.3		1.9
Recovery clause related		8.7		—
Environmental remediation		16.9		20.7
Transmission and distribution storm reserve		—		40.0
Deferred gain on property sales		1.7		1.9
Accumulated reserve – cost of removal		479.9		462.2
Other		—		3.6
		509.5		530.3
Total regulatory liabilities	$	539.0	$	560.2

(1) Related to plant life. Includes $14.6 million and $17.0 million of excess deferred taxes as of Dec. 31, 2004 and Dec. 31, 2003, respectively.

(2) Amortized over a 10-year period ending December 2004.

(3) Amortized over the term of the related debt instrument.

4. Income Tax Expense

Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)	Federal			Foreign			State			Total
2004
Continuing operations
Current payable	$	(7.6	)	$	(1.1	)	$	10.6		$	1.9
Deferred		(193.2	)		0.3			(51.2	)		(244.1	)
Amortization of investment tax credits		(2.9	)		—			—			(2.9	)
Income tax (benefit) from continuing operations		(203.7	)		(0.8	)		(40.6	)		(245.1	)
Discontinued operations
Current payable		8.3			—			5.6			13.9
Deferred		(110.6	)		—			(0.8	)		(111.4	)
Income tax (benefit) from discontinued operations		(102.3	)		—			4.8			(97.5	)
Total income tax (benefit)	$	(306.0	)	$	(0.8	)	$	(35.8	)	$	(342.6	)
2003
Continuing operations
Current payable	$	59.6		$	2.2		$	7.3		$	69.1
Deferred		(123.2	)		5.3			(14.4	)		(132.3	)
Amortization of investment tax credits		(4.7	)		—			—			(4.7	)
Income tax (benefit) expense from continuing operations		(68.3	)		7.5			(7.1	)		(67.9	)
Discontinued operations
Current payable		(1.6	)		—			7.0			5.4
Deferred		(539.5	)		—			(37.4	)		(576.9	)
Income tax (benefit) from discontinued operations		(541.1	)		—			(30.4	)		(571.5	)
Total income tax (benefit) expense	$	(609.4	)	$	7.5		$	(37.5	)	$	(639.4	)
2002
Continuing operations
Current payable	$	12.6		$	1.0		$	10.4		$	24.0
Deferred		(72.4	)		—			(5.6	)		(78.0	)
Amortization of investment tax credits		(4.8	)		—			—			(4.8	)
Income tax (benefit) expense from continuing operations		(64.6	)		1.0			4.8			(58.8	)
Discontinued operations
Current payable		27.4			—			5.6			33.0
Deferred		(16.8	)		—			(1.7	)		(18.5	)
Income tax expense from discontinued operations		10.6			—			3.9			14.5
Total income tax (benefit) expense	$	(54.0	)	$	1.0		$	8.7		$	(44.3	)

TECO Energy uses the liability method to determine deferred income taxes. Under the liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the 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 management determines 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.

Based primarily on the reversal of deferred income tax liabilities and 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.

The principal components of the company’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

Deferred Income Tax Assets and Liabilities

(millions) Dec. 31,	2004			2003
Deferred income tax assets(1)
Property related	$	780.3		$	517.3
Alternative minimum tax credit forward		208.5			224.6
Investment in partnership		80.8			56.4
Goodwill write-down		16.0			107.5
Net operating loss carryforward		158.8			—
Other		134.7			145.7
Total deferred income tax assets	$	1,379.1		$	1,051.5
Deferred income tax liabilities(1)
Property related	$	(557.6	)	$	(521.8	)
Basis difference in oil and gas properties		—			4.4
Other		53.5			19.4
Total deferred income tax liabilities	$	(504.1	)	$	(498.0	)
Net deferred tax assets	$	875.0		$	553.5

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

Included in the “Property related” component of the deferred tax asset, as of Dec. 31, 2004, is the impact of The asset impairments discussed inNotes 18and21.

At Dec. 31, 2004 the company has unused federal and state (Florida) net operating losses of approximately $413.0 million and $259.0 million, respectively, expiring in 2024. In addition, the company has available alternative minimum tax credit carryforwards for tax purposes of approximately $208 million which may be used indefinitely to reduce federal income taxes.

Effective Income Tax Rate

(millions) For the years ended Dec. 31,	2004			2003			2002
Net (loss) income from continuing operations before minority interest	$	(435.0	)	$	51.9		$	265.4
Plus: minority interest		79.5			48.8			—
Net (loss) income from continuing operations		(355.5	)		100.7			265.4
Total income tax provision (benefit)		(245.1	)		(67.9	)		(58.8	)
(Loss) income from continuing operations before income taxes		(600.6	)		32.8			206.6
Income taxes on above at federal statutory rate of 35%		(210.2	)		11.5			72.3
Increase (decrease) due to
State income tax, net of federal income tax		(26.3	)		(4.6	)		3.2
Foreign income taxes		(0.8	)		7.5			1.0
Amortization of investment tax credits		(2.9	)		(4.7	)		(4.8	)
Permanent reinvestment – foreign income		(10.5	)		(12.3	)		(8.1	)
Non-conventional fuels tax credit		—			(66.0	)		(107.3	)
AFUDC equity		(0.3	)		(6.9	)		(8.7	)
Dividend income		14.6			—			—
Other		(8.7	)		7.6			(6.4	)
Total income tax provision from continuing operations	$	(245.1	)	$	(67.9	)	$	(58.8	)
Provision for income taxes as a percent of income from continuing operations, before income taxes		40.8	%		(207.0	%) (1)		(28.5	%)

(1) This calculation is not necessarily meaningful as a result of the interaction between tax losses and tax credits for the period.

We have experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included the recognition of non-conventional fuel credits, permanent reinvestment of foreign income under Accounting Principles Board Opinion No. 23,Accounting for Taxes — Special Areas, (APB 23), repatriation of foreign source income to the United States resulting in the discontinuance of the permanent reinvestment criteria for certain investments under APB 23, Guatemalan tax reform effective Jul. 1, 2004, and equity treatment of variable interest entities as required under FIN 46R.

At Dec. 31, 2004, the portion of cumulative undistributed earnings from our investments in EEGSA was approximately $42 million. Since these earnings have been and are intended to be indefinitely reinvested in foreign operations, no provision has been made for U.S. taxes or foreign withholding taxes that may be applicable upon an actual or deemed repatriation.

The consolidated entity recorded a net state benefit in 2004 to reflect state deferred balances at the expected realizable rate which is lower than in prior years and to record estimated state benefits from impairments.

The provision for income taxes as a percent of income from discontinued operations was 33.2%, 36.2% and 18.4%, respectively, in 2004, 2003, and 2002. The total effective income tax rate differs from the federal statutory rate due to state income tax, net of federal income tax, the non-conventional fuels tax credit and other miscellaneous items. The actual cash paid for income taxes as primarily required for the alternative minimum tax, state income taxes and payments for prior year audits in 2004, 2003 and 2002 was $22.4 million, $58.8 million and $71.9 million, respectively.

5. Employee Postretirement Benefits

Pension Benefits

TECO Energy has a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings. The company’s policy is to fund the plan based on the amount determined by the company’s actuaries within the guidelines set by ERISA for the minimum annual contribution. In 2004, the company made a contribution of $14.2 million to the plan. In 2005, the company expects to make a contribution of about $13.6 million.

Amounts disclosed for pension benefits also include the unfunded obligations for the supplemental executive retirement plans. These are non-qualified, non-contributory defined benefit retirement plans available to certain members of senior management. In 2004, the company made a contribution of $9.8 million to these plans. In 2005, the company expects to make a contribution of about $4.6 million to these plans.

TECO Energy reported other comprehensive income of $7.2 million in 2004 and other comprehensive losses of $43.9 million and $4.4 million in 2003 and 2002, respectively, related to adjustments to the minimum pension liability associated with these pension plans (SeeNote 10).

The asset allocation for the company’s pension plan as of Sep. 30, 2004 and 2003, the measurement dates for the company’s post-retirement benefit plans, and the target allocation for 2005, by asset category, follows:

Asset Allocation

Asset category	Target Allocation for 2005	Percentage of Plan Assets at Sep. 30,
		2004		2003
Equities	55% – 60%	60	%	57	%
Fixed income	40% – 45%	40	%	43	%
Total		100	%	100	%

The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns over the long term. The target equities/fixed income mix is designed to meet investment objectives. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

The assumptions for the expected return on plan assets were developed based on an analysis of historical market returns, the plan’s past experience and current market conditions.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. The company contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on age and service. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on a service schedule. In 2005, the company expects to make a contribution of about $9.8 million to this program. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

At Dec. 31, 2004 and 2003, TECO Energy had the following long-term debt outstanding:

Long-term Debt (millions) Dec. 31,		Due	2004			2003
TECO Energy	Notes:
	7.2% (effective rate of 7.38%)(1)	2011	$	600.0		$	600.0
	6.125% (effective rate of 6.31%)(1)	2007		300.0			300.0
	7% (effective rate of 7.08%)(1)	2012		400.0			400.0
	10.5% (effective rate of 12.37%)(1)(2)	2007		380.0			380.0
	7.5% (effective rate of 7.85%)(1)(2)	2010		300.0			300.0
	Junior subordinated notes:
	8.50%(3)	2041		206.2			—
	5.93%(4)	2007		71.4			—
	Preferred Securities:
	8.5%(14)	2041		—			200.0
	9.5%(14)	2007		—			449.1
				2,257.6			2,629.1
Tampa Electric	First mortgage bonds (issuable in series):
	7.75% (effective rate of 7.96% for 2003)	2022		—			75.0
	Installment contracts payable:(5)
	6.25% Refunding bonds (effective rate of 6.81%)(1)(6)	2034		86.0			86.0
	5.85% Refunding bonds (effective rate of 5.88%)	2030		75.0			75.0
	5.1% Refunding bonds (effective rate of 5.75%)(7)	2013		60.7			60.7
	5.5% Refunding bonds (effective rate of 6.32%)(7)	2023		86.4			86.4
	4% (effective rate of 4.19%)(8)	2025		51.6			51.6
	4% (effective rate of 4.16%)(8)	2018		54.2			54.2
	4.25% (effective rate of 4.44%)(8)	2020		20.0			20.0
	Notes:
	6.875% (effective rate of 6.98%)(1)	2012		210.0			210.0
	6.375% (effective rate of 7.35%)(1)	2012		330.0			330.0
	5.375% (effective rate of 5.59%)(1)	2007		125.0			125.0
	6.25% (effective rate of 6.31%)(1)(2)	2014-2016		250.0			250.0
				1,348.9			1,423.9
Peoples Gas System	Senior Notes:(1)(2)
	10.35%	2005-2007		2.6			3.4
	10.33%	2005-2008		4.0			4.8
	10.3%	2005-2009		5.6			6.4
	9.93%	2005-2010		5.8			6.6
	8%	2005-2012		21.2			23.3
	Notes:
	6.875% (effective rate of 6.98%)(1)	2012		40.0			40.0
	6.375% (effective rate of 7.35%)(1)	2012		70.0			70.0
	5.375% (effective rate of 5.59%)(1)	2007		25.0			25.0
				174.2			179.5
TWG-Merchant	Non-recourse secured facility notes, variable rate:
	8.13% for 2004 and 3.00% for 2003(9)(10)(11)	2004		1,395.0			1,395.0
	Non-recourse financing facility — Union County: 7.5%(5) (10)	2005-2021		676.1			692.3
				2,071.1			2,087.3
TECO Guatemala	Non-recourse secured facility notes, variable rate:
	4.38% for 2003(9)	2004		—			36.7
	6.63% for 2004 and 2003(9)	2005-2009		4.4			16.0
	4.75% for 2003(9)	2004		—			14.0
	Non-recourse secured facility notes:
	10.1%	2004		—			15.3
	9.629%	2004		—			19.1
				4.4			101.1
Other	Dock and wharf bonds, 5%(5)	2007		110.6			110.6
	Non-recourse mortgage notes, variable rate:
	5.43% for 2004 and 4.45% for 2003(12)	2005		4.1			4.6
	3.95% for 2003 (effective rate of 4.16%)(12)	2004		—			3.0
	4.78% (effective rate of 5.09%)(13)	2005-2006		13.0			—
				127.7			118.2
Unamortized debt (discount), net				(19.2	)		(27.6	)
				5,964.7			6,511.5
Less amount due within one year				13.6			31.6
Less long-term liabilities held for sale(10)				2,071.1			2,087.3
Total long-term debt			$	3,880.0		$	4,392.6

(1) These securities are subject to redemption in whole or in part, at any time, at the option of the company.

(2) These long-term debt agreements contain various restrictive financial covenants (seeNote 12).

(3) These securities may be redeemed in whole or in part, at par by action of the company on or after Dec. 20, 2005.

(4) The rate on these securities was reset from 5.11% (effective rate of 5.85%) to 5.93% on Oct. 15, 2004. These securities, along with the forward purchase contract to purchase the company’s common stock, comprise the mandatorily convertible equity security units of TECO Capital Trust II.

(5) Tax-exempt securities.

(6) Proceeds of these bonds were used to refund bonds with an interest rate of 9.9% in February 1995. For accounting purposes, interest expense has been recorded using a blended rate of 6.52% on the original and refunding bonds, consistent with regulatory treatment.

(7) Proceeds of these bonds were used to refund bonds with interest rates of 5.75%-8%.

(8) The interest rate on these bonds was fixed for a five-year term on Aug. 5, 2002.

(9) Composite year-end interest rate.

(10) This obligation is expected to be transferred in the disposition of the Union and Gila River power plants. As a result, the liability has been reclassified to “Liabilities associated with assets held for sale”. SeeNote 21 andNote 23 for additional details.

(11) These notes were in default as of Dec. 31, 2004. SeeNote 12.

(12) These notes represent 100% of the debt for BT-One, LLC, an 80% owned consolidated affiliate. In total, the company has a $1.0 million guarantee on these notes.

(13) These notes represent 100% of the debt for Hernando Oaks, LLC, a 50% owned consolidated affiliate. In total, the company has a $9.2 million guarantee on these notes.

(14) As a result of the adoption of FIN46R, effective Jan. 1, 2004, the preferred securities are no longer recognized on the Consolidated Balance Sheet.

8. Preferred Stock

Preferred stock of TECO Energy – $1 par

10 million shares authorized, none outstanding.

Preference stock (subordinated preferred stock) of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – $100 par

1.5 million shares authorized, none outstanding.

9. Common Stock

Stock-Based Compensation

In April 2004, the shareholders approved the 2004 Equity Incentive Plan (2004 Plan). The 2004 Plan superseded the 1996 Equity Incentive Plan (1996 Plan), and no additional grants will be made under the 1996 Plan. The rights of the holders of the outstanding options under the 1996 Plan were not affected. The purpose of the 2004 Plan is to attract and retain key employees and consultants of the company, to provide an incentive for them to achieve long-range performance goals and to enable them to participate in the long-term growth of the company. The 2004 Plan amended the 1996 Plan to increase the number of shares of common stock subject to grants by 10,000,000 shares, place various limitations on the types of awards available to be granted, specify a ten-year term for the 2004 Plan and any grants made thereunder and allow awards to consultants of the company. Under the 2004 Plan, the Compensation Committee of the Board of Directors may award stock grants, stock options and / or stock equivalents to officers, key employees and consultants of TECO Energy and its subsidiaries.

The Compensation Committee has discretion to determine the terms and conditions of each award, which may be subject to conditions relating to continued employment, restrictions on transfer or performance criteria.

Under the 2004 Plan and the 1996 Plan (collectively referred to as the “Equity Plans”), 2.4 million, 2.8 million and 1.8 million stock options were granted to employees in 2004, 2003 and 2002, respectively, each with a maximum term of 10 years. The weighted average fair value per share of stock options granted to employees under the Equity Plans in 2004, 2003, and 2002, respectively, was $2.80, $1.79 and $4.90, using the Black-Scholes option pricing model with assumptions as described inNote 1. In addition, 0.3 million, 0.6 million and 0.3 million shares of restricted stock were awarded in 2004, 2003 and 2002, respectively, with weighted average fair values of $13.30, $11.14 and $27.97, respectively.

Compensation expense recognized for stock grants awarded under the 2004 Plan and the 1996 Plan was $5.2 million, $1.6 million and $1.7 million in 2004, 2003 and 2002, respectively. Approximately half of the stock grants awarded in 2004, 2003 and 2002 are performance shares, restricted subject to meeting specified total shareholder return goals, vesting in three years with final payout ranging from zero to 200% of the original grant. Adjustments are made to reflect contingent shares which could be issuable based on current period results. The consolidated balance sheets at Dec. 31, 2004 and 2003 reflected a $(0.5) million and a $(4.7) million liability, respectively, classified as other deferred credits, for these contingent shares. The remaining stock grants are restricted subject to continued employment generally, with the majority of the 2004, 2003 and 2002 stock grants vesting in three years, and the 1997 and 1996 stock grants vesting at normal retirement age.

Stock option transactions during the last three years under the Equity Plans are summarized as follows:

Stock Options – Equity Plans

	Option Shares (thousands)		Weighted Avg. Option Price
Balance at Dec. 31, 2001	5,190		$	24.79
Granted	1,770		$	27.97
Exercised	(487	)	$	20.93
Cancelled	(57	)	$	27.03
Balance at Dec. 31, 2002	6,416		$	25.94
Granted	2,829		$	11.10
Exercised	(14	)	$	11.09
Cancelled	(306	)	$	23.35
Balance at Dec. 31, 2003	8,925		$	21.35
Granted	2,388		$	13.44
Exercised	(512	)	$	11.17
Cancelled	(489	)	$	22.87
Balance at Dec. 31, 2004	10,312		$	19.95
Exercisable at Dec. 31, 2004	741		$	11.09
Available for future grant at Dec. 31, 2004	9,456

As of Dec. 31, 2004, the 10.3 million options outstanding under the Equity Plans are summarized below.

Stock Options Outstanding at Dec. 31, 2004

Option Shares (thousands)	Range of Option Prices	Weighted Avg. Option Price		Weighted Avg. Remaining Contractual Life
4,577	$11.09 — $13.50	$	12.30	9 Years
1,917	$20.75 — $22.48	$	21.27	4 Years
493	$23.55 — $25.97	$	24.09	2 Years
3,325	$27.56 — $31.58	$	29.11	6 Years

In April 1997, the Shareholders approved the 1997 Director Equity Plan (1997 Plan), as an amendment and restatement of the 1991 Director Stock Option Plan (1991 Plan). The 1997 Plan superseded the 1991 Plan, and no additional grants will be made under the 1991 Plan. The rights of the holders of outstanding options under the 1991 Plan will not be affected. The purpose of the 1997 Plan is to attract and retain highly qualified non-employee directors of the company and to encourage them to own shares of TECO Energy common stock. The 1997 Plan is administered by the Board of Directors. The 1997 Plan amended the 1991 Plan to increase the number of shares of common stock subject to grants by 250,000 shares, expanded the types of awards available to be granted and replaced the fixed formula grant by giving the Board discretionary authority to determine the amount and timing of awards under the plan.

Under the 1997 Plan, 5,000, 6,000 and 5,500 stock grants were awarded to directors in 2004, 2003 and 2002, respectively, with weighted average fair values of $13.56, $11.09 and $27.97, respectively. In addition, 35,000, 40,000 and 27,500 stock options were granted to directors in 2004, 2003 and 2002, respectively, each with a maximum term of 10 years. The weighted average fair value per share of stock options granted to directors under the 1997 Plan in 2004, 2003 and 2002, respectively, was $2.90, $1.49 and $4.90, using the Black-Scholes option pricing model with assumptions as described inNote 1. Stock option transactions during the last three years under the 1997 Plan are summarized as follows:

Stock Options — Director Equity Plans

	Option Shares (thousands)		Weighted Avg. Option Price
Balance at Dec. 31, 2001	202		$	24.49
Granted	28		$	27.97
Exercised	(22	)	$	20.95
Cancelled	(2	)	$	27.56
Balance at Dec. 31, 2002	206		$	25.31
Granted	40		$	11.72
Exercised	—		$	—
Cancelled	(10	)	$	23.41
Balance at Dec. 31, 2003	236		$	23.08
Granted	35		$	14.03
Exercised	—		$	—
Cancelled	(8	)	$	19.81
Balance at Dec. 31, 2004	263		$	21.97
Exercisable at Dec. 31, 2004	75		$	12.80
Available for future grant at Dec. 31, 2004	198

As of Dec. 31, 2004, the 263,000 options outstanding under the 1997 Plan with option prices of $11.09 – $31.58, had a weighted average option price of $21.97 and a weighted average remaining contractual life of six years.

Dividend Reinvestment Plan

In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy raised $5.1 million, $8.0 million and $11.2 million of common equity from this plan in 2004, 2003 and 2002, respectively.

Common Stock and Treasury Stock

In June 2002, the company completed a public offering of 15.525 million common shares at a price to the public of $23.00 per share. The sale of these shares resulted in net proceeds to the company of approximately $346.4 million, which were used to repay short-term debt and for general corporate purposes. In October 2002, the company issued 19.385 million common shares at a price to the public of $11.00 per share. The sale of these shares resulted in net proceeds to the company of approximately $206.8 million, which were used to repay short-term debt.

In September 2003, TECO Energy sold 11 million shares of common stock to funds managed by Franklin Advisers, Inc. at a price of $11.76 per share. Net proceeds of approximately $129 million were used to repay short-term indebtedness and for general corporate purposes.

On Aug. 25, 2004, the company completed an early settlement exchange offer of its TECO Capital Trust II Equity Security Units for 10.2 million shares of common stock (seeNote 7 andNote 23).

Shareholder Rights Plan

In accordance with the company’s Shareholder Rights Plan, a Right to purchase one additional share of the company’s common stock at a price of $90 per share is attached to each outstanding share of the company’s common stock. The Rights expire in May 2009, subject to extension. The Rights will become exercisable 10 business days after a person acquires 10% or more of the company’s outstanding common stock or commences a tender offer that would result in such person owning 10% or more of such stock. If any person acquires 10% or more of the outstanding common stock, the rights of holders, other than the acquiring person, become rights to buy shares of common stock of the company (or of the acquiring company if the company is involved in a merger or other business combination and is not the surviving corporation) having a market value of twice the exercise price of each Right.

The company may redeem the Rights at a nominal price per Right until 10 business days after a person acquires 10% or more of the outstanding common stock.

Employee Stock Ownership Plan

Effective Jan. 1, 1990, TECO Energy amended the TECO Energy Group Retirement Savings Plan, a tax-qualified benefit plan available to substantially all employees, to include an employee stock ownership plan (ESOP). During 1990, the ESOP purchased 7 million shares of TECO Energy common stock on the open market for $100 million. The share purchase was financed through a loan from TECO Energy to the ESOP. This loan was at a fixed interest rate of 9.3% and was repaid from dividends on ESOP shares and from TECO Energy’s contributions to the ESOP.

TECO Energy’s contributions to the ESOP were $2.1 million, $21.1 million, and $13.6 million in 2004, 2003 and 2002, respectively. TECO Energy’s annual contribution equals the interest accrued on the loan during the year plus additional principal payments needed to meet the matching allocation requirements under the plan, less dividends received on the ESOP shares. The components of net ESOP expense recognized for the past three years are as follows:

ESOP Expense

(millions) For the years ended Dec. 31,	2004			2003			2002
Interest expense	$	0.3		$	2.6		$	4.3
Compensation expense		8.4			16.0			12.2
Dividends		(4.0	)		(5.3	)		(8.5	)
Net ESOP expense	$	4.7		$	13.3		$	8.0

Compensation expense was determined by the shares allocated method.

At Dec. 31, 2004, the ESOP had no shares remaining to be allocated. Shares were released to provide employees with the company match in accordance with the terms of the TECO Energy Group Retirement Savings Plan and in lieu of dividends on allocated ESOP shares. The dividends received by the ESOP were used to pay debt service on the loan between TECO Energy and the ESOP.

For financial statement purposes, the unallocated shares of TECO Energy stock were reflected as a reduction of common equity, classified as unearned compensation. Dividends on all ESOP shares were recorded as a reduction of retained earnings, as are dividends on all TECO Energy common stock. The tax benefit related to dividends paid to the ESOP for allocated shares is a reduction of income tax expense and was $1.5 million, $1.6 million and $2.0 million for 2004, 2003 and 2002, respectively. The tax benefit related to dividends paid to the ESOP for unallocated shares is an increase in retained earnings and was $0.1 million, $0.4 million and $1.3 million in 2004, 2003 and 2002, respectively. All ESOP shares were considered outstanding for earnings per share computations.

10. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (loss) (OCI) for the years ended Dec. 31, 2004, 2003 and 2002, related to changes in the fair value of cash flow hedges, foreign currency adjustments and adjustments to the minimum pension liability associated with the company’s supplemental executive retirement plan:

Comprehensive Income (Loss) (millions)	Gross			Tax			Net
2004
Unrealized (loss) on cash flow hedges	$	(14.6	)	$	(4.9	)	$	(9.7	)
Less: Loss reclassified to net income(1)		22.8			8.3			14.5
Gain on cash flow hedges		8.2			3.4			4.8
Foreign currency adjustments		—			—			—
Pension adjustments(2)		9.5			2.3			7.2
Total other comprehensive income	$	17.7		$	5.7		$	12.0
2003
Unrealized (loss) on cash flow hedges(1)	$	(31.8	)	$	(10.6	)	$	(21.2	)
Less: Loss reclassified to net income(1)		76.4			27.1			49.3
Gain on cash flow hedges		44.6			16.5			28.1
Foreign currency adjustments		1.2			—			1.2
Pension adjustments(2)		(69.3	)		(25.4	)		(43.9	)
Total other comprehensive (loss)	$	(23.5	)	$	(8.9	)	$	(14.6	)
2002
Unrealized (loss) on cash flow hedges(1)	$	(51.2	)	$	(20.4	)	$	(30.8	)
Less: Loss reclassified to net income		29.0			11.4			17.6
(Loss) on cash flow hedges		(22.2	)		(9.0	)		(13.2	)
Foreign currency adjustments		(1.2	)		—			(1.2	)
Pension adjustments(2)		(7.2	)		(2.8	)		(4.4	)
Total other comprehensive (loss)	$	(30.6	)	$	(11.8	)	$	(18.8	)

(1) Amounts include interest rate swaps designated as cash flow hedges at TPGC, which was consolidated effective Apr. 1, 2003 as a result of the termination of the partnership. Prior to Apr. 1, 2003, only the company’s proportionate share of its equity investee’s comprehensive loss was included. SeeNotes 20 and21 for additional details regarding the OCI balances for cash flow hedges.

(2) SeeNote 5 for additional details regarding pension adjustments.

Accumulated Other Comprehensive Income

(millions) Dec. 31,	2004			2003
Minimum pension liability adjustment(1)	$	(44.3	)	$	(51.5	)
Net unrealized gains (losses) from cash flow hedges(2)		0.5			(4.3	)
Total accumulated other comprehensive income	$	(43.8	)	$	(55.8	)

(1) Net of tax benefit of $27.9 million and $30.2 million, respectively, as of Dec. 31, 2004 and 2003, respectively.

(2) Net of tax benefit of $1.3 million and $4.7 million, respectively, as of Dec. 31, 2004 and 2003, respectively.

11. Earnings Per Share

For the years ended Dec. 31, 2004, 2003 and 2002, stock options for 10.6 million shares, 6.3 million shares and 4.5 million shares, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect. Additionally, 1.9 million, 14.9 million and 14.9 million common shares issuable under the purchase contract associated with the mandatorily convertible equity units were also excluded from the computation of diluted earnings per share for the years ended Dec. 31, 2004, 2003 and 2002, respectively, due to their antidilutive effect.

Earnings Per Share

(millions, except per share amounts) For the years ended Dec. 31,	2004			2003			2002
Numerator
Net (loss) income from continuing operations, basic and diluted	$	(355.5	)	$	100.7		$	265.4
Discontinued operations, net of tax		(196.5	)		(1,005.8	)		64.7
Cumulative effect of a change in accounting principle, net		—			(4.3	)		—
Net (loss) income, basic and diluted	$	(552.0	)	$	(909.4	)	$	330.1
Denominator
Average number of shares outstanding — basic		192.6			179.9			153.2
Plus: Incremental shares for assumed conversions:
Stock options at end of period and contingent performance shares		—			2.8			2.1
Less: Treasury shares which could be purchased		—			(2.5	)		(2.0	)
Average number of shares outstanding — diluted		192.6			180.2			153.3
Earnings per share from continuing operations
Basic	$	(1.85	)	$	0.56		$	1.73
Diluted	$	(1.85	)	$	0.56		$	1.73
Earnings per share from discontinued operations, net
Basic	$	(1.02	)	$	(5.59	)	$	0.42
Diluted	$	(1.02	)	$	(5.58	)	$	0.42
Earnings per share from cumulative effect of change in accounting principle, net
Basic	$	—		$	(0.02	)	$	—
Diluted	$	—		$	(0.02	)	$	—
Earnings per share
Basic	$	(2.87	)	$	(5.05	)	$	2.15
Diluted	$	(2.87	)	$	(5.04	)	$	2.15

12. Commitments and Contingencies

Capital Investments

TECO Energy has made certain commitments in connection with its continuing capital expenditure program. At Dec. 31, 2004, these estimated capital investments total approximately $1.7 billion for the years 2005 through 2009 and are summarized as follows:

Forecasted Capital Investments

As of Dec. 31, 2004 (millions)	2005		2006		2007- 2009		Total 2005-2009
Tampa Electric
Transmission	$	19.2	$	25.1	$	98.6	$	142.9
Distribution		75.4		78.4		235.8		389.6
Generation		56.1		57.5		190.8		304.4
Other		19.5		16.3		43.4		79.2
Environmental		44.3		69.3		285.6		399.2
Tampa Electric Total		214.5		246.6		854.2		1,315.3
Peoples Gas		40.0		40.0		120.0		200.0
TECO Coal		23.7		22.1		54.9		100.7
TECO Transport		19.6		20.2		59.4		99.2
Other		5.0		0.2		0.6		5.8
Total	$	302.8	$	329.1	$	1,089.1	$	1,721.0

For 2005, Tampa Electric’s electric division expects to spend $214 million, consisting of $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 $253 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 (seeNote 1).

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 $43 million in 2005 and $157 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 equipment.

The other unregulated companies expect to invest $5.0 million in 2005 and $0.8 million during 2006 through 2009, mainly for normal renewal and replacement capital.

Legal Contingencies

TM Delmarva Power Arbitration

TM Delmarva Power L.L.C. (TMDP), a TWG subsidiary, had reserved, but not yet paid, the full $49 million, representing the maximum payment obligation for an arbitration award plus accrued interest issued by the arbitration panel in a proceeding brought against TMDP by the non-equity member, NCP of Virginia, L.L.C. (NCP), in the Commonwealth Chesapeake Project (CCC). In August 2004, the company entered into an agreement with NCP and its owners under which TECO Energy and its subsidiary agreed to purchase NCP’s interest in CCC for $30 million in cash plus shares of TECO Energy common stock having a value of $10 million, and NCP released all claims against the company and its subsidiaries. The funds and shares were released from escrow upon receipt of FERC approval on Sep. 30, 2004. The transaction to purchase the remaining interest in CCC from NCP therefore had a positive impact on pretax earnings of approximately $9 million in the third quarter of 2004. (SeeNote 23 for discussion of a subsequent event involving CCC).

Grupo Lawsuit

In March 2001, TWG (under its former name of TECO Power Services Corporation) was served with a lawsuit filed in the Circuit Court for Hillsborough County 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, resulting in only one count remaining. On Oct. 18, 2004, TWG’s motion for summary judgment on the remaining count was granted. The plaintiffs have appealed and the company expects that the appellate court would render a decision by the end of 2005.

On Aug. 30, 2004, a Colombian trade union, Sindicato de Trabajadores de la Electricidad de Colombia, which was to be 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 of $48 million. TECO Energy, Inc. and TWG also were 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 would share in any recovery. The arbitration is in its preliminary stages, and, although the respondents have not been served, the parties’ arbitrators have been selected by the parties.

Other Issues

A number of securities class action lawsuits were filed in August, September and October 2004 against the company and certain current and former officers by purchasers of TECO Energy 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 and remain in the initial pleading stage as of Dec. 31, 2004. On Feb. 1, 2005, the Court entered its order appointing the (i) “TECO Lead Plaintiff Group”, comprised of NECA-IBEW Pension Fund (The Decatur Plan), Monroe County Employees Retirement System, John Marder and Charles Korpak, as the Lead Plaintiff for the Class and (ii) the law firm of Lerach Coughlin Stoia Geller Rudman & Robbins LLP as Lead Counsel. The plaintiffs have 60 days (or until Apr. 4, 2005) to file its consolidated complaint. The defendants will then have 60 days (or as late as Jun. 3, 2005) to file a motion to dismiss and supporting brief, and then the plaintiffs would have 60 days (or as late as Aug. 2, 2005) to file their opposition brief. The motion would then be before the Judge for a decision which could be made based on the papers or, after a hearing if scheduled at the Judge’s discretion. The company intends to defend the litigation vigorously. In addition, in connection with the previously disclosed SEC informal inquiry resulting from a letter from the non-equity member in the CCC raising issues related to the arbitration proceeding involving that project, the SEC has requested additional information primarily relating to the allegations made in these securities class action lawsuits focusing on various merchant plant investments and related matters.

The company cannot predict the ultimate resolution of these matters, including the class action litigation and the Grupo-related proceedings, at this time, and there can be no assurance that any such matters will not have a material adverse impact on TECO Energy’s 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 FAS 5,Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that the ultimate resolution of pending matters will have a material adverse effect on the company’s results of operations or financial condition.

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 accrued 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 party’s 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 creditworthy.

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 costs are recoverable through customer rates established in subsequent base rate proceedings.

Long Term Commitments

TECO Energy has commitments under long-term operating leases, primarily for building space, office equipment and heavy equipment, and marine assets at TECO Transport. On Dec. 30, 2002, TECO Transport completed a sale-leaseback transaction to be accounted for as an operating lease covering one ocean-going tug and barge, five river towboats and 49 river barges. On Dec. 21, 2001, TECO Transport sold three ocean-going barges and one ocean-going tug boat in a sale-leaseback transaction to be accounted for as an operating lease. Both lease terms are 12 years with early buyout options after 5 years.

Total rental expense for these operating leases, included in the Consolidated Statements of Income for the years ended Dec. 31, 2004, 2003 and 2002 was $32.3 million, $28.9 million and $26.0 million, respectively.

The following is a schedule of future minimum lease payments at Dec. 31, 2004 for all operating leases with noncancelable lease terms in excess of one year:

Future Minimum Lease Payments of Operating Leases

Year ended Dec. 31:	Amount (millions)
2005	$	25.2
2006		20.7
2007		17.2
2008		13.0
2009		12.6
Later years		68.3
Total minimum lease payments	$	157.0

In 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the 10-year period beginning Apr. 1, 1995. In each of the years 2004, 2003 and 2002, $2.7 million of buy-out costs were amortized to expense.

Guarantees and Letters of Credit

On Jan. 1, 2003, TECO Energy adopted the prospective initial measurement provisions for certain types of guarantees, in accordance with FASB Interpretation No. (FIN) 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (an interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34). Upon issuance or modification of a guarantee after Jan. 1, 2003, the company must determine if the obligation is subject to either or both of the following:

• Initial recognition and initial measurement of a liability; and/or

• Disclosure of specific details of the guarantee.

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative subject to FAS 133) are likely to be subject to the recognition and measurement, as well as the disclosure provisions, of FIN 45. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2004 are as follows:

Letters of Credit and Guarantees

(millions) Letters of Credit and Guarantees for the Benefit of:	Maturing									Total		Liabilities Recognized at Dec. 31, 2004
	2005		2006		2007- 2009		After 2009
Tampa Electric
Letters of credit	$	—	$	—	$	—	$	2.4		$	2.4	$	—
Guarantees:
Fuel purchase/energy management(1)(2)		—		—		—		20.0			20.0		0.1
		—		—		—		22.4			22.4		0.1
TECO Wholesale Generation-Merchant
Guarantees:
Fuel purchase/energy management(2)		174.9		—		—		—			174.9		5.0
Construction/Investment related		2.0		—		—		—			2.0		—
		176.9		—		—		—			176.9		5.0
TECO Transport
Letters of credit		—		—		—		2.4			2.4		—
TECO Coal
Letters of credit		—		—		—		20.0			20.0		—
Guarantees: Other(2)		10.0		—		—		1.4	(1)		11.4		2.2
		10.0		—		—		21.4			31.4		2.2
TECO Guatemala
Letters of credit		—		4.7		—		—			4.7		—
Other
Guarantees:
Debt related		—		—		—		10.2			10.2		10.2
Fuel purchase/energy management(1)(2)		—		—		—		8.7			8.7		—
		—		4.7		—		18.9			18.9		10.2
Total	$	186.9	$	4.7	$	—	$	65.1		$	256.7	$	17.5

(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2009.

(2) The amounts shown are the maximum theoretical amount guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Dec. 31, 2004. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

A summary of TECO Energy’s significant financial covenants as of Dec. 31, 2004 is as follows:

TECO Energy Significant Financial Covenants

(millions, unless otherwise indicated) Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Dec. 31, 2004
Tampa Electric
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(3)	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(3)	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(4)	Cumulative operating cash flow in excess of 1.7 times interest	$258 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	Debit/capital	Cannot exceed 65%	70.0% (6)
project guarantees(5)	EBITDA/interest(2)	Minimum of 3.0 times	1.9 times(6)
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) See description of credit facilities inNote 6.

(4) 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 available for future restricted payments.

(5) SeeTPGC Guarantees below.

(6) The Construction Undertakings permit TECO Energy to terminate its obligation is thereunder, including the requirement to comply with the covenants, by providing a Substitute Guarantor reasonably satisfactory to the lending group. On Sep. 22, 2003, TECO Energy tendered a Substitute Guarantor, which it believes satisfied the requirements of the Construction Undertakings. The lending group declined to accept this tender as being satisfactory. TECO Energy has the right to assert that the Construction Undertakings are terminated in the event that the lending group seeks to exercise its remedies based on a violation of the EBITDA-to-interest coverage ratio and the debt-to-capital covenants.

TPGC Guarantees

The TECO Energy guarantees of the equity contribution agreements of TPGC and the Construction Undertaking 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 during 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 21 for further discussion on this agreement andNote 23 for details of a related subsequent event.

13. Related Parties

In October 2003, Tampa Electric signed a five-year contract renewal with an affiliate company, TECO Transport, 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. In September 2004, the FPSC voted to disallow approximately $14 to $16 million (pre-tax) of the costs that Tampa Electric can recover from its customers for water transportation services. This impact has been fully recognized by Tampa Electric for 2004. The decision allows, but does not require, Tampa Electric to rebid the water transportation and terminal service contract. Tampa Electric filed its objection to the disallowance on Oct. 27, 2004, and a decision on this matter is expected in the first quarter of 2005. SeeNote 23 for a subsequent event.

In February 2002, Tampa Electric and TECO-Panda Generating Company II (TPGC II) entered into an assignment and assumption agreement under which Tampa Electric obtained TPGC II’s rights and interests to four combustion turbines being purchased from General Electric, and assumed the corresponding liabilities and obligations for such equipment. In accordance with the terms of the assignment and assumption agreement, Tampa Electric paid $62.5 million to TPGC II as reimbursement for amounts already paid to General Electric by TPGC II for such equipment. No gain or loss was incurred on the transfer. In the first quarter of 2003, Tampa Electric recorded a $48.9 million after-tax charge related to the cancellation of these turbine purchase commitments (seeNote 18).

As of Dec. 31, 2003, a note receivable of $8.1 million due from EEGSA, an unconsolidated affiliate, bearing a current effective interest rate of 6.14%, was recorded on the balance sheet. In 2004, this note was repaid in full.

On Jan. 3, 2003, the $137.0 million loan receivable from PLC, a wholly-owned subsidiary of Panda Energy, converted to a 50% ownership interest in PLC, leading to a joint venture with Panda Energy. This joint venture held a 50% ownership interest in Texas Independent Energy, L.P. (TIE). The TIE partnership owns and operates the Odessa and Guadalupe power stations in Texas. In September 2003, TWG completed foreclosure proceedings against Panda Energy for their ownership interest in PLC as a result of Panda’s default under a $23.0 million note receivable. Consequently, in 2003, PLC was fully consolidated and the $23.0 million note receivable was converted to an equity interest. The investment in PLC was sold in 2004. See alsoNote 16 for additional information regarding PLC.

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.4 million, $1.2 million and $1.1 million for the years ended Dec. 31, 2004, 2003 and 2002, respectively, to Ausley McMullen, of which Mr. Ausley (a director of TECO Energy) is an employee. Other transactions were not material for the years ended Dec. 31, 2004, 2003 and 2002. No material balances were payable as of Dec. 31, 2004 or 2003.

14. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets, as required by FAS 131,Disclosures about Segments of an Enterprise and Related Information. All significant intercompany transactions are eliminated in the consolidated financial statements of TECO Energy, but are included in determining reportable segments.

During the first quarter of 2005, as part of its continued focus on core utility and profitable unregulated operations, the company revised internal reporting information used for decision making purposes. With this change, management began to view the results and performance of TECO Guatemala, Inc. (TECO Guatemala) (formerly TWG Non-Merchant, Inc.), as a separate segment comprised of all Guatemalan operations. TECO Guatemala includes the equity investments in the San José and Alborada power plants, the equity investment in the Guatemalan distribution company, EEGSA, and the TECO Guatemala parent company. Results for TECO Guatemala were previously reported in the Other Unregulated segment. Following the sales of the larger energy services businesses, which were previously reported in the Other Unregulated segment, the remaining small operations of TECO Solutions are now reported within “Other & Eliminations.” Prior period segment results have been restated to reflect the revised segment structure.

The information presented in the following table excludes all discontinued operations. SeeNote 21 for additional details of the components of discontinued operations.

Segment Information⁽¹⁾

(millions)	Tampa Electric			Peoples Gas		TECO Coal			TECO Transport			TECO Guatemala			TWG Merchant			Other & Eliminations			Total TECO Energy
2004
Revenues — outsiders	$	1,683.8		$	417.2	$	327.6		$	173.4		$	11.5		$	7.6		$	18.3		$	2,639.4
Sales to affiliates		3.6			—		—			76.2			—			—			(79.8	)		—
Total revenues		1,687.4			417.2		327.6			249.6			11.5			7.6			(61.5	)		2,639.4
Depreciation		180.9			34.1		36.3			21.9			0.8			1.0			0.9			275.9
Restructuring costs(2)		—			0.7		—			—			—			0.5			—			1.2
Total interest charges(3)		95.8			15.2		11.2			4.7			14.7			50.7			130.6			322.9
Internally allocated interest(3)		—			—		11.1			(1.0	)		14.3			50.7			(76.8	)		(1.7	)
Provision (benefit) for taxes		83.9			17.3		22.8			4.6			8.1			(314.0	)		(67.8	)		(245.1	)
Net income (loss) from continuing operations(3)	$	146.0		$	27.7	$	61.3		$	10.2		$	5.7	(5)	$	(534.1	)(4)	$	(72.3	)(8)	$	(355.5	)
Goodwill		—			—		—			—			59.4			—			—			59.4
Investment in unconsolidated affiliates		—			—		—			3.3			239.2			—			20.5			263.0
Other non-current investments		—			—		—			—			—			—			8.0			8.0
Total assets		4,167.3			671.1		413.9			315.4			363.6			2,736.8			808.4			9,476.5
Capital expenditures		181.2			38.7		22.9			20.2			0.4			0.2			0.1			263.7
2003
Revenues — outsiders	$	1,582.7		$	408.4	$	296.3		$	162.2		$	108.2		$	(2.5	)	$	7.6		$	2,562.9
Sales to affiliates		3.4			—		—			98.4			50.2			—			(152.0	)		—
Total revenues		1,586.1			408.4		296.3			260.6			158.4			(2.5	)		(144.4	)		2,562.9
Depreciation		210.3			32.7		34.2			20.6			15.0			0.3			0.3			313.4
Restructuring costs(2)		9.9			4.1		—			1.7			4.7			0.4			3.8			24.6
Total interest charges(3)		85.0			15.6		11.0			4.9			23.0			55.7			121.3			316.5
Internally allocated interest(3)		—			—		11.0			(2.0	)		13.2			67.8			(93.7	)		(3.7	)
Provision (benefit) for taxes		48.3			15.7		(64.4	)		9.7			9.2			(36.6	)(7)		(49.8	)		(67.9	)
Net income (loss) from continuing operations(3)	$	98.9	(6)	$	24.5	$	77.1		$	15.3		$	22.0	(5)	$	(60.8	)	$	(76.3	)	$	100.7
Goodwill		—			—		—			—			59.4			—			11.8			71.2
Investment in unconsolidated affiliates		—			—		—			—			140.8			158.9			43.8			343.5
Other non-current investments		—			—		—			—			8.1			—			8.4			16.5
Total assets		4,178.6			651.5		340.8			315.8			549.8			3,504.4			921.4			10,462.3
Capital expenditures		289.1			42.6		20.6			19.6			19.2			(1.5	)		2.1			391.7
2002
Revenues — outsiders	$	1,548.9		$	318.1	$	316.4		$	143.9		$	147.4		$	4.9		$	7.7		$	2,487.3
Sales to affiliates		34.3			—		0.7			110.7			51.4			—			(197.1	)		—
Total revenues		1,583.2			318.1		317.1			254.6			198.8			4.9			(189.4	)		2,487.3
Depreciation		189.8			30.5		31.4			22.2			16.2			0.2			0.3			290.6
Restructuring costs(2)		16.6			—		—			—			1.2			—			—			17.8
Total interest charges(3)		51.5			14.8		8.2			6.3			32.9			24.2			31.4			169.3
Internally allocated interest(3)		—			—		8.1			(1.7	)		15.1			87.5			(113.7	)		(4.7	)
Provision (benefit) for taxes		86.1			14.7		(130.1	)		10.8			3.9			(11.4	)(7)		(32.8	)		(58.8	)
Net income (loss) from continuing operations(3)	$	171.8		$	24.2	$	76.4		$	21.0		$	25.2	(9)	$	(18.8	)	$	(34.4	)	$	265.4
Goodwill		—			—		—			—			59.4			95.1			39.2			193.7
Investment in unconsolidated affiliates		—			—		—			—			135.6			(38.2	)		51.8			149.2
Other non-current investments		—			—		—			—			39.8			795.8			9.7			845.3
Total assets		4,119.4			629.9		283.5			355.1			761.2			2,113.9			815.4			9,078.4
Capital expenditures		632.2			53.5		48.2			25.2			76.8			222.7			0.2			1,058.8

(1) From continuing operations. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for: Commonwealth Chesapeake Company (CCC), Frontera Generation Limited Partnership, and the Union and Gila River projects (formerly part of TWG Merchant); and TECO Coalbed Methane, Prior Energy, BGA, BCH Mechanical and AGC (formerly part of Other & Eliminations segment). SeeNote 21.

(2) SeeNote 19for a discussion of restructuring charges in 2004, 2003 and 2002.

(3) Segment net income is reported on a basis that includes internally allocated financing costs. Internally allocated costs for 2004, 2003 and 2002 were at pre-tax rates of 8%, 8% and 7%, respectively, based on the average investment in each subsidiary. Internally allocated interest charges are a component of total interest charges.

(4) Net income for 2004 includes after-tax charges of $390.7 million ($609.5 million pretax) for asset impairments for the Dell and McAdams merchant assets (seeNote 18), and a $99.0 million after-tax charge ($152.3 million pretax) to write-off its investment in TIE (seeNote 16).

(5) Net income for 2004 includes a $12.8 million after-tax asset impairment charge ($21.1 million pretax) related to certain steam turbines (seeNote 18), and $24.1 million in after-tax charges associated with debt extinguishment and income taxes due to repatriation of cash following refinancing for the San José Power Station in Guatemala. Net income for 2003 includes $37.5 million after-tax asset and intangible impairment charges ($59.9 million pretax) primarily related to the steam turbines and project cancellation costs (seeNote 18), $9.0 million after-tax ($14.8 million pretax) income from the operations of HPP up until the date of sale, and $34.6 million of after-tax gains ($56.3 million pretax) on the sale of HPP (seeNote 16).

(6) Net income for 2003 includes a $48.9 million after-tax ($79.6 million pretax) asset impairment charge related to turbine purchase cancellations (seeNote 18).

(7) Taxes have been allocated, for segment reporting purposes, to TWG based on the weighted-average tax rates of the TWG components.

(8) Net income for 2004 includes a $12.0 million after-tax gain ($19.7 million pretax) on the sale of the interest in the propane business (seeNote 16).

(9) Net income for 2002 includes $9.0 million after-tax ($14.7 million pretax) income from the operations of HPP.

Tampa Electric Company provides retail electric utility services to more than 625,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase and distribution of natural gas for more than 314,000 residential, commercial, industrial and electric power generation customers in the state of Florida.

TECO Transport, through its wholly-owned subsidiaries, transports, stores and transfers coal and other dry bulk commodities for third parties and Tampa Electric. TECO Transport’s subsidiaries operate on the Mississippi, Ohio and Illinois rivers, in the Gulf of Mexico and worldwide.

TECO Coal, through its wholly owned subsidiaries, owns mineral rights and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia. TECO Coal acquired and began operating two synfuel facilities in 2000, whose production qualifies for the non-conventional fuels tax credit. In 2003 these synfuel operations were transferred into a newly formed LLC for the purpose of continuing growth in the production and sale of synthetic fuel. In April 2003, TECO Coal sold 49.5% interest in this entity and an additional 40.5% in 2004 (seeNote 16).

TWG-Merchant has subsidiaries that have interests in independent power projects in Arkansas and Mississippi.

TECO Guatemala’s businesses are primarily engaged in owning and operating independent power projects with long-term contracts in Guatemala.

Foreign Operations

TECO Guatemala includes independent power operations and investments in Guatemala. TECO Energy, through its equity investments, has a 96% ownership interest and operates the 78-megawatt Alborada power station that supplies energy to EEGSA, an electric utility in Guatemala, under a U.S. dollar-denominated power sales agreement. TECO Energy, through its equity investments, also has a 100% ownership interest in the 120-megawatt San José power station and in transmission facilities in Guatemala. The plant provides capacity under a U.S. dollar-denominated power sales agreement to EEGSA. Prior to 2004 and the adoption of FIN 46R, the subsidiaries that hold interests in the San José and Alborada power stations in Guatemala were consolidated entities. As of Jan. 1, 2004, in accordance with the interpretation and application of the consolidation guidance established in FIN 46R to long-term power purchase agreements, TECO Energy can no longer consolidate these project companies and they are considered equity investments (seeNotes 1 and2 for additional details).

TECO Energy, through a wholly-owned subsidiary, owns a 30% interest in a three member consortium that also includes Iberdrola, an electric utility in Spain, and Electricidad de Portugal, an electric utility in Portugal. The consortium, called Distribuidora Electrica Centroamericana Dos (“DECA II”) owns an 80.9% interest in both EEGSA and Inversiones Electricas Centroamericanas, S.A. (“INVELCA”), the holding company for Guatemalan-based electric transmission (“TRELEC”), services (“Energica”) and unregulated distribution (“Comegsa”) companies, and a 55% interest in Novega.com, a telecommunications and data transmission carrier.

Total assets at Dec. 31, 2004, 2003 and 2002 included $327.2 million, $445.8 million and $415.9 million, respectively, related to these Guatemalan operations and investments. Revenues included $6.7 million, $82.7 million and $85.1 million for the years ended Dec. 31, 2004, 2003 and 2002, respectively, and income from equity investments included $45.2 million, $8.8 million and $3.3 million for the same periods from these Guatemalan operations and investments.

15. Asset Retirement Obligations

On Jan. 1, 2003, TECO Energy adopted FAS 143,Accounting for Asset Retirement Obligations. The company recognized liabilities for retirement obligations associated with certain long-lived assets, in accordance with the relevant accounting guidance. An asset retirement obligation (ARO) for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

TECO Energy has recognized asset retirement obligations for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. Prior to the adoption of FAS 143, TECO Coal accrued reclamation costs for such activities. For TECO Coal, the adoption of FAS 143 modified the valuation and accrual methods used to estimate the fair value of asset retirement obligations.

As a result of the adoption of FAS 143, in 2003 TECO Energy recorded an increase to net property, plant and equipment of $7.8 million (net of accumulated depreciation of $6.6 million) and an increase to asset retirement obligations of $22.1 million, partially offset by previously recognized accrued reclamation obligations associated with coal mining activities of $12.3 million. A pretax charge of $1.8 million, net of a $0.2 million offset due to a regulatory asset at Tampa Electric, ($1.1 million after tax) was recognized as a change in accounting principle.

For the years ended Dec. 31, 2004 and Dec. 31, 2003, TECO Energy recognized $2.0 million and $1.2 million of accretion expense, respectively, associated with asset retirement obligations. During 2004, no significant additional ARO obligations were incurred, and no significant revisions to estimated cash flows used in determining the recognized asset retirement obligations were necessary. FAS 143 was not effective for the year ended Dec. 31, 2002.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

Upon adoption of FAS 143 at Jan. 1, 2003, the estimated accumulated cost of removal and dismantlement included in net accumulated depreciation as of Dec. 31, 2003 of $462.2 million was reclassified to a regulatory liability (see alsoNote 3). For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal, or dismantlement, less salvage value is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

16. Mergers, Acquisitions and Dispositions

PLC Development/TIE

At Dec. 31, 2002, TWG had a loan receivable of $137 million from PLC, a subsidiary of Panda Energy International. On Jan. 3, 2003, this loan was converted to a partnership interest in PLC. SeeNotes 1 and13 for additional details regarding the conversion of this loan to an equity interest in PLC. Furthermore, in September 2003, the company consummated the foreclosure on Panda Energy’s interest in PLC for a default under a $23 million note receivable leading to TWG’s 100% ownership in PLC which owns 50% of TIE (seeNotes 1,13 and20). As of Sep. 30, 2003, TWG consolidated PLC, resulting in a net increase in investment in unconsolidated affiliates of approximately $18 million. On Aug. 30, 2004, a TWG-Merchant subsidiary completed the sale of its 50% indirect interest in TIE to PSEG Americas Inc., for $0.5 million. The company recorded a $152.3 million pretax impairment ($99.0 million after tax) to write off the value of the investment as a result of the sale.

Summary financial information for TIE is included in the table below.

(millions) Dec. 31,	2004 (1)			2003
Revenues	$	319.7		$	453.1
Operating income		4.8			25.5
Net (loss) available for allocation to partners	$	(18.3	)	$	(14.4	)
Current assets	$	—		$	57.9
Non-current assets		—			802.7
Current liabilities		—			83.5
Non-current liabilities	$	—		$	500.1

(1) 2004 only reflects results through Jul. 31, 2004, the effective date of the sale. The amounts for July 2004 represent estimates based on information received from the management of TIE.

Frontera

On Dec. 22, 2004, a subsidiary of TWG Merchant, Inc. completed the sale of its interests in Frontera Generation Limited Partnership (Frontera), the owner of the Frontera Power Station in Texas, to a subsidiary of Centrica plc for $133.7 million, consisting of $128.5 million of cash and assumption of $5.2 million of liabilities. TECO Energy has the opportunity to receive an Annual Earnout Payment if Frontera is the successful bidder and enters into a Reliability Must Run Contract with the Electric Reliability Council of Texas (ERCOT). Both TECO Energy and Centrica plc have guaranteed the payment obligations of their respective direct or indirect subsidiaries under the Purchase Agreement, with Centrica’s obligation limited to 10% of the Adjusted Purchase Price (as defined in the Purchase Agreement). As a result of the sale, a pretax loss of $42.1 million ($27.0 million after tax) was recorded. The sale is subject to certain ordinary and customary post-closing adjustments to working capital items. These adjustments are not expected to be material. SeeNote 21 – Other transactions for additional details related to this transaction.

Commonwealth Chesapeake

In August 2004, the company entered into an agreement with NCP of Virginia, LLC (NCP), the non-equity member in Commonwealth Chesapeake Company (CCC), under which TECO Energy and a subsidiary agreed to purchase NCP’s interest in CCC for $30 million in cash plus shares of TECO Energy common stock having a value of $10 million, and NCP released all claims against the company and its subsidiaries. The funds and shares were released from escrow upon receipt of FERC approval on Sep. 30, 2004 (seeNote 12 for additional details of this transaction andNote 23 for discussion of a subsequent event involving CCC).

TECO Propane Ventures

In the first quarter of 2004, US Propane, LLC sold a majority of its assets, consisting of direct and indirect equity investments in Heritage Propane Partners, L.P., and the remaining indirect investment was sold in the second quarter of 2004. The sales resulted in cash proceeds of $53 million and after-tax gains totaling $12.0 million.

Hamakua Power Station

On Jul. 15, 2004, TECO Wholesale Generation’s 50% indirect interest in the Hamakua Power Station in Hawaii was sold to an affiliate of Black River Energy, an affiliate of Energy Investors Funds’ US Power Fund, L.P.. Via its ownership of Black River Energy, which already owns 50% of the plant, Energy Investors Funds is now the sole owner of Hamakua. Cash proceeds from the sale were approximately $12 million, and resulted in an immaterial gain. As a result of the transaction, TECO Energy was also relieved of certain financial guarantees related to the facility.

Prior Energy

Effective Feb. 1, 2004, a subsidiary of TECO Energy completed the sale of Prior Energy for net proceeds of approximately $30 million. This sale did not result in a material gain or loss to the company. See the Other transactions section of Note 21 for additional details relating to this disposition.

BGA

Effective Jan. 1, 2004, the company completed the sale of TECO BGA, Inc. (formerly a component of TECO Energy Services) to an entity owned by an employee group for a loss on disposal of $12.2 million ($7.5 million after tax). This loss was recorded as part of the asset impairment charge reported in the income statement for the year ended Dec. 31, 2003.

Synthetic Fuel Facilities

Effective Apr. 1, 2003, TECO Coal sold a 49.5% interest in its synthetic fuel production facilities located at its operations in eastern Kentucky. No significant gain or loss was recognized at the time of the sale. The company, through its various affiliates, will provide feedstock supply, and operating, sales and management services to the buyer through 2007, the current expiry date for the related Section 29 credit for which the production qualifies. Because the transaction was structured on a deferred payment basis typical of similar transactions in the industry, TECO Coal received no significant cash at the time of sale. The sale required receipt of a positive response to a Private Letter Ruling (PLR) request, and the proceeds from this transaction were held in escrow pending resolution of this contingency. On Oct. 31, 2003, TECO Coal received a PLR from the IRS that resolved any uncertainty related to the previous sale of the 49.5% interest in its synthetic fuel facilities; triggered the release of certain cash escrows related to this sale; and confirmed that synthetic fuel produced by TECO Coal is eligible for Section 29 credits and that its testing procedures are in compliance with the requirements of the IRS. On Nov. 5, 2003, $58.9 million of restricted cash that had been held in escrow was released following receipt of the PLR. In June 2004, TECO Coal sold an additional 40.5% of its membership interest in the synthetic fuel facilities under similar terms as the first transaction. In addition to retaining a 10% membership interest in the facilities, the TECO Coal subsidiary will continue to supply the feedstock and operate the facilities.

TECO Coalbed Methane

TECO Coalbed Methane, a subsidiary of TECO Energy, produced natural gas from coal seams in Alabama’s Black Warrior Basin. In September 2002, the company announced its intent to sell the TECO Coalbed Methane gas assets. On Dec. 20, 2002, substantially all of TECO Coalbed Methane’s assets in Alabama were sold to the Municipal Gas Authority of Georgia. Proceeds from the sale were $140 million, $42 million paid in cash at closing, and a $98 million note receivable which was paid in January 2003. Net income for the year ended Dec. 31, 2003 included a $23.5 million after-tax gain for the final cash installment from the sale of these assets. TECO Coalbed Methane’s results are included in discontinued operations for all periods presented (seeNote 21).

Hardee Power Partners

In 2003, Hardee Power Partners, Ltd. (HPP), which holds a 370-MW gas-fired generation facility located in central Florida, was sold to an affiliate of Invenergy LLC and GTCR Golder Rauner LLC. Under the terms of the sale, subsidiaries of the company would continue to provide service to HPP under the existing operation and maintenance agreement. Under the terms of the agreement, these services ceased in September 2004. Additionally, Tampa Electric’s long-term power purchase obligation to receive electricity from HPP remains in effect with no changes as a result of the transaction (seeNote 1). The sale proceeds of approximately $107 million exceeded the net book value of $51.5 million (including assets of $149.1 million and liabilities of $97.6 million) resulting in a pretax gain of $56.3 million.

Due to the anticipated power purchases by Tampa Electric from HPP under the pre-existing long-term power purchase agreement (see thePurchased Power section ofNote 1) resulting in cash outflows, the results from operations are precluded from being presented as discontinued operations.

17. Goodwill and Other Intangible Assets

Effective Jan. 1, 2002, TECO Energy and its subsidiaries adopted FAS 141,Business Combinations, and FAS 142,Goodwill and Other Intangible Assets. FAS 141 requires all business combinations initiated after Jun. 30, 2001 to be accounted for using the purchase method of accounting. With the adoption of FAS 142, goodwill is no longer subject to amortization. Rather, goodwill and intangible assets, with an indefinite life, are subject to an annual assessment for impairment by applying a fair-value-based test. Intangible assets with a measurable useful life are required to be amortized.

As required under FAS 142, TECO Energy reviews recorded goodwill and intangible assets at least annually for each reporting unit. Reporting units are generally determined as one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill and other intangible assets. The fair value for the reporting units evaluated is generally determined using discounted cash flows appropriate for the business model of each significant group of assets within each reporting unit. The models incorporate assumptions relating to future results of operations that are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Management periodically reviews and adjusts the assumptions, as necessary, to reflect current market conditions and observable activity. If a sale is expected in the near term or a similar transaction can be readily observed in the marketplace, then this information is used by management to estimate the fair value of the reporting unit.

In December 2004, the company recognized an $11.8 million pretax charge ($8.4 million after tax) to write off the value of the remaining goodwill associated with BCH Mechanical. In 2003, the company recorded pretax goodwill impairments of $17.7 million ($10.9 million after tax) and $1.7 million ($1.1 million after tax), respectively, for BCH Mechanical and TECO BGA. These charges are reflected in discontinued operations. SeeNotes 21,23 and25 for additional details.

In December 2004, as a result of its annual impairment assessment, the company recognized a pretax impairment charge of $4.8 million ($3.1 million after tax) to write off the value of an intangible asset associated with the acquisition of the Commonwealth Chesapeake power station (SeeNote 18 for additional details). This charge is reflected in discontinued operations. In 2003, the company also recognized pretax impairment charges of $6.6 million ($4.1 million after tax) to write-off technology licenses at TWG. Included in discontinued operations in 2003 is a pretax impairment charge of $1.5 million ($0.8 million after tax) to write off a long-term customer arrangement at BGA. For the years ended Dec. 31, 2004, 2003 and 2002, the company recognized amortization expense of $0.2 million, $4.7 million and $23.1 million, respectively. SeeNotes 21, 23 and 25for additional details.

Further, the company recognized a pretax impairment charge in June 2003 of $95.2 million ($61.2 million after tax) to write off all of the goodwill previously recorded at TWG Merchant based on the implied fair value of its goodwill, in accordance with FAS 142. This goodwill arose from the previous acquisitions of the Commonwealth Chesapeake power station in Virginia and the Frontera power station in Texas. These charges are reflected in discontinued operations as a result of the company’s sale of its interest in Frontera in December 2004 and CCC in April 2005. (SeeNote 16 for additional details).

The company has $59.4 million of goodwill remaining on its balance sheet as of Dec. 31, 2004, which is reflected in the TECO Guatemala segment. Additionally, as of Dec. 31, 2004, the company has no more intangible assets.

18. Asset Impairments

Following major investments in merchant power, during 2001 and 2002 conditions in merchant energy markets changed dramatically, reducing prospects for profitability and leading to cessation of new merchant development activities in 2003. During 2003, the company announced that it would re-focus on its regulated utilities and its profitable unregulated businesses, and reduce its exposure to the merchant power sector. This led to the decision in 2003 to exit the Union and Gila River power stations (seeNote 21 for additional details). During 2004, wholesale power prices remained weak and prospects for price recovery for the next several years remained poor. While management monitored these events throughout 2004, there were no specific triggering events prior to the fourth quarter that warranted a SFAS 142 or 144 impairment analysis. In the fourth quarter of 2004, management conducted a review of prospects for long-term price recovery as well as opportunities for sales of the assets. This review led to the sale of the company’s investment in the Frontera power station in December 2004 (seeNote 16). Also as a result of this review, management determined as of Dec. 31, 2004 a lower probability that the remaining merchant investments would be held for the long term, resulting in impairments to the Dell, McAdams, and Commonwealth Chesapeake power stations described below.

In December 2004, a pretax impairment charge of $609.5 million ($390.7 million after tax) was recognized related to the company’s investments in the Dell and McAdams power stations. Under a probability analysis weighted toward short-term recovery, the investments failed the recoverability test of FAS 144. As a result, the assets were written down to fair market value based on a probability weighting of potential sales of the assets and salvage value, which represented the best estimate of fair market value.

In December 2004, the company recognized a pretax impairment charge of $81.3 million ($52.1 million after tax) related to its investment in the Commonwealth Chesapeake power station. Under a probability analysis weighted toward short-term recovery, the investments failed the recoverability test of FAS 144. As a result, the assets were written down to fair market value based on a probability weighting of potential sales of the assets, which represented the best estimate of fair market value. This amount is included in discontinued operations on the income statement. SeeNote 23 for additional details of a subsequent event.

On Aug. 30, 2004, a TWG-Merchant subsidiary completed the sale of its 50% indirect interest in TIE. In the second quarter of 2004 the company recorded a $151.9 million pre-tax impairment ($98.7 million after-tax) to record the estimated write-off of the investment reflecting the anticipated sale. This estimate was finalized resulting in an additional $0.4 million pre-tax impairment ($0.3 million after-tax) being recorded in the third quarter of 2004. SeeNote 16 for additional details.

In December 2004, a pretax impairment charge of $8.2 million ($5.9 million after tax) was recognized related to the company’s interests in BCH Mechanical. SeeNote 23 for details of a subsequent event. The impairment charge and results of operations are reflected in discontinued operations (seeNote 21).

In December 2004, as part of its annual impairment review, pretax impairment charges of $21.1 million ($12.8 million after tax) were recognized to write off the remaining value of steam turbines originally planned for use in a cogeneration project. Based on management’s review of the market for steam turbines and its refocus on its core businesses, it was determined that the turbines should be written down to fair market value. In December 2003, pretax asset impairment charges of $27.8 million ($17.4 million after tax) were recognized primarily related to the steam turbines and licenses that were also planned for use in a cogeneration project. The charges are reflected in the TECO Guatemala segment.

In the first quarter of 2004, Litestream Technologies, LLC, an entity in which TECO Fiber, a subsidiary of TECO Solutions, holds an equity investment, was placed into bankruptcy by creditors. As a result of the bankruptcy, the company recognized a pretax loss of $5.5 million ($3.4 million after tax). The loss on the equity investment in Litestream was determined using the estimated fair value of the company’s claims to net assets. The charge is reflected in the Eliminations and Other segment.

Additional impairment charges recognized in 2004 include a $2.4 million pretax ($1.5 million after tax) valuation adjustment at TECO Solutions, Inc. (TECO Solutions) related to a district cooling plant, which is reflected in discontinued operations, and a pretax impairment of $0.9 million ($0.6 million after tax) on ocean-going barges at TECO Transport.

As of Dec. 31, 2003, based on the negotiations with potential buyers, including the project lenders, a change in management’s expectations regarding an exit strategy in the near term, and management’s designation of the Union and Gila River project companies as held for sale, a pretax asset impairment charge of $1,185.7 million ($770.7 million after tax) was recognized and reflected in discontinued operations, in accordance with FAS 144 (seeNote 21 for additional details).

In 2003, TECO Energy recognized a pretax asset impairment charge of $104.1 million ($64.2 million after tax) relating to installment payments made and capitalized under turbine purchase commitments in prior periods. As reported previously and inNote 13, certain turbine rights had been transferred from Other Unregulated operations to Tampa Electric in 2002 for use in Tampa Electric’s generation expansion activities. These cancellations, made in April 2003, fully terminate all turbine purchase obligations for these entities.

19. Restructuring Costs

In 2004, as part of the company’s continued focus to exit merchant operations and to grow the core utility operations to provide for centralized oversight along functional lines, certain restructuring activities were implemented. These actions involved seven employees, including officers and other personnel from operations and support services. In September and October of 2003, TECO Energy announced a corporate reorganization to restructure the company along functional lines, consistent with its objectives to grow the core utility operations, maintain liquidity, generate cash and maximize the value in the existing assets. The 2003 actions included the involuntary termination or retirement of 337 employees, including officers and other personnel from operations and support services.

In 2002, TECO Energy initiated a restructuring program that impacted approximately 250 employees across multiple operations and services within, primarily, Tampa Electric. This program included retirements, the elimination of positions and other cost control measures. The total costs associated with this program, included severance, salary continuation and other termination and retirement benefits.

The company recognized a pretax expense of $1.2 million, $24.6 million and $17.8 million for accrued benefits and other termination and retirement benefits for the years ended Dec. 31, 2004, 2003 and 2002, respectively.

Restructuring Charges

(millions) For the years ended Dec. 31,	2004		2003		2002
Tampa Electric	$	—	$	9.9	$	16.6
Peoples Gas		0.7		4.1		—
TWG Merchant		0.5		0.4		—
TECO Guatemala		—		4.6		1.2
TECO Transport		—		1.7		—
TECO Coal		—		—		—
Eliminations and other(1)		—		3.9		—
Total TECO Energy	$	1.2	$	24.6	$	17.8

(1) This amount relates to charges at TECO Energy parent.

Accrued Liability for Restructuring Costs

(millions)	2004		2003		2002
Beginning balance	$	15.8	$	6.0	$	0.2
Charged to income (pre-tax)		1.2		24.6		17.8
Payments and settlements		16.5		14.8		12.0
Ending balance	$	0.5	$	15.8	$	6.0

20. TPGC Joint Venture Termination

In January 2002, TWG (formerly TECO Power Services Corporation) subsidiaries agreed to purchase the interests of Panda Energy in the TPGC projects in 2007 for $60 million, and TECO Energy guaranteed payment of this obligation. Panda Energy obtained bank financing using the purchase obligation and assigned TECO Energy’s guarantee as collateral. Under certain circumstances, the purchase obligation could have been accelerated for a reduced price based on the timing of the acceleration. In connection with this purchase obligation, Panda Energy retained a cancellation right, exercisable in 2007 for $20 million by the holder, with early exercise permitted for a reduced price of $8 million.

On Apr. 9, 2003, the TWG subsidiaries and Panda Energy amended the agreements related to the purchase obligation. The modified terms accelerated the purchase obligation to occur on or before Jul. 1, 2003, and reduced the overall purchase obligation to $58 million. Under the guarantee, TWG became obligated to make interest and certain principal payments to or on behalf of Panda related to the collateralized loan obligation of Panda. The purchase obligation of $58 million included $35 million for Panda Energy’s interest in TPGC, and a short-term receivable from Panda, collateralized by Panda’s remaining interests in PLC (seeNotes 1 and13 for additional details on TECO Energy’s indirect ownership interest in PLC). Both modifications to the purchase obligation were subject to the condition, which TECO Energy could waive, that bank financing be obtained by TECO Energy. Panda Energy’s cancellation right was accelerated to expire on Jun. 16, 2003. TECO Energy’s guarantee of the TWG subsidiaries’ obligation was modified to reflect the amendments to the purchase obligation. In April 2003, TECO Energy recognized the fair value of the guarantee as a pretax loss of $35.0 million ($21.4 million after tax), included in discontinued operations, as a result of the expected disposition of the project companies (seeNote 21). From April 2003 through June 2003, TECO Energy made and accrued certain principal payments under the guarantee commitment.

As a result of the amendments to these agreements in early April 2003, management believed the exercise of the modified guarantee and the related purchase obligation became highly probable. The likelihood of the exercise of the purchase obligation created a presumption of effective control. When combined with TECO Energy’s exposure to the majority of risk of loss under the previously disclosed letters of credit and contractor undertakings, management believed that consolidation of TPGC was appropriate as of the date of the modifications to the agreements. Prior to Apr. 1, 2003, TWG recognized assets of $839.1 million, liabilities of $48.9 million and an unrealized loss in OCI of $69.0 million, to reflect the equity method of accounting for its investment in TPGC. As a result of the consolidation on Apr. 1, 2003, the company recognized additional assets of $2,446.9 million, primarily relating to utility plant and construction work in progress, additional liabilities of $1,976.8 million (including non-recourse debt), and an additional unrealized loss in OCI of $69.0 million for interest rate swaps designated as hedges. SeeNote 21 for a discussion of the subsequent designation of the TPGC projects as assets and liabilities held for sale.

In June 2003, TECO Energy satisfied the bank financing condition resulting in the acceleration of TECO Energy’s guarantee obligation and executed a final agreement with Panda to effect the termination of Panda’s involvement in the partnership. Proceeds from the bank financing obtained in June 2003, which is more fully discussed inNote 6, were used to fund the net termination payment to Panda. Upon acceleration of the guarantee obligation and the resulting partnership termination, TWG received the 50% outstanding partnership interests in TPGC. As previously discussed, under the amended agreements, $35.0 million, pretax, had been recognized in April 2003 as the fair value of the guarantee obligation. The remaining amount was recorded as due from Panda and collateralized by Panda’s remaining interests in PLC. Foreclosure proceedings were consummated on Panda’s remaining interests in PLC in September 2003. As of Dec. 31, 2004 and Dec. 31, 2003 substantially all of the assets and liabilities associated with the TPGC projects (Union and Gila River) were classified as held for sale. All results of operations for these two projects have been reclassified to discontinued operations for all periods presented.

For the year ended Dec. 31, 2003, TWG recorded total pretax charges of $249.1 million ($155.9 million after tax) as a direct result of the consolidation of TPGC. SeeNote 21 for a discussion of the remaining amount recorded in discontinued operations.

21. Discontinued Operations and Assets Held for Sale

SeeNote 25 for a discussion of updating of discontinued operations subsequent to year end.

Union and Gila River Project Companies (TPGC)

During 2004 an agreement was reached with the steering committee of the lending group for the Union and Gila River power stations on all material terms and forms of definitive agreements for the previously announced sale and transfer to the lenders of ownership of these plants. The lenders process of seeking approval for the transaction to be completed required a 100% approval by the lenders. Two lenders, representing approximately 10% of the debt, dissented. The lending group indicated that in order to facilitate the completion of this transaction, a pre-negotiated Chapter 11 case of the Union and Gila River project entities was likely to be required. A pre-negotiated reorganization can be achieved if the approval of at least one-half of the lenders comprising two-thirds of the amount of debt can be obtained in contrast to the 100% approval contemplated in the consensual sale and transfer (seeNote 23 for details of a subsequent event). No material changes in the terms of the transaction from that previously announced are anticipated. Based on these events, as of Dec. 31, 2004 management expects to complete the transfer of the project entities in 2005, therefore the assets and liabilities of TPGC continue to be reported as held for sale. The Union and Gila River project companies comprised part of the TWG operating segment until designated as assets held for sale in December 2003.

As an asset held for sale, the assets and liabilities that are expected to be transferred as part of the sale, as of Dec. 31, 2004 and 2003, have been reclassified, respectively, in the balance sheet. Furthermore, the company has determined that TPGC meets the criteria of a discontinued operation. Results from operations for the Union and Gila River project companies have been reflected in discontinued operations for all periods presented. For the year ended Dec. 31, 2002, TPGC was a development stage company. The following table provides selected components of discontinued operations for TPGC.

Components of income from discontinued operations –

Union and Gila River Project Companies

(millions) For the years ended Dec. 31,	2004			2003			2002
Revenues	$	510.7		$	319.4		$	—
Asset impairment(1)		—			(1,185.7	)		—
(Loss) from operations		(33.5	)		(1,239.8	)		—
(Loss) on joint venture termination		—			(153.9	)		—
(Loss) income before provision for income taxes		(144.9	)		(1,441.4	)		27.4
(Benefit) provision for income taxes		(48.9	)		(522.7	)		10.6
Net (loss) income from discontinued operations	$	(96.0	)	$	(918.7	)	$	16.8

(1) Includes charges recognized in accordance with FAS 133.

Asset impairment charges

The pretax asset impairment charge of $1,185.7 million ($762.0 million after tax) recorded in 2003 is comprised of an impairment in long-lived assets and a related charge to reflect the impacts of hedge accounting. The asset impairment charge was recognized in accordance with FAS 144. The recognition of the asset impairment effectively accelerated the recognition of previously capitalized interest. As a result, in accordance with cash flow hedge accounting under FAS 133, a reversal from OCI of $22.6 million of pretax losses on the interest rate swaps was required to give effect in the income statement to the previously hedged interest which was capitalized during construction.

In addition, as of Dec. 31, 2003 the change in future expectations regarding the probability of the company retaining the long-term, non-recourse debt resulted in the reversal of an additional $63.8 million pretax losses which were previously deferred in OCI and related to the future recognition of capitalized interest amortization and future interest expense on the non-recourse debt, anticipated to be recognized in periods subsequent to 2004.

Loss on joint venture termination

As discussed in greater detail inNote 20, the consolidation of TPGC on Apr. 1, 2003 resulted in the recognition of a pretax charge of $153.9 million ($94.7 million after tax) which was recorded in discontinued operations. This pretax charge included: $35.0 million ($21.4 million after tax) related to the partnership termination under the guarantee; and $118.9 million ($73.3 million after tax) related to the consolidation of TPGC to reflect the impact of Panda’s portion of TPGC’s partnership deficit and the elimination of certain related-party liabilities (seeNote 13).

The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items:

Assets held for sale – Union and Gila River Project Companies

(millions) Dec. 31,	2004		2003
Current assets	$	128.8	$	72.9
Net property, plant and equipment		1,369.0		1,367.9
Other investments		658.5		676.1
Other non-current assets		22.4		23.7
Total assets held for sale	$	2,178.7	$	2,140.6

Liabilities associated with assets held for sale –

Union and Gila River Project Companies

(millions) Dec. 31,	2004		2003
Current portion of long-term debt, non-recourse – Secured Facility Note	$	1,395.0	$	1,395.0
Other current liabilities		233.8		94.0
Long-term debt, non-recourse Financing Facility Note		658.5		675.1
Other non-current liabilities		13.7		21.7
Total liabilities associated with assets held for sale	$	2,301.0	$	2,185.8

Current and non-current assets

Current assets include $47.9 million and $18.8 million of restricted cash as of Dec. 31, 2004 and 2003, respectively. Also included in current assets is $17.6 million and $16.2 million, as of Dec. 31, 2004 and 2003, respectively, representing the current portion of the investment in Union County bonds, described in Other investments below.

Net property, plant and equipment

Net property, plant and equipment has been reduced by accumulated depreciation of $49.4 million and a valuation adjustment of $1,099.3 million as of Dec. 31, 2004 and 2003. In accordance with FAS 144, no depreciation was recognized on TPGC’s assets in 2004 as a result of being classified as held for sale. Had TPGC’s assets not been classified as held for sale, $84.7 million of depreciation expense would have been recognized in 2004. This impairment charge arose as a result of changes in management’s expectations, including its long-term strategic outlook, and is more fully described inNote 18. The decline of the fair value of the disposal group (comprised of the assets and liabilities expected to be transferred upon disposition) below the carrying value is principally attributable to the decline in future wholesale power price expectations as a result of the repercussions of the failure of deregulation in California and the Enron bankruptcy; less than economic dispatch in some areas of the country; the U.S. economic slowdown; uncertainty with respect to long-term price recovery; and the significant excess generating capacity in many areas of the country. The primary triggering event for the recognition of the charge by the company was the significant change in management’s expectations regarding the company’s long-term future involvement in the Union and Gila River project companies and the decision, during the fourth quarter of 2003, to sell the project companies.

Other investments

Other investments represent industrial revenue bonds from Union County, Arkansas, which were acquired by Union Power Partners, L.P. (UPP), a subsidiary of TPGC, with financing obtained by borrowings from Union County (the County). As of Dec. 31, 2004 and 2003, respectively, UPP’s investment in the bonds from the County (excluding the current position) totaled $658.5 million and $676.1 million, which equals the non-recourse financing facility from the County. The County’s debt service payments on the bonds equal UPP’s debt service obligations to the County. This agreement provides an incentive to and a means through which the company can invest in the County. For periods prior to Dec. 31, 2003, TECO Energy did not include TPGC in the Consolidated Balance Sheet (seeNote 20).

Interest income on the investment and interest expense on the related long-term, non-recourse financing have no net impact on the company’s results of discontinued operations. The obligation to pay cash under the long-term debt is fully offset by the right to receive cash from the bond issuer. The interest rate and maturity date on both the bonds and the related long-term debt is 7.5% per year and June 2021.

Current and non-current liabilities

Included in current liabilities is the current portion of the financing facility due to the County, described in Other investments above, of $17.6 million and $16.2 million as of Dec. 31, 2004 and 2003, respectively. Also included is $68.1 million and $58.6 million as of Dec. 31, 2004 and 2003, respectively, for interest rate swaps entered into by the Union and Gila River projects in connection with the non-recourse collateralized borrowings.

The purpose of the interest rate swap agreement was to effectively convert a portion of the floating-rate debt to a fixed rate. The interest rate swap agreements have terms ranging from 2 to 5 years with the majority maturing in June 2006. As more fully described inNote 22, the designation of the secured facility note as a liability associated with assets held for sale resulted in the prospective loss of hedge accounting for the periods beyond the expected effective date of the sale.

Non-recourse, secured facility note

In 2001, the Union and Gila River project companies obtained construction financing of $1,395.0 million in the form of floating rate, non-recourse senior secured credit facilities from a bank group. The Union and Gila River project companies each jointly and severally guarantee and cross-collateralize the loans and debts of the other. The loans are non-recourse to TECO Energy, TWG and its subsidiaries that own the project entities.

Credit Facilities

The Union and Gila River project companies, as part of the non-recourse project financing, have credit facilities for commercial letters of credit to facilitate gas purchases and power sales. These facilities are recourse only to the project companies, and not to TECO Energy or its other subsidiaries. At Dec. 31, 2004 and 2003, the credit facilities totaled $265.0 million and $200.0 million, respectively, and aggregate letters of credit outstanding under the facilities totaled $181.4 million and $144.2 million, respectively. The project companies also had an $80 million debt reserve facility, which was cancelled in 2004. The Union and Gila River project companies’ non-recourse credit facilities have maturity dates of June 2006.

SeeNote 23 regarding subsequent events relating to the Union and Gila River projects companies.

Other transactions

In 2004, 2003 and 2002, the company completed several sales transactions and achieved significant milestones towards additional transactions anticipated to be completed in 2005. The completed transactions include: the sale of Frontera in 2004; Prior Energy in 2004;TECO BGA in 2004; TECO AGC, Ltd. in 2004; Hardee Power Partners, Ltd. (HPP) in 2003; and the sale of TECO Coalbed Methane in 2002 (seeNote 16 for additional details). As a result of the accounting treatment of the sale of HPP, the results from operations of HPP through the date of the sale and for all prior periods presented are included in continuing operations. For all periods presented, the results from operations and gains and losses of Frontera, Prior Energy,

TECO BGA, TECO AGC, Ltd., and TECO Coalbed Methane are presented as discontinued operations on the income statement. As of Dec. 31, 2004, no significant assets or liabilities remained relating to these entities, with the exception of certain cash proceeds held by TECO Energy which are subject to restriction, as described inNote 1. SeeNote 25 for a subsequent event for CCC leading to the results from operations of CCC being presented as discontinued operations on the income statement.

At Dec. 31, 2004, assets and liabilities held for sale–other includes BCH Mechanical and TECO Thermal, both investments of TECO Solutions (seeNote 23 for additional details of a subsequent event including BCH Mechanical). For all periods presented, the results from operations of each of these entities are presented as discontinued operations on the income statement.

The following table provides selected components of discontinued operations for transactions other than the Union and Gila River projects (TPGC) transaction:

Components of income from discontinued operations – Other

(millions) For the years ended Dec. 31,	2004			2003			2002
Revenues	$	141.7		$	198.5		$	228.2
(Loss) income from operations		(110.1	)		(132.0	)		43.5
(Loss) gain on sale		(43.4	)		39.7			12.7
(Loss) income before provision for income taxes(1)		(149.1	)		(135.9	)		51.8
(Benefit) provision for income taxes		(48.6	)		(48.8	)		3.9
Net (loss) income from discontinued operations(1)	$	(100.5	)	$	(87.1	)	$	47.9

(1) Results for BCH, TECO Thermal, TECO BGA and Prior Energy include internal financing costs, allocated prior to discontinued operations designation. Internally allocated costs for 2004, 2003 and 2002 were at pretax rates of 8%, 8% and 7%, respectively, based on the average investment in each subsidiary.

Revenues

Revenues for energy marketing operations at Prior Energy and TECO Gas Services are presented on a net basis in accordance with Emerging Issues Task Force No. (EITF) 99-19,Reporting Revenue Gross as a Principal versus Net as an Agent, and EITF 02-3,Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2004, 2003 and 2002 were $128.0 million, $853.4 million and $568.3 million, respectively.

(Loss) Gain on sale

As a result of the sale of Frontera in December 2004, the company recognized a pretax loss of $42.1 million ($27.0 million after-tax). The sales of Prior Energy and TECO AGC, Ltd. in 2004 did not result in a material gain or loss to the company.

As a result of the sale of TECO Coalbed Methane in December 2002, the company recognized pretax gains of $39.7 million ($24.1 million after-tax) and $12.7 million ($7.7 million after-tax) for the years ended Dec. 31, 2003 and Dec. 31, 2002, respectively.

The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items for all other transactions described above:

Assets held for sale – Other

(millions) Dec. 31,	2004		2003
Current assets	$	—	$	96.5
Net property, plant and equipment		7.7		1.5
Other non-current assets		1.5		8.2
Total assets held for sale	$	9.2	$	106.2
Liabilities associated with assets held for sale – Other
(millions) Dec. 31,	2004		2003
Current liabilities	$	3.0	$	55.4
Total liabilities associated with assets held for sale	$	3.0	$	55.4

22. Derivatives and Hedging

From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:

• To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS;

• To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its other affiliates;

• To limit the exposure to electricity, natural gas and fuel oil price fluctuations related to the operations of natural gas-fired and fuel oil-fired power plants at TWG;

• To limit the exposure to price fluctuations for physical purchases of fuel at TECO Transport; and

• To limit the exposure to Section 29 tax credits from TECO Coal’s synthetic fuel produced as a result of changes to the reference price of domestically produced oil.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. For unregulated operations, the company uses derivative instruments primarily to optimize the value of physical assets, including generation capacity, natural gas production, and natural gas delivery.

The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.

The company applies the provisions of FAS 133,Accounting for Derivative Instruments and Hedging Activities, as amended by FAS 138,Accounting for Certain Derivative Instruments and Certain Hedging Activity and FAS 149,Amendment on Statement 133 on Derivative Instruments and Hedging Activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or the loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of its reclassification. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the amount paid or received on the underlying physical transaction.

At Dec. 31, 2004 and 2003, respectively, TECO Energy and its affiliates had derivative assets (current and non-current) totaling $3.8 million and $21.1 million, and liabilities (current and non-current) totaling $12.0 million and $12.0 million. At Dec. 31, 2004 and 2003, accumulated other comprehensive income (AOCI) included $0.5 million and ($4.3) million, respectively, of unrealized after-tax gains (losses), representing the fair value of cash flow hedges whose transactions will occur in the future. Included in AOCI at Dec. 31, 2003 was an unrealized after-tax loss of $14.6 million on interest rate swaps designated as cash flow hedges, reflecting the remaining amount included in AOCI related to cash flow hedges for the period preceding the expected disposition of TPGC (seeNote 21). At Dec. 31, 2002 the unrealized after-tax loss of $37.3 million, included in AOCI, represented the company’s proportionate share of AOCI at TPGC, in accordance with the equity method of accounting. Amounts recorded in AOCI reflect the estimated fair value of derivative instruments designated as hedges, based on market prices as of the balance sheet date. These amounts are expected to fluctuate with movements in market prices and may or may not be realized as a loss upon future reclassification from OCI.

For the years ended Dec. 31, 2004, 2003 and 2002, TECO Energy and its affiliates reclassified amounts from OCI (excluding certain reclassifications for interest rate swaps described below) and recognized net pretax gains (losses) of $1.2 million, ($12.6) million and ($29.0) million, respectively. Amounts reclassified from OCI were primarily related to cash flow hedges of physical purchases of natural gas and physical sales of electricity. For these types of hedge relationships, the loss on the derivative, reclassified from OCI to earnings, is offset by the reduced expense arising from lower prices paid or received for spot purchases of natural gas or decreased revenue from sales of electricity. Conversely, reclassification of a gain from OCI to earnings is offset by the increased cost of spot purchases of natural gas or sales of electricity.

As a result of 1) the suspension of construction on the Dell and McAdams power plants at TWG in 2003 and 2) the maintenance activity on the Frontera Power Station at TWG in early 2003, the company discontinued hedge accounting for purchases of natural gas and sales of electricity which were no longer anticipated to take place within two months of the originally designated time period for delivery. The discontinuation of hedge accounting resulted in a reclassification of a pretax gain of $0.2 million from OCI to earnings, reflecting the fair value of the related derivatives as of the discontinuation date. This gain is included in the net pretax loss reported above for 2002. In addition, as a result of the designation of TPGC as an asset held for sale in 2003, the company concluded that the hedged interest expense for periods beyond the expected disposition date were no longer probable. As a result, the company reclassified pretax losses of $24.0 million ($15.6 million after-tax) and $63.8 million ($41.5 million after tax) from OCI to income from discontinued operations in 2004 and 2003, respectively (seeNote 21). Gains and losses on these derivative instruments, subsequent to the discontinuation of hedge accounting treatment, were recorded in earnings.

Based on the fair value of cash flow hedges at Dec. 31, 2004, pretax losses of $11.5 million are expected to be reversed from OCI to the Consolidated Statements of Income within the next twelve months. However, these losses and other future reclassifications from OCI will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2006.

During the years ended Dec. 31, 2003 and 2002, respectively, Prior Energy, a subsidiary of TECO Energy, recognized pretax gains (losses) of $(1.3) million and $0.7 million, respectively for transactions that were in place to hedge gas storage inventory that qualified for fair value hedge accounting treatment under FAS 133. These gains and losses are included in discontinued operations as a result of the sale of Prior Energy (seeNotes 16and21).

At Dec. 31, 2004, TECO Energy subsidiaries had derivative assets totaling $3.8 million for transactions that were not designated as either a cash flow or fair value hedge. These derivatives are marked-to-market with fair value gains and losses recognized through earnings. For the years ended Dec. 31, 2004, 2003 and 2002, the company recognized gains (losses) on marked-to-market derivatives of $0.8 million, ($6.5) million and ($2.4) million, respectively.

23. Subsequent Events

Tampa Electric accounts receivable securitized borrowing facility

On Jan. 6, 2005, Tampa Electric and TEC Receivables Corp (“TRC”), a wholly-owned subsidiary of Tampa Electric, entered into a $150 million accounts receivable securitized borrowing facility. The assets of TRC are not intended to be generally available to the creditors of Tampa Electric Company. Under the Purchase and Contribution Agreement, Tampa Electric sells and/or contributes to TRC all of its receivables for the sale of electricity or gas to its customers and related rights (the “Receivables”) with the exception of certain excluded receivables and related rights defined in the agreement, and assigns to TRC the deposit accounts into which the proceeds of such Receivables are paid. The Receivables are sold by Tampa Electric to TRC at a discount. Under the Loan and Servicing Agreement among Tampa Electric as Servicer, TRC as Borrower, certain lenders named therein and Citicorp North America, Inc. as Program Agent, TRC may borrow up to $150 million to fund its acquisition of the Receivables under the Purchase Agreement. TRC secures such borrowings with a pledge of all of its assets including the Receivables and deposit accounts assigned to it. Tampa Electric will acts as Servicer to service the collection of the Receivables. TRC pays program and liquidity fees based on Tampa Electric’s credit ratings. The terms of the Loan and Servicing Agreement include the following financial covenants: (i) for the 12-months ending each quarter-end, the ratio of Tampa Electric’s earnings before interest, taxes, depreciation and amortization (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, as defined in the agreement, must not exceed 60% and (iii) certain dilution and delinquency ratios with respect to the Receivables, set at levels substantially above historic averages, must be maintained.

Sale of BCH Mechanical, Inc.

On Jan. 7, 2005, an indirect subsidiary of TECO Energy completed the disposal of its 100% interest in BCH Mechanical, Inc. (“BCH”) pursuant to a Stock Purchase Agreement dated as of Dec. 31, 2004. The purchaser of BCH was BCH Holdings, Inc., the majority owner of which is Daryl W. Blume, who was a Vice President of BCH and one of the owners of BCH when it was purchased by a subsidiary of TECO Energy in September 2000. Under the transaction, TECO Energy retained BCH’s net working capital determined as of Dec. 31, 2004, and certain other existing obligations. As a result of asset and goodwill impairments recorded in the fourth quarter 2004 as part of the annual impairment testing, no additional gain or loss was recorded as a result of the completion of the sale (seeNote 18). See theOther transactions section ofNote 21 for additional details relating to this disposition.

Final settlement of Equity Security Units

On Jan. 14, 2005, the final settlement rate for TECO Energy’s remaining outstanding 7,208,927 equity security units (“units”) (NYSE: TE-PRU) that were not tendered in the early settlement offer completed in August 2004 was set based on the average trading price of TECO Energy common stock from the 20 consecutive trading days ending Jan. 12, 2005, as required under the terms of the units. As a result of the final settlement of the purchase contract component of the units, the units ceased trading on the NYSE before the opening of the market on Jan. 14, 2005. On Jan. 18, 2005, each holder of the TECO Energy units purchased from TECO Energy 0.9509 shares of TECO Energy common stock per unit for $25 per share. The cash for the unit holders’ purchase obligation was satisfied from the proceeds received upon the maturity of a portfolio of U.S. Treasury securities acquired in connection with the October 2004 remarketing of the trust preferred securities to TECO Capital Trust II. As a result, TECO Energy issued 6.85 million shares of common stock on Jan. 18, 2005 and received approximately $180 million of proceeds from the settlement.

Transfer of Union and Gila project companies

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”). Because two members of the 40-member lending group failed to agree to the consensual transfer, 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. 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. The company also consented to the Joint Plan. The project entities are seeking approval of a schedule that contemplates confirmation of the Joint Plan in the March 2005 through May 2005 time frame.

In addition to the Master Settlement Agreement, 100% of the project lenders approved the Master Release Agreement (the “Release”) providing for release of all claims against the company 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 payment by the company of the $30 million for settlement of all previous existing financial obligations is made. Also on Jan. 24, 2005, the project entities received FERC approval of the transfer of the ownership to the bank lending group.

FPSC ruling on waterborne fuel transportation contract

In October 2004, Tampa Electric filed with the FPSC, a motion for clarification and reconsideration of the disallowance of recovery of costs under its waterborne transportation contract with TECO Transport (see Note 13). On Mar. 1, 2005, the FPSC heard oral arguments on the motion and denied Tampa Electric’s request for reconsideration and clarification. This decision by the FPSC had no additional impact on Tampa Electric’s results as of Dec. 31, 2004.

24. Quarterly Data (unaudited)

Financial data by quarter is as follows:

(millions, except per share amounts) Quarter ended	Dec. 31			Sep. 30(1)			Jun. 30(1)			Mar. 31(1)
2004
Revenues	$	656.4		$	698.1		$	668.9		$	616.0
(Loss) income from operations	$	(590.2	)	$	76.4		$	81.7		$	51.8
Net (loss) income
Net (loss) income from continuing operations(3)	$	(351.1	)	$	45.8		$	(81.9	)	$	31.7
Net (loss) income(3)	$	(487.6	)	$	41.3		$	(108.2	)	$	2.5
Earnings per share (EPS) — basic
EPS from continuing operations	$	(1.76	)	$	0.23		$	(0.43	)	$	0.17
EPS	$	(2.44	)	$	0.21		$	(0.57	)	$	0.01
Earnings per share (EPS) — diluted
EPS from continuing operations	$	(1.76	)	$	0.23		$	(0.43	)	$	0.17
EPS	$	(2.44	)	$	0.21		$	(0.57	)	$	0.01
Dividends paid per common share	$	0.19		$	0.19		$	0.19		$	0.19
Stock price per common share(2)
High	$	15.49		$	13.57		$	14.60		$	15.38
Low	$	13.40		$	11.87		$	11.30		$	13.86
Close	$	15.35		$	13.53		$	11.99		$	14.63
Quarter ended	Dec. 31(1)			Sep. 30(1)			Jun. 30 (1)			Mar. 31 (1)
2003
Revenues	$	592.3		$	706.5		$	650.0		$	614.1
(Loss) income from operations	$	(19.1	)	$	90.6		$	96.2		$	(6.5	)
Net (loss) income
Net (loss) income from continuing operations	$	23.7		$	28.6		$	66.8		$	(18.4	)
Net (loss) income(4)	$	(790.7	)	$	(19.5	)	$	(101.9	)	$	2.7
Earnings per share (EPS) — basic
EPS from continuing operations	$	0.13		$	0.16		$	0.38		$	(0.10	)
EPS	$	(4.21	)	$	(0.11	)	$	(0.58	)	$	0.02
Earnings per share (EPS) — diluted
EPS from continuing operations	$	0.12		$	0.16		$	0.38		$	(0.10	)
EPS	$	(4.20	)	$	(0.11	)	$	(0.58	)	$	0.02
Dividends paid per common share	$	0.19		$	0.19		$	0.19		$	0.355
Stock price per common share(2)
High	$	14.85		$	14.20		$	13.69		$	17.00
Low	$	11.80		$	11.50		$	10.05		$	9.47
Close	$	14.41		$	13.82		$	11.99		$	10.63

(1) Amounts shown include reclassifications to reflect discontinued operations as discussed inNote 21.

(2) Trading prices for common shares.

(3) Second and fourth quarter results include impairment charges as described inNote 17 andNote 18.

(4) Fourth quarter results include impairment charges related to TPGC, as described inNote 18.

25. Sale of Commonwealth Chesapeake Company

On Jan. 13, 2005, an indirect subsidiary of TECO Energy entered into a Purchase Agreement to sell its membership interest in Commonwealth Chesapeake Company, LLC (CCC), the owner of the Commonwealth Chesapeake Power Station in Virginia, to an affiliate of Tenaska Power Fund, L.P. The sale closed on Apr. 19, 2005. Proceeds from the sale were approximately $89 million after consideration for the value of working capital less transaction-related expenses. As of a result of asset impairments recorded in the fourth quarter 2004 as part of annual impairment testing, the sale transaction did not result in a material gain or loss (seeNote 18). The sale is subject to certain ordinary and customary post-closing adjustments in working capital items, which are not expected to be material. As a result of entering the agreement to sell CCC during the first quarter of 2005, CCC qualified for discontinued operations. Accordingly, CCC’s results for all periods herein have been restated to reflect the operations of CCC in discontinued operations (see the Other transactions section ofNote 21).

A summary of the operating results of Commonwealth Chesapeake for 2004, 2003, and 2002 is as follows:

(millions) For the years ended Dec. 31,	2004			2003			2002
Revenues	$	29.7		$	35.3		$	23.1
(Loss) income from operations		(68.9	)		(62.6	)		5.0
(Benefit) provision for income taxes		(20.0	)		(23.6	)		1.9
Net (loss) income from discontinued operations	$	(48.9	)	$	(39.0	)	$	3.1

The assets and liabilities are not material to the financial statements.

SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

TECO ENERGY, INC.

PARENT COMPANY ONLY

Condensed Balance Sheets

Assets (millions)	Dec. 31, 2004			Dec. 31, 2003
Current assets
Cash and cash equivalents	$	70.4		$	28.0
Restricted cash		7.0			6.9
Advances to affiliates		3,069.6			3,078.4
Accounts receivable from affiliates		13.9			3.4
Other current assets		1.2			11.4
Total current assets		3,162.1			3,128.1
Other assets
Investment in subsidiaries		568.7			1,381.5
Deferred income taxes		483.7			293.5
Other assets		35.3			46.7
Total other assets		1,087.7			1,721.7
Total assets	$	4,249.8		$	4,849.8
Liabilities and capital
Current liabilities
Notes payable	$	—		$	37.5
Accounts payable to affiliates		0.4			0.3
Accounts payable		8.9			21.9
Interest payable		19.6			19.2
Other current liabilities		7.1			9.1
Total current liabilities		36.0			88.0
Other liabilities
Advances from affiliates		283.6			233.9
Deferred income taxes		318.9			117.4
Long-term debt
Junior subordinated		277.7			669.3
Others		1,964.4			1,958.8
Other liabilities		85.3			104.7
Total other liabilities		2,929.9			3,084.1
Capital
Common equity		199.7			187.8
Additional paid in capital		1,489.4			1,220.8
Retained earnings (deficit)		(357.6	)		339.5
Accumulated other comprehensive income		(43.8	)		(55.8	)
Common equity		1,287.7			1,692.3
Unearned compensation		(3.8	)		(14.6	)
Total capital		1,283.9			1,677.7
Total liabilities and capital	$	4,249.8		$	4,849.8

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

SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

TECO ENERGY, INC.

PARENT COMPANY ONLY

Condensed Statements of Income

For the years ended Dec. 31, (millions)	2004			2003			2002
Revenues	$	1.7		$	4.4		$	6.7
Expenses
Administrative and general expenses		19.4			7.2			8.6
Restructuring charges		—			2.6			—
Total expenses		19.4			9.8			8.6
Income from operations		(17.7	)		(5.4	)		(1.9	)
Loss on debt extinguishment		(4.4	)		—			(34.1	)
(Losses) earnings from investments in subsidiaries		(470.3	)		(873.2	)		363.8
Interest income (expense)
Interest income
Affiliates		78.2			139.3			120.0
Interest expense
Affiliates		(29.6	)		(43.0	)		(40.1	)
Others		(178.9	)		(171.9	)		(103.4	)
Total interest expense		(130.3	)		(75.6	)		(23.5	)
(Loss) income before income taxes		(622.7	)		(954.2	)		304.3
(Benefit) for income taxes		(70.7	)		(48.0	)		(25.8	)
Net (loss) income from continuing operations		(552.0	)		(906.2	)		330.1
Cumulative effect of change in accounting principle, net of tax		—			(3.2	)		—
Net (loss) income	$	(552.0	)	$	(909.4	)	$	330.1

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

SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

TECO ENERGY, INC.

PARENT COMPANY ONLY

Condensed Statements of Cash Flows

For the years ended Dec. 31, (millions)	2004			2003			2002
Cash flows from operating activities	$	91.7		$	10.2		$	(82.4	)
Cash flows from investing activities
Investment in subsidiaries		28.7			156.7			(232.4	)
Dividends from subsidiaries		219.4			296.0			316.1
Net change in affiliate advances		32.9			(741.2	)		(1,230.8	)
Cash flows from investing activities		281.0			(288.5	)		(1,147.1	)
Cash flows from financing activities
Dividends to shareholders		(145.2	)		(165.2	)		(215.8	)
Common stock		10.2			136.6			572.6
Proceeds from long-term debt – others		—			296.8			1,510.9
Repayment of long-term debt – others		(122.7	)		—			(600.0	)
Early exchange of equity units		(17.7	)		—			—
Net increase (decrease) in short-term debt		(37.5	)		(312.5	)		350.0
Equity contract adjustment payments		(17.4	)		(20.3	)		(15.3	)
Cash flows from financing activities		(330.3	)		(64.6	)		1,602.4
Net (decrease) increase in cash and cash equivalents		42.4			(342.9	)		372.9
Cash and cash equivalents at beginning of period		28.0			370.9			(2.0	)
Cash and cash equivalents at end of period	$	70.4		$	28.0		$	370.9

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

SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

TECO ENERGY, INC.

PARENT COMPANY ONLY

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. Basis of Presentation

TECO Energy, Inc., on a stand alone basis, (the parent company) has accounted for majority-owned subsidiaries using the equity basis of accounting. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the headingNotes to Consolidated Financial Statements in the2004 Annual Report, which information is hereby incorporated by reference.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles. Actual results could differ from those estimates.

2. Long-term Obligations

SeeNote 7to the TECO EnergyConsolidated Financial Statements for a description and details of long-term debt obligations of the parent company.

3. Commitments and Contingencies

SeeNote 12 to the TECO EnergyConsolidated Financial Statements for a description of all material contingencies and guarantees outstanding of the parent company.

4. Subsequent Events

SeeNote 23 to the TECO EnergyConsolidated Financial Statements for a description of events that occurred subsequent to Dec. 31, 2004 that affected the parent company. These include the sale of BCH Mechanical; and the final settlement of Equity Security units that resulted in the parent company issuing 6.85 million shares of common stock on Jan. 18, 2005 and receiving approximately $180 million of proceeds from this settlement.

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TECO ENERGY, INC.

For the Years Ended Dec. 31, 2004, 2003 and 2002

(millions)

	Balance at Beginning of Period		Additions						Payments & Deductions (1)		Balance at End of Period
			Charged to Income			Other Charges
Allowance for Uncollectible Accounts:
2004	$	4.5	$	8.4	(2)	$	0.4		$	5.3	$	8.0
2003	$	6.6	$	7.0		$	(1.8	)(3)	$	7.3	$	4.5
2002	$	7.1	$	7.9		$	0.2		$	8.6	$	6.6

(1) Write-off of individual bad debt accounts

(2) Includes $3.1 million charged to discontinued operations for asset impairments for BCH

(3) Includes $1.1 million of bad debt reserves for Prior Energy and BGA that were moved to assets held for sale