UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2003

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File No. 1-8180

TECO ENERGY, INC.

(Exact name of each Registrant as specified in its charter)

Florida	59-2052286
(state of incorporation)	(I.R.S. Employer Identification Number)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(address of principal executive offices)

(813) 228-4111

(telephone number)

Commission File No. 1-5007

TAMPA ELECTRIC COMPANY

(Exact name of each Registrant as specified in its charter)

Florida	59-0475140
(state of incorporation)	(I.R.S. Employer Identification Number)

TECO Plaza

702 N. Franklin Street

Tampa, Florida 33602

(address of principal executive offices)

(813) 228-4111

(telephone number)

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

Title of each class	Name of each exchange on which registered
TECO Energy, Inc.
Common Stock, $1.00 par value	New York Stock Exchange
Common Stock Purchase Rights	New York Stock Exchange
Equity Security Units	New York Stock Exchange

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

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

Indicate by check mark whether TECO Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).  Yes  x  No  ¨

Indicate by check mark whether Tampa Electric Company is an accelerated filer (as defined in Exchange Act Rule 12b-2).  Yes  x  No  ¨

Number of shares of TECO Energy, Inc.’s common stock outstanding as of July 31, 2003 was 176,669,023.

As of July 31, 2003, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (H) (1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

This combined Form 10-Q represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes representations only as to information relating to itself and its subsidiaries.

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the financial position of TECO Energy, Inc. and subsidiaries as of June 30, 2003 and 2002, and the results of their operations and cash flows for the periods ended June 30, 2003 and 2002. The results of operations for the three-month and six-month periods ended June 30, 2003 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2003. References should be made to the explanatory notes affecting the consolidated income and balance sheet accounts contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2002 and to the notes on pages 9 through 31 of this report.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page No.
Consolidated Balance Sheets, June 30, 2003 and Dec. 31, 2002	3-4
Consolidated Statements of Income for the three-month and six-month periods ended June 30, 2003 and 2002	5-6
Consolidated Statements of Comprehensive Income for the three-month and six-month periods ended June 30, 2003 and 2002	7
Consolidated Statements of Cash Flows for the six-month periods ended June 30, 2003 and 2002	8
Notes to the Consolidated Financial Statements	9-31

2

TECO ENERGY, INC.

Consolidated Balance Sheets

Unaudited

Assets (millions)	June 30, 2003			Dec. 31, 2002
Current assets
Cash and cash equivalents	$	267.9		$	411.1
Restricted cash		91.4			1.6
Short-term investments		15.5			—
Receivables, less allowance for uncollectibles of $4.5 million and $6.6 million at June 30, 2003 and Dec. 31, 2002, respectively		524.5			422.7
Current notes receivable		23.0			235.1
Current derivative assets		52.5			12.5
Inventories, at average cost
Fuel		114.0			113.7
Materials and supplies		105.5			96.1
Prepayments and other current assets		103.1			30.4
Total current assets		1,297.4			1,323.2
Property, plant and equipment
Utility plant in service
Electric		7,397.8			5,054.4
Gas		762.5			746.7
Construction work in progress		1,640.0			1,556.8
Other property		870.7			857.4
Property, plant and equipment, at original cost		10,671.0			8,215.3
Accumulated depreciation		(2,812.3	)		(2,751.3	)
Total property, plant and equipment (net)		7,858.7			5,464.0
Other assets
Deferred income taxes		482.8			340.2
Long-term derivative asset		12.1			0.1
Other investments		704.5			845.3
Regulatory assets		178.2			163.2
Investment in unconsolidated affiliates		325.2			149.2
Goodwill and other intangible assets		106.6			204.8
Deferred charges and other assets		186.3			147.8
Total other assets		1,995.7			1,850.6
Total assets	$	11,151.8		$	8,637.8

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

3

TECO ENERGY, INC.

Consolidated Balance Sheets - continued

Unaudited

Liabilities and capital (millions)	June 30, 2003			Dec. 31, 2002
Current liabilities
Long-term debt due within one year	$	48.2		$	127.1
Notes payable		417.5			360.5
Accounts payable		363.5			377.4
Customer deposits		99.0			94.6
Current derivative liability		94.4			3.9
Interest accrued		149.8			49.8
Taxes accrued		39.4			95.9
Total current liabilities		1,211.8			1,109.2
Other liabilities
Deferred income taxes		526.0			495.0
Investment tax credits		25.2			27.5
Long-term derivative liability		57.3			0.2
Regulatory liabilities		96.7			98.1
Deferred credits and other liabilities		272.0			321.5
Long-term debt, less amount due within one year
Recourse		3,662.4			3,112.7
Non-recourse		2,275.3			211.6
Total other liabilities		6,914.9			4,266.6
Minority interest		(1.1	)		1.2
Company preferred securities		649.1			649.1
Capital
Common equity (400 million shares authorized; 176.6 million and 175.8 million outstanding at June 30, 2003 and Dec. 31, 2002, respectively)		176.6			175.8
Additional paid in capital		1,100.7			1,094.5
Retained earnings		1,218.8			1,413.7
Accumulated other comprehensive income		(94.5	)		(41.2	)
Common equity		2,401.6			2,642.8
Unearned compensation		(24.5	)		(31.1	)
Total capital		2,377.1			2,611.7
Total liabilities and capital	$	11,151.8		$	8,637.8

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

4

TECO ENERGY, INC.

Consolidated Statements of Income

Unaudited

(millions, except per share amounts)	Three months ended June 30,
	2003			2002
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $19.4 million in 2003 and $18.7 million in 2002)	$	501.7		$	481.1
Unregulated		235.5			196.6
Total revenues		737.2			677.7
Expenses
Regulated operations
Fuel		94.2			87.7
Purchased power		33.6			49.9
Cost of natural gas sold		52.3			38.2
Other		61.5			68.2
Other operations		236.4			174.0
Maintenance		36.6			40.9
Depreciation		96.4			76.9
Goodwill impairment		95.2			—
Taxes, other than income		43.8			44.2
Total expenses		750.0			580.0
(Loss) income from operations		(12.8	)		97.7
Other (expense) income
Allowance for other funds used during construction		4.1			5.7
Other income		34.3			15.0
Loss on joint venture termination		(153.9	)		—
Income (loss) from equity investments		2.3			(1.6	)
Total other (expense) income		(113.2	)		19.1
Interest charges
Interest expense		77.0			33.9
Distribution on preferred securities		11.3			9.9
Allowance for borrowed funds used during construction		(1.6	)		(2.2	)
Total interest charges		86.7			41.6
(Loss) income before provision for income taxes		(212.7	)		75.2
(Benefit) for income taxes		(87.4	)		(5.7	)
Net (loss) income from continuing operations before minority interests		(125.3	)		80.9
Minority interest		23.4			—
Net (loss) income from continuing operations		(101.9	)		80.9
Discontinued operations
Income from discontinued operations		—			1.5
Income tax (benefit)		—			(3.3	)
Total discontinued operations		—			4.8
Cumulative effect of change in accounting principle, net of tax		—			—
Net (loss) income	$	(101.9	)	$	85.7

	Basic					Diluted
	Three months ended June 30,					Three months ended June 30,
	2003			2002		2003			2002
Average common shares outstanding		176.4			144.2		176.6			144.7
Earnings per share from continuing operations	$	(0.58	)	$	0.56	$	(0.58	)	$	0.56
Earnings per share	$	(0.58	)	$	0.59	$	(0.58	)	$	0.59
Dividends paid per common share outstanding	$	0.190		$	0.355

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

5

TECO ENERGY, INC.

Consolidated Statements of Income

Unaudited

(millions, except per share amounts)	Six months ended June 30,
	2003			2002
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $38.2 million in 2003 and $35.9 million in 2002)	$	969.7		$	905.2
Unregulated		426.0			379.1
Total revenues		1,395.7			1,284.3
Expenses
Regulated operations
Fuel		145.3			154.0
Purchased power		73.0			76.9
Cost of natural gas sold		123.1			73.5
Other		122.5			131.7
Other operations		419.1			337.5
Maintenance		71.2			80.9
Depreciation		176.2			154.9
Asset impairment		104.1			—
Goodwill impairment		95.2			—
Taxes, other than income		87.2			87.9
Total expenses		1,416.9			1,097.3
(Loss) income from operations		(21.2	)		187.0
Other (expense) income
Allowance for other funds used during construction		11.7			10.0
Other income		47.1			30.3
Loss on joint venture termination		(153.9	)		—
(Loss) from equity investments		(3.4	)		(1.9	)
Total other (expense) income		(98.5	)		38.4
Interest charges
Interest expense		133.1			73.4
Distribution on preferred securities		22.6			18.9
Allowance for borrowed funds used during construction		(4.5	)		(3.8	)
Total interest charges		151.2			88.5
(Loss) income before provision for income taxes		(270.9	)		136.9
(Benefit) for income taxes		(126.3	)		(13.9	)
Net (loss) income from continuing operations before minority interests		(144.6	)		150.8
Minority interest		23.4			—
Net (loss) income from continuing operations		(121.2	)		150.8
Discontinued operations
Income from discontinued operations (including gain on disposal of $37.4 million in 2003)		38.2			3.7
Income tax provision (benefit)		15.1			(6.6	)
Total discontinued operations		23.1			10.3
Cumulative effect of change in accounting principle, net of tax		(1.1	)		—
Net (loss) income	$	(99.2	)	$	161.1

	Basic					Diluted
	Six months ended June 30,					Six months ended June 30,
	2003			2002		2003			2002
Average common shares outstanding		176.2			142.3		176.5			142.7
Earnings per share from continuing operations	$	(0.69	)	$	1.06	$	(0.69	)	$	1.06
Earnings per share	$	(0.56	)	$	1.13	$	(0.56	)	$	1.13
Dividends paid per common share outstanding	$	0.545		$	0.700

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

6

TECO ENERGY, INC.

Consolidated Statements of Comprehensive Income

Unaudited

(millions)	Three months ended June 30,						Six months ended June 30,
	2003			2002			2003			2002
Net (loss) income	$	(101.9	)	$	85.7		$	(99.2	)	$	161.1
Other comprehensive (loss) income, net of tax
Foreign currency translation adjustments		0.4			—			1.2			—
Net unrealized (losses) gains on cash flow hedges		(44.8	)		(8.5	)		(54.5	)		4.2
Other comprehensive (loss) income, net of tax		(44.4	)		(8.5	)		(53.3	)		4.2
Comprehensive (loss) income	$	(146.3	)	$	77.2		$	(152.5	)	$	165.3

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

7

TECO ENERGY, INC.

Consolidated Statements of Cash Flows

Unaudited

(millions)	Six months ended June 30,
	2003			2002
Cash flows from operating activities
Net (loss) income	$	(99.2	)	$	161.1
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation		176.2			154.9
Deferred income taxes		(83.4	)		(69.7	)
Investment tax credits, net		(2.2	)		(2.2	)
Allowance for funds used during construction		(16.2	)		(13.9	)
Amortization of unearned compensation		8.5			6.7
Cumulative effect of change in accounting principle, pretax		1.8			—
Gain on asset sales, pretax		(71.8	)		—
Equity in earnings of unconsolidated affiliates		5.5			4.5
Minority interest		(23.4	)		—
Asset impairment, pretax		104.1			—
Goodwill impairment, pretax		95.2			—
Loss on joint venture termination, pretax		153.9			—
Deferred recovery clause		(17.4	)		51.3
Refund to customers		—			(2.0	)
Receivables, less allowance for uncollectibles		(67.9	)		(56.7	)
Inventories		(0.1	)		(32.8	)
Prepayments and other deposits		(47.2	)		5.1
Taxes accrued		(81.4	)		45.2
Interest accrued		21.7			11.8
Accounts payable		(58.7	)		35.0
Other		56.0			24.1
Cash flows from operating activities		54.0			322.4
Cash flows from investing activities
Capital expenditures		(310.7	)		(578.8	)
Allowance for funds used during construction		16.2			13.9
Purchase of minority interest		—			(9.9	)
Net proceeds from sales of assets		149.7			—
Restricted cash		(52.8	)		—
Investment in unconsolidated affiliates		(4.6	)		1.4
Other non-current investments		(66.5	)		(336.7	)
Cash flows from investing activities		(268.7	)		(910.1	)
Cash flows from financing activities
Dividends		(96.0	)		(98.0	)
Common stock		4.6			360.1
Proceeds from long-term debt		648.1			842.7
Minority interest		20.4			—
Restricted cash		(20.4	)		(146.3	)
Repayment of long-term debt		(498.5	)		(412.0	)
Settlement of joint venture termination obligation		(33.5	)		—
Net increase (decrease) in short-term debt		57.0			(357.7	)
Issuance of preferred securities		—			435.7
Equity contract adjustment payments		(10.2	)		(5.1	)
Cash flows from financing activities		71.5			619.4
Net (decrease) increase in cash and cash equivalents		(143.2	)		31.7
Cash and cash equivalents at beginning of period		411.1			108.4
Cash and cash equivalents at end of period	$	267.9		$	140.1

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

8

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. (TECO Energy or the company) and its wholly-owned subsidiaries.

The equity method of accounting is used to account for investments in partnership arrangements in which TECO Energy or its subsidiary companies do not have majority ownership or exercise control.

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

All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP).

Restricted Cash

Restricted cash is comprised of $38 million of cash held in escrow under the sale agreement for the 49.5-percent interest of TECO Coal’s synfuel production facilities pending a private letter ruling (PLR) from the Internal Revenue Service (IRS), and $53 million at TPS primarily related to cash to be used only for construction-related purposes at the Union and Gila River power stations. Following the delivery of a PLR, approximately $28 million will be released. However, over time, up to $50 million of cash from the synfuel facility sale will accumulate in escrow to provide credit support for the company’s obligations under the sale agreement due to the company’s current credit rating.

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. Capitalized costs were transferred to construction in progress when financing had been obtained and construction activity had commenced. In accordance with Statement of Position (“SOP”) 98-5, Reporting on the Costs of Start-up Activities, start-up costs and organization costs were 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. TECO-Panda Generating Company, L.P. (TPGC) capitalized a portion of amortized debt financing costs in the amount of $1.0 million and $2.2 million for the three months ended June 30, 2003 and 2002, respectively, and $2.6 million and $4.3 million for the six months ended June 30, 2003 and 2002.

Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates are accounted for using the equity method of accounting. The percentage ownership interest for each investment is presented in the following table.

TECO Energy and Subsidiaries’ Investments in Unconsolidated Affiliates

	June 30, 2003	Dec. 31, 2002
TECO Power Services (TPS)
TPGC (1)	100	50
PLC Development Holdings, LLC, (PLC) (2)	50	—
Empresa Electricia de Guatemala, S.A. (EEGSA)	24	24
Hamakua Energy Partners, L.P.	50	50
Hamakua Land Partnership, LLP	50	50
TECO Propane Ventures (TPV)
US Propane	38	38
TECO Energy Services
TECO Thermal Systems, Inc.	50	50

9

TECO Energy and Subsidiaries’ Investments in Unconsolidated Affiliates - continued

	June 30, 2003	Dec. 31, 2002
TECO Fiber
Litestream Technologies, LLC	36	65
TECO Properties
Hernando Oaks, LLC	50	50
Brandon Properties Partners, LTD.	50	50
Walden Woods Business Center, LTD.	50	50

(1) TPS consolidated TPGC effective April 1, 2003 and received Panda’s 50-percent interest in June 2003. See Note 11 for a detailed discussion.

(2) TPS holds an indirect ownership interest in Texas Independent Energy, L.P. (TIE) through PLC. See Notes 11, 15 and 19 for a discussion of the investment.

Revenue Recognition

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 Peoples Gas System (PGS)) retail businesses and the prices charged to customers are regulated by the Florida Public Service Commission (FPSC). Tampa Electric’s wholesale business is regulated by the Federal Energy Regulatory Commission (FERC). See Note 5 for a discussion of the applicability of Financial Accounting Standard (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 for long-term engineering or construction-type contracts at TECO Energy Services (formerly TECO BGA and BCH Mechanical) are recognized under the same method, which includes estimates of the total costs for the project compared to the estimated work progress already completed for the contract.

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 three months and six months ended June 30, 2003 were $225.2 million and $538.7 million, respectively, compared to $133.6 million and $258.3 million, respectively, for the three and six months ended June 30, 2002.

Purchased Power

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $33.6 million and $73.0 million, respectively, for the three months and six months ended June 30, 2003, compared to $49.9 million and $76.9 million, respectively, for the three months and six months ended June 30, 2002. These purchased power costs are recoverable through an FPSC-approved cost recovery clause.

Total unregulated purchased power for the three months and six months ended June 30, 2003 were $19.1 million and $25.9 million, respectively, compared to purchases of $12.5 million and $19.1 million, respectively for the three months and six months ended June 30, 2002.

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 utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.9% for the six months ended June 30, 2003 and 4.2% for the six months ended June 30, 2002. For the three months ended June 30, 2003, Tampa Electric recognized depreciation expense of approximately $13 million related to accelerated depreciation of certain Gannon power station coal-fired assets, in accordance with a regulatory order issued by the FPSC. This amount reflects two quarters of accelerated depreciation expense, as required to be recognized under the regulatory order issued in the second quarter of 2003.

The original cost of utility plant retired or otherwise disposed of and the cost of removal, or dismantlement, less salvage value are charged to accumulated depreciation. As regulated utilities, Tampa Electric and Peoples Gas 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

10

removal in accumulated depreciation. At Jan. 1, 2003, the estimated accumulated cost of removal and dismantlement included in net accumulated depreciation was approximately $442.0 million. At June 30, 2003, the cost of removal and dismantlement component of accumulated depreciation was approximately $451 million. The implementation of FAS 143, Accounting for Asset Retirement Obligations, in 2003 resulted in an increase in the carrying amount of long-lived assets. The adjusted capitalized amount is depreciated over the remaining useful life of the asset. See Note 6.

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 Statement of Income. These amounts totaled $19.4 million and $18.7 million, respectively, for the three months ended June 30, 2003 and 2002, and $38.2 million and $35.9 million, respectively, for the six months ended June 30, 2003 and 2002. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statement of Income in “Taxes, other than income.” For the three months ended June 30, 2003 and 2002, these totaled $19.4 million and $18.7 million, respectively, and for the six months ended June 30, 2003 and 2002, they totaled $38.1 million and $35.9 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 segment of a business.

In accordance with FAS 144, the company assesses whether there has been an other-than-temporary impairment of its long-lived assets and certain intangibles held and used by the company when such impairment indicators exist. Except as discussed in Note 10 relating to certain long-term turbine purchase contracts, no significant events or changes in circumstances occurred during the six months ended June 30, 2003 to indicate an impairment of long-lived 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. 25 and related interpretations in accounting for its stock-based compensation plans. See Note 9 for the pro forma impact that the application of the recognition provisions of FAS 123 would have on reported net income and earnings per share.

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, Accounting for Stock-Based Compensation, 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. The adoption of the disclosure provisions of this standard did not have a material impact on the company’s financial position.

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. One of TECO Energy’s long-term debt issues contains a covenant that requires the company to achieve certain interest coverage levels in order to pay dividends; and a TECO Energy credit facility contains a covenant that could limit the payment of dividends exceeding $40 million in any quarter under certain circumstances if drawn. See Notes 7, 8 and 18 for a more detailed description of significant financial covenants.

Should TECO Energy exercise its right to defer payments on its subordinated notes issued in connection with the issuance of trust preferred securities by TECO Capital Trust I or TECO Capital Trust II, TECO Energy 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.

The primary sources of funds to pay dividends on TECO Energy’s common stock are dividends from its operating companies. Tampa Electric’s first mortgage bond indenture and certain long-term debt at PGS contain restrictions that limit the payment of dividends on the common stock of Tampa Electric (see Note 18). Tampa Electric’s first mortgage bond indenture does not limit loans or advances. 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. As of June 30, 2003 and Dec. 31, 2002, the balances restricted as to transfers to the parent company in the form of loans, advances or cash dividends were less than 21% and 19%, respectively, of consolidated common equity.

11

Reclassifications

Certain prior year amounts were reclassified to conform with the current year presentation. See Revenue Recognition accounting policy related to reporting energy marketing operations on a net basis.

2. Derivatives and Hedging

At June 30, 2003, the company had derivative assets totaling $64.6 million and liabilities totaling $151.7 million. At Dec. 31, 2002, the company had derivative assets totaling $12.6 million and liabilities totaling $4.1 million. At June 30, 2003 and Dec. 31, 2002, accumulated other comprehensive income (OCI) included $86.9 million and $32.4 million, respectively, of unrealized after-tax losses, representing the fair value of cash flow hedges whose transactions will occur in the future. Included in OCI at June 30, 2003 and Dec. 31, 2002 is an unrealized after-tax loss of $80.5 million and $37.3 million, respectively, on interest rate swaps at TPGC (see Note 8). The unrealized loss included in OCI at Dec. 31, 2002 represented the company’s proportionate share of OCI, versus the fully consolidated amount included in OCI at June 30, 2003. Amounts recorded in OCI 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.

As of June 30, 2003, TECO Energy had transactions in place to hedge commodity price risk and interest rate risk that qualify for cash flow hedge accounting treatment under FAS 133. TECO Energy had no reclassification of net pretax gains for the three months ended June 30, 2003, and net pretax gains of $18.7 million for the six months ended June 30, 2003. 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.

Based on the fair value of cash flow hedges at June 30, 2003, pretax losses of $1.4 million are expected to be reversed from OCI to the Consolidated Statement of Income within the next twelve months. However, these gains and other future reclassifications from OCI will fluctuate with movements in the underlying market price of the derivative instruments. Excluding interest rate hedges, the company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2006.

At June 30, 2003, TECO Energy had transactions in place to hedge gas storage inventory that qualify for fair value hedge accounting treatment under FAS 133. During the three months and six months ended June 30, 2003, the company recognized pretax gains of $0.5 million and losses of $1.5 million, respectively, compared to pretax gains of $0.9 million for the six months ended June 30, 2002. There were no amounts recognized to earnings for the three months ended June 30, 2002. For the three months and six months ended June 30, 2003, the company also recognized pretax gains of $0.9 million and $4.2 million, respectively, relating to derivatives that do not qualify for cash flow or fair value hedge accounting treatment that are marked to market, compared to pretax losses of $2.4 million, for the six months ended June 30, 2002. There were no amounts recognized to earnings for the three months ended June 30, 2002.

3. Other Investments

Included in “Other investments” are 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. As of June 30, 2003, UPP had purchased industrial revenue bonds from the county totaling $700.0 million, which equals the amount of borrowings from Union County. Union County’s debt service payments on the bonds equal UPP’s debt service obligations to the county. This agreement with Union County enables the company to invest in the economic development of the county and provides an economic incentive for the company to do so. As of Dec. 31, 2002, TECO Energy did not include TPGC in the Consolidated Balance Sheet (see Note 11).

For the three months ended June 30, 2003, UPP recognized $13.1 million of interest income on the investment in Union County bonds, and $13.1 million of interest expense on the Union County financings due to the consolidation of TPGC. For all other periods presented, income or loss at TPGC was recognized on a net basis by TECO Energy. Interest income on the investment and interest expense on the related long-term debt have been presented on a net basis in the Consolidated Statement of Income, and have no net impact on the company’s results of operation. Principal and interest on the bonds and related long-term debt are due quarterly commencing Sept. 15, 2003 and continuing to final maturity on June 15, 2021. Interest accrued through Sept. 15, 2003 will be payable on that date. The interest rate on the bonds and the related long-term debt is 7.5% per year.

12

The principal maturities of the industrial revenue bonds and the equal principal maturities of the related long-term debt financing, for each of the five years succeeding Dec. 31, 2002 and thereafter are as follows:

Future Minimum Payments for Union County Industrial Revenue Bonds

Year ended Dec. 31:	Amount (millions)
2003	$	7.7
2004		16.2
2005		17.6
2006		19.5
2007		21.4
Later Years		617.6
Total minimum payments	$	700.0

4. Goodwill and Other Intangible Assets

As required under FAS 142, TECO Energy continues to review recorded goodwill and intangibles 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 may be 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.

As a result of the consolidation of TPGC, effective April 1, 2003 (see Note 11), the completion and commercial operation of the Union Power Partners (UPP) plant in June 2003, and the termination of the partnership with Panda Energy in June 2003, management initiated an interim review for the possible impairment of goodwill associated with TPS’ domestic generation reporting units. This evaluation indicated that a probable impairment of goodwill existed. Consequently, the company recorded an estimated pretax impairment charge in June 2003 of $94.5 million to write off all of the goodwill previously recorded at these reporting units subject to the completion of an independent appraisal. This goodwill arose from the previous acquistions of the Commonwealth Chesapeake power station in Virginia and the Frontera power station in Texas. TPS has no remaining domestic goodwill, and as of June 30, 2003, TECO Energy’s total consolidated goodwill was $100.2 million compared to $193.7 million as of Dec. 31, 2002.

The amount of intangible assets recorded at June 30, 2003 was $6.4 million (net of accumulated amortization of $40.1 million) and at Dec. 31, 2002 was $11.1 million (net of accumulated amortization of $35.4 million). For the three months ended June 30, 2003, no amortization expense was recorded compared to $2.3 million in the same period of 2002. For the six months ended June 30, 2003 and 2002, the company recognized amortization expense of $4.7 million and $6.0 million, respectively.

Intangible assets at June 30, 2003 and Dec. 31, 2002 include $6.7 million relating to an indefinite-lived intangible asset arising from gasification technology licenses held by TPS.

5. 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 generally accepted accounting principles 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 June 30, 2003 and Dec. 31, 2002 are presented in the following table:

13

Regulatory Assets and Liabilities

(millions)
	June 30, 2003		Dec. 31, 2002
Regulatory assets:
Regulatory tax asset (1)	$	58.3	$	54.9
Other:
Cost recovery clauses		51.1		34.7
Coal contract buy-out (2)		4.1		5.4
Unamortized refinancing costs (3)		34.0		35.9
Environmental remediation		20.7		20.3
Competitive rate adjustment		5.5		7.4
Other		4.5		4.6
		119.9		108.3
Total regulatory assets	$	178.2	$	163.2
Regulatory liabilities:
Regulatory tax liability (1)	$	33.5	$	36.6
Other:
Deferred allowance auction credits		2.1		2.1
Cost recovery clauses		1.2		2.2
Environmental remediation		20.7		20.3
Transmission and distribution storm reserve		38.0		36.0
Deferred gain on property sales (4)		1.2		0.9
		63.2		61.5
Total regulatory liabilities	$	96.7	$	98.1

(1) Related primarily to plant life. Includes excess deferred taxes of $18.9 million and $20.9 million as of June 30, 2003 and Dec. 31, 2002, respectively.

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

(3) Unamortized refinancing costs:

Related to debt transactions as follows (millions):	Amortized until:
$  50.0	2004
$  51.6	2005
$  22.1	2007
$  25.0	2011
$  50.0	2011
$150.0	2012
$150.0	2012
$  85.9	2014
$  25.0	2021
$100.0	2022

(4) Amortized over a 5-year period with various ending dates.

6. 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 for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under existing or enacted law, statute, 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.

14

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 modifies the valuation and accrual methods used to estimate the fair value of asset retirement obligations.

As a result of the adoption of FAS 143, 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. An after-tax charge of $1.1 million ($1.8 million pretax, net of $0.2 million offset by a regulatory asset at Tampa Electric) was recognized as a change in accounting principle.

For the three months and six months ended June 30, 2003, TECO Energy recognized $0.3 million and $0.6 million, respectively, of accretion expense associated with asset retirement obligations. During these periods, no new retirement 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 three months and six months ended June 30, 2002.

7. Short-Term Debt

At June 30, 2003 and Dec. 31, 2002, the following credit facilities and related borrowings existed:

Credit Facilities

	June 30, 2003						Dec. 31, 2002
(millions)	Credit Facilities		Borrowings Outstanding		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding		Letters of Credit Outstanding
Recourse:
Tampa Electric
1-year facility	$	300.0	$	30.0	$	—	$	300.0	$	—	$	—
TECO Energy
1-year term loan		350.0		350.0		—		350.0		350.0		—
TECO Energy
18-month facility		150.0		—		—		—		—		—
TECO Energy
1-year facility		37.5		37.5		—		—		—		—
TECO Energy
3-year facility		350.0		—		159.2		350.0		—		179.8
		1,187.5		417.5		159.2		1,000.0		350.0		179.8
Non-recourse:
TECO Power Services
5-yr TPGC project facilities (1) (2)		200.0		—		120.8		—		—		—
5-yr TPGC project facilities (2)		80.0		—		—		—		—		—
		280.0		—		120.8		—		—		—
Total	$	1,467.5	$	417.5	$	280.0	$	1,000.0	$	350.0	$	179.8

(1) Letter of credit facility only.

(2) TPGC was not consolidated at Dec. 31, 2002.

15

The weighted average interest rate on outstanding notes payable at June 30, 2003 and Dec. 31, 2002 was 2.17% and 1.88%, respectively. At June 30, 2003 and Dec. 31, 2002, notes payable consisted of the following:

Notes Payable

(millions)	June 30, 2003		Dec. 31, 2002
Credit facilities outstanding	$	417.5	$	350.0
Commercial paper		—		10.5
Total notes payable	$	417.5	$	360.5

On June 24, 2003, TECO Energy entered into a $37.5 million credit facility with four banks, secured by the Union and Gila River assets. The proceeds from the credit facility were used in the termination of the partnership with Panda. This credit facility has debt-to-capital covenants similar to those of the other TECO Energy credit facilities, but also includes an earnings before interest, taxes, depreciation and amortization (EBITDA) to interest coverage requirement of 2.5 times, a limitation on liens of not more than 60% of the fair value of assets, and a restriction on the sale of any of the company’s interest in the Union and Gila River projects. This loan can be repaid without penalty at any time with three business days’ notice.

On April 9, 2003, TECO Energy entered into a $350 million unsecured credit facility with Merrill Lynch. The term of the new credit facility is for up to eighteen months. The Merrill Lynch credit facility requires TECO Energy’s debt-to-capital ratio, as defined in the credit agreement not to exceed 65%. This facility also has covenants that, if the facility is drawn, could limit the payment of dividends exceeding $40 million in any quarter unless, prior to the payment of any dividends, the company delivers to Merrill Lynch liquidity projections satisfactory to Merrill Lynch demonstrating that the company will have sufficient cash or cash equivalents to pay both the dividends contemplated and each of the three quarterly dividends next scheduled to be paid on its common stock.

Tampa Electric Company’s $300 million credit facility has a maturity date of November 2003. TECO Energy’s $350 million one-year facility also matures in November 2003 and its $350 million 3-year facility matures in November 2004. Within its 3-year facility, TECO Energy has $250 million of capacity to issue letters of credit, of which $159 million was utilized at June 30, 2003. TECO Energy’s $350 million one-year credit facility requires commitment fees of 20-25 basis points, and drawn amounts incur interest expense at LIBOR plus 55-80 basis points at current ratings. The Tampa Electric Company bank facility requires commitment fees of 15 basis points, and drawn amounts are charged interest at LIBOR plus 105-117.5 basis points at current credit ratings.

In order to utilize the credit facilities, TECO Energy’s debt-to-capital ratio, as defined in the credit agreement, may not exceed 65%. Under Tampa Electric’s credit facility, Tampa Electric’s debt-to-capital ratio may not exceed 60% measured at the end of the applicable quarter and its EBITDA to interest coverage ratio must be at least 2.5 times. See Note 18 for a summary of performance against significant financial covenant requirements.

The TPGC non-recourse project facilities have maturity dates of June 2006. The Union and Gila River project financings each include a debt service credit facility of $40 million and a commercial letter of credit facility of $100 million.

8. Long-Term Debt

On June 13, 2003, TECO Energy issued $300 million of 7.5% Senior Unsecured Notes due in 2010. These notes contain a covenant that limits the ability of the company to create any lien upon any of its property in excess of 5% of consolidated tangible net assets, as defined in the agreement, without equally and ratably securing the 7.5% Notes. Net proceeds of $293 million were used to repay short-term debt and for general corporate purposes.

In April 2003, Tampa Electric issued $250 million of 6.25% Senior Notes due in 2016, in a private debt placement. Net proceeds of $248.4 million were used to repay short-term indebtedness and for general corporate purposes at Tampa Electric. The 6.25% Senior Notes contain covenants that (1) require Tampa Electric Company to maintain, as of the last day of each fiscal quarter, a debt-to-capital ratio, as defined in the agreement, that does not exceed 60%, and (2) prohibit the creation of any liens on any of its property in excess of $787 million in the aggregate, with certain exceptions, as defined, without equally and ratably securing the 6.25% Senior Notes.

In 2001, TPGC obtained construction financing in the form of floating rate, non-recourse senior secured credit facilities from a bank group. The construction loans will convert to term loans upon the completion and full commercial operation of the Union and Gila River projects. The Union and Gila River projects each jointly and severally guarantee and cross-collateralize the loans and debts of the other. The loans are non-recourse to TECO Energy and the subsidiaries that own the project entities.

In connection with the non-recourse borrowings, TPGC entered into interest rate swap agreements to effectively convert a portion of the floating rate debt to a fixed rate basis. At June 30, 2003 and Dec. 31, 2002, TPGC had interest rate swap agreements with notional amounts totaling $882.8 million and $1,035.0 million, respectively. The interest rate swap agreements have terms ranging from 2 to 5 years with the majority maturing in June 2006.

16

At June 30, 2003 and Dec. 31, 2002, TECO Energy had the following long-term debt outstanding.

Long-term Debt
(millions)	Due	June 30, 2003		Dec. 31, 2002
TECO Energy
Notes: 7.2% (effective rate of 7.38%) (2)	2011	$	600.0	$	600.0
Notes: 6.125% (effective rate of 6.31%) (2)	2007		300.0		300.0
Notes: 7% (effective rate of 7.08%) (2)	2012		400.0		400.0
Notes: 10.5% (effective rate of 12.29%) (2) (6)	2007		380.0		380.0
Notes: 7.5% (effective rate of 7.83%) (2) (6)	2010		300.0		—
			1,980.0		1,680.0
Tampa Electric
First mortgage bonds (issuable in series):
7.75% (effective rate of 7.96%)	2022		75.0		75.0
6.125% (effective rate of 6.61%)	2003		—		75.0
Installment contracts payable (3):
6.25% Refunding bonds (effective rate of 6.81%) (4)	2034		86.0		86.0
5.85% (effective rate of 5.88%)	2030		75.0		75.0
5.1% Refunding bonds (effective rate of 5.78%) (5)	2013		60.7		60.7
5.5% Refunding bonds (effective rate of 6.35%) (5)	2023		86.4		86.4
4% (effective rate of 4.21%) (6)	2025		51.6		51.6
4% (effective rate of 4.16%) (6)	2018		54.2		54.2
4.25% (effective rate of 4.43%) (6)	2020		20.0		20.0
Notes: 6.875% (effective rate of 6.98%) (2)	2012		210.0		210.0
Notes: 6.375% (effective rate of 7.34%) (2)	2012		330.0		330.0
Notes: 5.375% (effective rate of 5.58%) (2)	2007		125.0		125.0
Notes: 6.25% (effective rate of 6.36%) (2)	2016		250.0		—
			1,423.9		1,248.9
Peoples Gas System
Senior Notes (6)
10.35%	2007		4.2		4.2
10.33%	2008		5.6		5.6
10.3%	2009		7.2		7.2
9.93%	2010		7.4		7.4
8%	2012		25.4		25.4
Notes: 6.875% (effective rate of 6.98%) (2)	2012		40.0		40.0
Notes: 6.375% (effective rate of 7.34%) (2)	2012		70.0		70.0
Notes: 5.375% (effective rate of 5.58%) (2)	2007		25.0		25.0
			184.8		184.8
TECO Power Services
Non-recourse secured facility notes, Series A: 7.8%	2003-2012		107.1		111.0
Non-recourse secured facility notes, variable rate: 4.63% (1)	2003-2007		40.9		50.1
Non-recourse secured facility notes: 10.1%	2003-2009		15.9		16.4
Non-recourse secured facility notes: 9.629%	2003-2010		20.7		24.8
Non-recourse secured facility note, variable rate: 6.88% (1)	2004-2009		7.0		16.0
Non-recourse secured facility note, variable rate: 5% (1)	2004-2009		23.0		14.0
Non-recourse secured facility note, variable rate: 2.97% weighted average	2003-2006		1,395.0		—
Non-recourse financing facility - Union County: 7.5% (7)	2021		700.0		—
			2,309.6		232.3

17

Long-Term Debt - continued
(millions)	Due	June 30, 2003			Dec. 31, 2002
Diversified companies
Dock and wharf bonds, 5% (3)	2007		110.6			110.6
Non-recourse mortgage notes: 4.40% (effective rate of 4.56%) (8)	2003-2004		5.3			—
Non-recourse mortgage notes: 3.90% (effective rate of 4.16%) (8)	2003-2004		2.5			—
Capital lease: implicit rate of 8.5%	2003		—			25.3
			118.4			135.9
Unamortized debt premium (discount), net			(30.8	)		(30.5	)
			5,985.9			3,451.4
Less amount due within one year (9)			48.2			127.1
Total long-term debt		$	5,937.7		$	3,324.3

(1) Composite year-end interest rate.

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

(3) Tax-exempt securities.

(4) 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.

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

(6) These long-term debt agreements contain various restrictive covenants, including provisions related to interest coverage, maximum levels of debt to total capitalization and limitations on dividends (see Note 18).

(7) This debt is fully offset by an investment in industrial revenue bonds issued by Union County, Arkansas (see Note 3).

(8) These notes represent 100% of the debt for a project in which TECO Properties has an 80-percent interest. In total, TECO Properties has a $1.0 million guarantee on these notes.

(9) Of the amount due in 2003, $0.8 million may be satisfied by the substitution of property in lieu of cash payments.

9. Stock-Based Compensation

TECO Energy maintains limited stock-based compensation plans. Stock options are granted with an option price greater than or equal to the fair value on the grant date. No compensation expense has been recognized for stock options granted under the 1996 Equity Incentive Plan and the 1997 Director Equity Plan. If the company had elected to recognize compensation expense for stock options based on the fair value at grant date, consistent with the method prescribed by FAS 123, net income and earnings per share would have been reduced to the pro forma amounts as follows. The pro forma amounts were determined using the Black-Scholes valuation model with weighted average assumptions as set forth below.

Pro Forma Disclosure — Stock Options

	Three months ended June 30,					Six months ended June 30,
(millions, except per share amounts)	2003			2002		2003			2002
Net (loss) income from continuing operations
As reported	$	(101.9	)	$	80.9	$	(121.2	)	$	150.8
Pro forma expense (1)		1.1			1.3		2.1			2.2
Pro forma	$	(103.0	)	$	79.6	$	(123.3	)	$	148.6
Net (loss) income
As reported	$	(101.9	)	$	85.7	$	(99.2	)	$	161.1
Pro forma expense (1)		1.1			1.3		2.1			2.2
Pro forma	$	(103.0	)	$	84.4	$	(101.3	)	$	158.9

18

Pro Forma Disclosure — Stock Options - continued

	Three months ended June 30,						Six months ended June 30,
(millions, except per share amounts)	2003			2002			2003			2002
Net (loss) income from continuing operations - EPS, basic
As reported	$	(0.58	)	$	0.56		$	(0.69	)	$	1.06
Pro forma	$	(0.58	)	$	0.55		$	(0.70	)	$	1.04
Net (loss) income from continuing operations - EPS, diluted
As reported	$	(0.58	)	$	0.56		$	(0.69	)	$	1.06
Pro forma	$	(0.58	)	$	0.55		$	(0.70	)	$	1.04
Net (loss) income - EPS, basic
As reported	$	(0.58	)	$	0.59		$	(0.56	)	$	1.13
Pro forma	$	(0.58	)	$	0.59		$	(0.57	)	$	1.12
Net (loss) income - EPS, diluted
As reported	$	(0.58	)	$	0.59		$	(0.56	)	$	1.13
Pro forma	$	(0.58	)	$	0.58		$	(0.58	)	$	1.11
Assumptions
Risk-free interest rate		4.33	%		5.09	%		4.33	%		5.09	%
Expected lives (in years)		6			6			6			6
Expected stock volatility		31.21	%		25.92	%		31.21	%		25.92	%
Dividend yield		5.98	%		5.47	%		5.98	%		5.47	%

(1) Compensation expense for stock options determined under fair-value based method, after-tax.

10. Asset Impairments

At Mar. 31, 2003, TECO Energy recorded a $64.2 million after-tax charge ($104.1 million pretax) to reflect the impact of the cancellation of turbine purchase commitments. This represented after-tax charges of $15.3 million ($24.5 million pretax) at TPS and $48.9 million ($79.6 million pretax) at Tampa Electric relating to installment payments made and capitalized in prior periods. As reported previously and in Note 15, certain turbine rights had been transferred from TPS 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 TPS and Tampa Electric.

11. TPGC Joint Venture Termination

In January 2002, TPS agreed to purchase the interests of Panda Energy in the TPGC projects in 2007 for $60 million, and TECO Energy guaranteed payment of TPS’ obligation under this agreement. Panda Energy obtained bank financing using the purchase obligation and 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 TPS’ 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 April 9, 2003, TECO Energy and Panda Energy amended the agreements related to the purchase obligation. The modified terms accelerated TPS’ purchase obligation to on or before July 1, 2003, and reduced the overall purchase obligation to $58 million. Under the guarantee TECO Energy 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 (see Note 1 for additional details on TECO Energy’s ownership interest in PLC). Both modifications to the purchase obligation were subject to the condition, which TECO Energy could waive, that bank financing could be obtained by TECO Energy. Panda Energy’s cancellation right was accelerated to expire on June 16, 2003. TECO Energy’s guarantee of TPS’ obligation was modified to reflect the amendments to the purchase obligation. In April 2003, TECO Energy recognized the fair value of the guarantee as an after-tax loss of $21.4 million ($35.0 million pretax), included in the “Loss on joint venture termination” caption in the Statements of Consolidated Income. From April 2003 through June 2003, TECO Energy made and accrued certain principal payments under the guarantee commitment, giving rise to a receivable from Panda of $9.0 million.

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 at that time. 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

19

appropriate as of the date of the modifications to the agreements. For convenience of reporting periods and accounting cycles, management selected April 1, 2003 as the initial date of consolidation.

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 the partnership between Panda and TECO Power Services. Proceeds from the bank financing obtained in June 2003, which is more fully discussed in Note 7, were used to fund the net termination payment to Panda. Upon acceleration of the guarantee obligation and the resulting partnership termination, TPS received the 50-percent outstanding partnership interests in TPGC. As previously discussed, under the amended agreements, $35.0 million, pretax, had been recognized in April 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.

For the three months ended June 30, 2003, TECO Energy recorded total after-tax charges of $155.9 million ($249.1 million pretax) at TPS. These charges included: $21.4 million after-tax ($35.0 million pretax) related to the partnership termination under the guarantee; $73.3 million after-tax ($118.9 million pretax) 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 (see Note 15), which were previously anticipated to occur in the third quarter as a result of the revised consolidation criteria established in FIN 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, effective July 1, 2003; and $61.2 million ($95.2 million pretax) of goodwill impairments (see Note 4 for additional details regarding the goodwill impairment). The total charges associated with the amendments to the agreements, excluding the goodwill impairments, of $94.7 million after-tax ($153.9 million pretax), are recorded as “Loss on joint venture termination”.

The following table presents the unaudited combined results of operations for TECO Energy on a pro forma basis as if the termination of the partnership had taken place at the beginning of each period presented. Management does not believe that these unaudited pro forma results of operations will be indicative of future operations as TPGC was a development stage company for all periods presented.

(Unaudited) Pro Forma Results of Operations

	Three months ended June 30,					Six months ended June 30,
(millions, except per share amounts)	2003			2002		2003			2002
Revenues	$	737.2		$	677.7	$	1,406.8		$	1,284.3
Net (loss) income from continuing operations (1)		(101.9	)		71.3		(122.7	)		137.2
Cumulative effect of change in accounting principle, net		—			—		(1.1	)		—
Net (loss) income (1)	$	(101.9	)	$	76.1	$	(101.7		$	147.5
Earnings per share, basic (1)(2)	$	(0.58	)	$	0.53	$	(0.58	)	$	1.04

(1) Includes pretax charges of $249.1 million and $353.2 million for the three months and six months ended June 30, 2003, respectively. The charges for the three months ended June 30, 2003 are the result of the partnership termination and the related goodwill impairment. In addition, for the six months ended June 30, 2003, the charges include the asset impairment associated with turbine purchase commitment cancellation (see Note 10).

(2) Average common shares outstanding, basic, were 176.4 million and 176.2 million for the three months and six months ended June 30, 2003, respectively, and 144.7 million and 142.7 million, respectively, for the same periods in 2002.

12. Income Tax Expense

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes, primarily due to the recognition of non-conventional fuels tax credits and other miscellaneous items as noted in the table that follows. The full-year estimate of the non-conventional fuels tax credits for 2003 is approximately $44 million.

In the second quarter of 2003, tax credits generated at TECO Coal for its behalf were reduced due to TECO’s April 1, 2003 sale of significant membership interests in the synfuel production. Generally accepted accounting principles require that income tax expense be recognized in interim periods at the expected consolidated annual effective income tax rate. In the second quarter, TECO Energy recognized $15.4 million of intra-period tax benefit previously deferred from the first quarter. The remainder of the total first quarter deferral of $25.9 million is expected to reverse by year-end, having no net impact for the full-year 2003 results.

In the quarter ended Mar. 31, 2003, TECO Energy recorded $64.2 million of after-tax charges for the cancellation of turbine purchase commitments by Tampa Electric and TECO Power Services. In the second quarter, TECO Energy considered $167.2 million as unusual and infrequently occurring items including after-tax charges for goodwill impairment and joint venture termination losses at TPS. The provision for income taxes as a percent of these items for the six months ended June 30, 2003 was 37.5%. For the six months ended June 30, 2003, net income from discontinued operations was $23.1 million and the provision for income taxes, as a percent of income from discontinued operations, was 39.4%.

20

Effective Income Tax Rate

	Three months ended June 30,						Six months ended June 30,
(millions)	2003			2002			2003			2002
Net income from continuing operations, excluding unusual and infrequently occurring items, net of tax (1)	$	65.3		$	80.9		$	110.4		$	150.8
Total income tax provision (benefit), excluding tax associated with unusual and infrequently occurring items (1)		11.6			(5.8	)		12.7			(13.9	)
Income from continuing operations before income taxes, excluding unusual and infrequently occurring items (1)	$	76.9		$	75.1		$	123.1		$	136.9
Income taxes on above at federal statutory rate of 35%	$	26.9		$	26.3		$	43.1		$	47.9
Increase (decrease) due to
State income tax, net of federal income tax		0.6			2.0			1.5			3.7
Foreign income taxes		2.5			0.9			3.8			0.9
Amortization of investment tax credits		(1.1	)		(1.1	)		(2.2	)		(2.2	)
Non-conventional fuels tax credit (2)		(16.4	)		(28.2	)		(25.7	)		(53.8	)
Permanent reinvestment-foreign income		(3.8	)		(3.1	)		(7.7	)		(5.7	)
AFUDC equity		(1.4	)		(2.0	)		(4.1	)		(3.5	)
Other		4.3			(0.6	)		4.0			(1.2	)
Total income tax provision from continuing operations	$	11.6		$	(5.8	)	$	12.7		$	(13.9	)
Provision for income taxes as a percent of income from continuing operations, before income taxes		15.1	%		(7.7	)%		10.3	%		(10.2	)%

(1) Excludes after-tax charges of $64.2 million ($104.1 million pretax) recorded in the three months ended Mar. 31, 2003 for an asset impairment (see Note 10), and $167.2 million ($266.0 million pretax) for the goodwill impairment and TPGC transaction losses recorded in the three months ended June 30, 2003 (see Note 11).

(2) Non-conventional fuels tax credit for the three months ended June 30, 2003 was increased by the $15.4 million intra-period tax benefit adjustment to recognize income taxes at the expected annualized effective income tax rate.

13. Discontinued Operations

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 six months ended June 30, 2003 included a $22.7 million after-tax gain for the final cash installment from the sale of these assets. TECO Coalbed Methane’s results were accounted for as discontinued operations for the three and six months ended June 30, 2002. For the three and six months ended June 30, 2002, operating revenues from TECO Coalbed Methane were $8.6 million and $17.6 million, respectively, and pretax operating income was $2.1 million and $4.9 million, respectively.

14. Comprehensive Income

TECO Energy reported the following comprehensive income (loss) for the three months and six months ended June 30, 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:

21

Comprehensive Income (Loss)

(millions) Three months ended June 30,	Gross			Tax			Net
2003
Unrealized (loss) gain on cash flow hedges (1)	$	(72.5	)	$	(27.7	)	$	(44.8	)
Less: (Gain) loss reclassified to net income		—			—			—
(Loss) gain on cash flow hedges		(72.5	)		(27.7	)		(44.8	)
Foreign currency adjustments		0.4			—			0.4
Total other comprehensive (loss) income	$	(72.1	)	$	(27.7	)	$	(44.4	)
2002
Unrealized (loss) gain on cash flow hedges (1)	$	(13.1	)	$	(3.4	)	$	(9.7	)
Less: Loss (gain) reclassified to net income		2.3			1.1			1.2
Total other comprehensive (loss) income		(10.8	)		(2.3	)		(8.5	)
Six months ended June 30,	Gross			Tax			Net
2003
Unrealized (loss) gain on cash flow hedges (1)	$	(69.1	)	$	(26.1	)	$	(43.0	)
Less: Loss (gain) reclassified to net income		(18.7	)		(7.2	)		(11.5	)
Gain (loss) on cash flow hedges		(87.8	)		(33.3	)		(54.5	)
Foreign currency adjustments		1.2			—			1.2
Total other comprehensive (loss) income	$	(86.6	)	$	(33.3	)	$	(53.3	)
2002
Unrealized (loss) gain on cash flow hedges	$	(16.5	)	$	(6.8	)	$	(9.7	)
Less: Loss (gain) reclassified to net income		22.7			8.8			13.9
Total other comprehensive income (loss)	$	6.2		$	2.0		$	4.2

(1) Amounts include cash flow interest rate swaps at TPGC, which was consolidated effective April 1, 2003 as a result of the termination of the partnership. Prior to April 1, 2003, only the company’s proportionate share of its equity investee’s comprehensive loss was included.

15. Related Parties

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. These transactions, primarily for legal services, were not material for the six months ended June 30, 2003 and 2002. No material balances were payable as of June 30, 2003 or Dec. 31, 2002.

In the second quarter of 2003, Tampa Electric returned to TECO Energy $118 million of capital which was previously contributed by TECO Energy to support Tampa Electric’s construction program.

In February 2002, Tampa Electric and TECO-Panda Generating Company II (TPGC II) entered into an assignment and assumption agreement whereby 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. See Note 10.

At Dec. 31, 2002, notes receivable from unconsolidated affiliates included the following: $795.8 million due from TPGC; $137.0 million due from PLC; $1.4 million due from Energeticke Centrum Kladno (ECKG); $13.7 million due from Mosbacher Power Partners L.P.; and $11.1 million due from EEGSA.

As of June 30, 2003, TPS had a note receivable from an unconsolidated affiliate of $11.1 million due from EEGSA, bearing a current effective interest rate of 6.42%.

On Jan. 3, 2003, the loan receivable from PLC converted to a 50-percent ownership interest in a joint venture with Panda Energy, PLC. This joint venture holds a 50-percent ownership interest in Texas Independent Energy, L.P. (TIE). The TIE partnership owns and operates the Odessa and Guadalupe power stations in Texas. See also Notes 1 and 11 for additional information regarding PLC.

As a result of amendments to certain agreements in April 2003, TECO Energy was required to consolidate TPGC. For the six months ended June 30, 2003 and 2002, “Other income” includes pretax income of $9.7 million and $12.4 million, respectively, from construction-related and loan agreements with Panda Energy. For the three months ended June 30, 2002, “Other income” includes $7.0 million, pretax. No amounts were recorded for the three months ended June 30, 2003. See Note 11 for the additional details of the impact of consolidation on the company.

22

16. Earnings Per Share

For the three and six months ended June 30, 2003 and 2002, stock options for 6.4 million shares and 3.7 million shares, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect. Additionally, 14.9 million common shares issuable under the purchase contract associated with the mandatorily convertible equity units issued in January 2002 were also excluded from the computation of diluted earnings per share for the three and six months ended June 30, 2003 and 2002 due to their antidilutive effect.

Earnings Per Share

(millions, except per share amounts)	Three months ended June 30,						Six months ended June 30,
	2003			2002			2003			2002
Numerator
Net (loss) income from continuing operations, basic	$	(101.9	)	$	80.9		$	(121.2	)	$	150.8
Effect of contingent performance shares		(0.4	)		—			(0.4	)		—
Net (loss) income from continuing operations, diluted	$	(102.3	)	$	80.9		$	(121.6	)	$	150.8
Discontinued operations, net of tax		—			4.8			23.1			10.3
Cumulative effect of a change in accounting principle, net		—			—			(1.1	)		—
Net (loss) income, basic	$	(101.9	)	$	85.7		$	(99.2	)	$	161.1
Effect of contingent performance shares		(0.4	)		—			(0.4	)		—
Net (loss) income, diluted	$	(102.3	)	$	85.7		$	(99.6	)	$	161.1
Denominator
Average number of shares outstanding - basic		176.4			144.2			176.2			142.3
Plus: Incremental shares for assumed conversions:
Stock options at end of period and contingent performance shares		2.8			2.9			2.8			2.9
Less: Treasury shares which could be purchased		(2.6	)		(2.4	)		(2.5	)		(2.5	)
Average number of shares outstanding - diluted		176.6			144.7			176.5			142.7
Earnings per share from continuing operations
Basic	$	(0.58	)	$	0.56		$	(0.69	)	$	1.06
Diluted	$	(0.58	)	$	0.56		$	(0.69	)	$	1.06
Earnings per share from discontinued operations, net
Basic	$	—		$	0.03		$	0.13		$	0.07
Diluted	$	—		$	0.03		$	0.13		$	0.07
Earnings per share from cumulative effect of
change in accounting principle, net
Basic	$	—		$	—		$	—		$	—
Diluted	$	—		$	—		$	—		$	—
Earnings per share
Basic	$	(0.58	)	$	0.59		$	(0.56	)	$	1.13
Diluted	$	(0.58	)	$	0.59		$	(0.56	)	$	1.13

17. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. The management of TECO Energy determined its reportable segments based on each subsidiary’s contribution of revenues, net income and total assets. All significant intercompany transactions are eliminated in the consolidated financial statements of TECO Energy but are included in determining reportable segments. In December 2002, the assets of TECO Coalbed Methane were sold. The information presented here excludes TECO Coalbed Methane’s results, which are reflected in the consolidated financial statements as discontinued operations.

23

Segment Information (1)

(millions) Three months ended June 30,	Tampa Electric			Peoples Gas		TPS			TECO Transport		TECO Coal			Other Unregulated			Eliminations & Other			TECO Energy
2003
Revenues - outsiders (2)	$	406.9		$	94.8	$	99.1		$	35.8	$	78.1		$	22.4		$	0.1		$	737.2
Sales to affiliates (2)		0.8			—		17.3			30.8		—			3.2			(52.1	)		—
Total revenues (2)	$	407.7		$	94.8	$	116.4		$	66.6	$	78.1		$	25.6		$	(52.0	)	$	737.2
Depreciation		57.3			8.1		17.4			5.0		8.4			0.2			—			96.4
Interest charges (3)		23.4			3.9		41.6			1.4		4.2			1.5			10.7			86.7
(Benefit) provision for taxes		20.7			3.0		(103.9	)(5)		4.0		11.0			(1.6	)		(20.6	)(6)		(87.4	)
Net (loss) income from continuing operations (3)	$	39.5		$	4.8	$	(179.4	)(5)	$	5.2	$	20.8		$	(1.8	)	$	9.0	(6)	$	(101.9	)
2002
Revenues - outsiders (2)	$	403.8		$	77.3	$	61.7		$	31.4	$	80.2		$	23.3		$	0.0		$	677.7
Sales to affiliates (2)		9.5			—		13.7			29.3		—			5.3			(57.8	)		—
Total revenues (2)	$	413.3		$	77.3	$	75.4		$	60.7	$	80.2		$	28.6		$	(57.8	)	$	677.7
Depreciation		46.6			7.7		6.8			5.5		7.7			2.6			—			76.9
Interest charges (3)		14.2			3.5		14.0			1.5		2.1			1.1			5.2			41.6
(Benefit) provision for taxes		23.3			2.8		2.0			2.2		(34.0	)		0.8			(2.8	)		(5.7	)
Net income (loss) from continuing operations (3)	$	45.4		$	4.4	$	8.9		$	4.2	$	19.7		$	2.1		$	(3.8	)	$	80.9
Six months ended June 30,
2003
Revenues - outsiders (2)	$	748.0		$	221.7	$	149.8		$	72.6	$	153.6		$	49.8		$	0.2		$	1,395.7
Sales to affiliates (2)		1.8			—		31.5			59.0		—			6.6			(98.9	)		—
Total revenues (2)	$	749.8		$	221.7	$	181.3		$	131.6	$	153.6		$	56.4		$	(98.7	)	$	1,395.7
Depreciation		103.3			16.5		24.3			10.2		16.7			5.2			—			176.2
Interest charges (3)		42.6			7.9		65.2			2.5		5.3			2.8			24.9			151.2
(Benefit) provision for taxes		8.9	(4)		10.6		(119.6	)(5)		6.5		(30.3	)		(1.4	)		(1.0	)(6)		(126.3	)
Net (loss) income from continuing operations (3)	$	30.5	(4)	$	16.7	$	(197.9	)(5)	$	9.8	$	46.5		$	(1.0	)	$	(25.8	)(6)	$	(121.2	)
2002
Revenues - outsiders (2)	$	742.5		$	162.7	$	104.9		$	64.7	$	161.2		$	48.3		$	0.0		$	1,284.3
Sales to affiliates (2)		16.5			—		25.8			60.2		—			11.1			(113.6	)		—
Total revenues (2)	$	759.0		$	162.7	$	130.7		$	124.9	$	161.2		$	59.4		$	(113.6	)	$	1,284.3
Depreciation		92.2			15.1		14.1			11.3		15.7			6.5			—			154.9
Interest charges (3)		28.1			7.0		27.9			3.2		4.1			2.4			15.8			88.5
(Benefit) provision for taxes		41.5			8.9		1.0			5.9		(65.4	)		2.0			(7.8	)		(13.9	)
Net income (loss) from continuing operations (3)	$	81.4		$	14.2	$	13.8		$	11.1	$	37.1		$	4.6		$	(11.4	)	$	150.8
At June 30, 2003
Goodwill, net	$	—		$	—	$	59.3		$	—	$	—		$	40.9		$	—		$	100.2
Investment in unconsolidated affiliates		—			—		279.4			—		—			45.8			—			325.2
Other non-current investments		—			—		695.6			—		—			8.9			—			704.5
Total Assets	$	3,745.4		$	598.0	$	5,584.5		$	309.0	$	349.7		$	328.4		$	236.8		$	11,151.8
At Dec. 31, 2002
Goodwill, net	$	—		$	—	$	154.5		$	—	$	—		$	39.2		$	—		$	193.7
Investment in unconsolidated affiliates		—			—		97.4			—		—			51.8			—			149.2
Other non-current investments		—			—		835.6			—		—			9.4			0.3			845.3
Total Assets	$	3,737.0		$	571.7	$	2,875.0		$	355.1	$	283.5		$	312.4		$	503.1		$	8,637.8

(1) From continuing operations. Revenues, interest expense, tax provisions (benefits) and net income for all periods have been adjusted to reflect the reclassification of TECO Coalbed Methane results as discontinued operations.

24

(2) Revenues for all periods have been adjusted to reflect the presentation of energy marketing related revenues on a net basis and the reclassification of earnings from equity investments from Revenues to Other income.

(3) Segment net income is reported on a basis that includes internally allocated financing costs. Internally allocated costs for the three and six months ended June 30, 2003 and 2002 were at pretax rates of 8% and 7%, respectively, based on the average investment in each subsidiary.

(4) Net income for the six months ended June 30, 2003 includes a $48.9 million after-tax ($79.6 million pretax) asset impairment related to the turbine purchase cancellations (see Note 10).

(5) Net income for the three and six months ended June 30, 2003 includes a $61.2 million after-tax ($95.2 million pretax) charge for goodwill impairment, and a $94.7 million after-tax charge ($153.9 million pretax) related to the partnership termination and resulting consolidation of TPGC. Net income for the six months ended June 30, 2003, also includes a $15.3 million after-tax ($24.5 million pretax) asset impairment related to the turbine purchase cancellations (see Note 10).

(6) Provision for income taxes and net income for the three months ended June 30, 2003 includes the recognition of $15.4 million of previously deferred tax credits for the production of synthetic fuel in the first quarter of 2003. The amount reported for the six months ended June 30, 2003 includes the remaining $10.5 million intra-period tax benefit deferral (see Note 12).

18. Commitments and Contingencies

Capital Investments

TECO Energy has made certain commitments in connection with its continuing capital expenditure program. At June 30, 2003, these estimated capital investments for the full year 2003, net of proceeds from asset sales of $181 million, total approximately $442 million and are summarized as follows:

Forecasted Capital Investments

(millions)	Estimated 2003
Tampa Electric	$	248
Peoples Gas		40
TECO Power Services		278
TECO Transport		20
TECO Coal		32
Other		5
Total capital investments		623
Less: proceeds from asset sales		(181	)
Net capital investments	$	442

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party 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 June 30, 2003, Tampa Electric Company has estimated its ultimate financial liability to be approximately $21 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 potentially responsible parties (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.

25

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 (FIN) No. 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.

• 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.

For the six months ended June 30, 2003, TECO Energy has not issued or modified any guarantees that would require initial recognition at fair value in the financial statements, except for the guarantee related to the TPGC joint venture, as discussed in Note 11. At June 30, 2003, TECO Energy had outstanding letters of credit with a face amount or maximum payment potential, undiscounted, of $159.6 million. These letters of credit guarantee performance to third parties related to debt service, major maintenance requirements and various trade activities. Most of the guarantees are renewable annually.

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

Letters of Credit and Guarantees

($ in millions)
Letters of Credit and Guarantees     for the Benefit of	2003		2004		2005-2007		After 2007		Total		Liabilities Recognized at June 30, 2003
Tampa Electric
Letters of credit	$	0.1	$	—	$	—	$	0.8	$	0.9	$	—
TECO Power Services
Letters of credit (1)		102.0		8.0		—		20.4		130.4		—
Guarantees:
Debt related		—		—		—		15.7		15.7		—
Tax related		—		—		—		3.8		3.8		—
Fuel purchase/energy management (2)		5.0		20.0		—		519.5		544.5		120.7
Construction/Investment related		5.0		—		—		—		5.0		—
		112.0		28.0		—		559.4		699.4		120.7
TECO Transport
Letters of credit		—		—		—		1.5		1.5		—
TECO Coal
Letters of credit								20.0		20.0		—
Guarantees: Fuel purchase related								1.4		1.4		1.6
		—		—		—		21.4		21.4		1.6
Other unregulated subsidiaries
Letters of credit		4.0						2.7		6.7		—
Guarantees:
Debt related								8.0		8.0		—
Fuel purchase/energy management (2)		—		—				188.7		188.7		39.8
		4.0		—		—		199.4		203.4		39.8
	$	116.1	$	28.0	$	—	$	782.5	$	926.6	$	162.1

(1) Primarily includes letters of credit for construction support for the Gila River and Union power stations.

(2) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2007. 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 June 30, 2003. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

26

In addition to the financial and non-financial guarantees listed above, TECO Energy and its subsidiaries enter into commercial agreements in the normal course of business that typically contain standard indemnification clauses. TECO Energy may sometimes agree to make payments to compensate or indemnify the counter-party for legal fees, environmental remediation costs and other similar costs arising from possible future events or changes in laws or regulations. These agreements cover a variety of goods and services, and have varying triggering events dependent on actions by third parties.

TECO Energy is unable to estimate the maximum potential future exposure under these clauses because the events that would obligate TECO Energy have not occurred, or if such event has occurred, TECO Energy has not been notified of any occurrence. As claims are made or changes in laws or regulations indicate, an amount related to the indemnification is reflected in the financial statements.

The Union and Gila River projects have credit facilities for commercial letters of credit and debt service as part of the non-recourse project financing. These facilities are recourse only to the TPGC project companies, and not to TECO Energy or its other subsidiaries. Each project has a letter of credit facility of $100 million to facilitate gas purchases and power sales. Total aggregate letters of credit outstanding under the two facilities at June 30, 2003 was $120.8 million. Each project also has a $40 million debt service reserve facility, neither of which has been drawn upon at June 30, 2003. See also Note 7.

Financial Covenants

A summary of TECO Energy’s significant financial covenants as of June 30, 2003 is as follows:

TECO Energy Significant Financial Covenants

(millions) Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at June 30, 2003
Tampa Electric
Mortgage bond indenture	Dividend restriction	Cumulative distributions cannot exceed cumulative net income plus $4	$147 unrestricted
PGS senior notes	EBIT/interest	Minimum of 2.0 times	3.4 times
	Restricted payments	Shareholder equity at least $500	$1,677
	Funded debt/capital	Cannot exceed 65%	50.7%
	Sale of assets	Less than 20% of total assets	0%
Credit facility	Debt/capital	Cannot exceed 60%	49.3%
	EBITDA/interest	Minimum of 2.5 times	7.3 times
6.25% senior notes	Debt/capital	Cannot exceed 60%	49.3%
	Limit on liens	Cannot exceed $787	$362
TECO Energy
Credit facilities (2)	Debt/capital	Cannot exceed 65%	57.5%
$37.5 credit facility	EBITDA/interest	Minimum 2.5 times	3.2 times
	Limit on liens	Cannot exceed 60% of fair value of assets	24.0% (3)
	Debt/capital	Cannot exceed 65%	57.5%
$380 million note indenture	Limit on restricted payments (4)	Cumulative operating cash flow in excess of 1.7 times interest	$139 unrestricted
	Limit on liens	Cannot exceed 5% of tangible assets	$176 unrestricted
	Limit on indebtedness	Interest coverage at least 2.0 times	3.0 times
$300 million note indenture	Limit on liens	Cannot exceed 5% of tangible assets	$176 unrestricted
TPGC guarantees (5)	Debt/capital	Cannot exceed 65%	57.5%
	EBITDA/interest	Minimum of 3.0 times	3.2 times

27

TECO Energy Significant Financial Covenants - continued

(millions) Instrument	Financial Covenant(1)	Requirement/ Restriction	Calculation at June 30, 2003
TECO Diversified
Energy management services agreement guarantee	Consolidated tangible net worth	Minimum of $200	$559
	Consolidated funded debt	Cannot exceed 60%	17.5%
Coal supply agreement guarantee	Dividend restriction	Net worth not less than $200 or $427 (40% of tangible net assets)	$517

(1) As defined in each applicable instrument.

(2) In addition, one of TECO Energy’s credit facilities, if drawn upon, can limit payment of dividends each quarter to $40 million, unless the company provides the lender with satisfactory liquidity projections demonstrating the company’s ability to pay both the dividends contemplated and each of the three quarterly dividends next scheduled to be paid. See Note 7 for the details regarding this credit facility.

(3) The fair market value of the assets has not been calculated. This calculation represents total secured debt, including TPS non-recourse debt, divided by total assets.

(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. At June 30, 2003, $139.1 million was accumulated and available for future restricted payments, representing two quarters accumulation.

(5) Includes Construction Undertaking Guarantees related to the TPGC projects.

In April 2003, Moody’s lowered TECO Energy’s senior unsecured debt rating to Ba1 with a negative outlook. This debt rating change triggered the repayment of the $250 million equity bridge loan balance associated with the construction of the Union and Gila River power projects. In addition, this ratings change required the company to post letters of credit, in an amount satisfactory to the majority of lenders, to secure the projects and project lenders for the remaining potential cost to complete the projects.

The company reached an agreement with the majority of the project lending banks for a total security amount of $234 million (including amounts for the remaining construction, liquidated damages for delays and performance shortfalls), $62 million of which was not required to be posted due to the achievement of the commercial operations of Gila River Phase 1 and Union Power Phase 3 prior to May 31, 2003. The company replaced and amended existing letters of credit (including retainage letters of credit) such that total letters of credit of $172 million were in place by May 20, 2003.

Subsequent to that posting, the outstanding letters of credit under these agreements were reduced by $62 million to $110 million in June with the commercial operation of Union Power Phase 4 and Gila River Phase 2.

19. Mergers, Acquisitions and Dispositions

For a detailed discussion of the termination of the company’s partnership with Panda Energy in TPGC, see Note 11.

Effective April 1, 2003, TECO Coal sold a 49.5-percent interest in its synthetic fuel production facilities located at its operations in eastern Kentucky. 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 “pay-as-you-go” basis typical of similar transactions in the industry, TECO Coal received no significant cash at the time of sale. The sale is contingent upon receipt of a positive response to a Private Letter Ruling (PLR) request and the proceeds from this transaction will be held in escrow pending resolution of this contingency. The current PLR request was made to reflect the revised ownership structure, location of facilities and other terms of previous PLRs. On June 27, 2003, the IRS suspended the issuance of PLRs when the audit side of the IRS raised questions about whether taxpayers were achieving “significant chemical change” and questioned the validity of the science used in the testing. TECO Energy believes it is operating its facilities in a manner that promotes the intent of the program and in compliance with and reliance on its PLRs.

Effective April 1, 2003, TECO Properties owns 80-percent of the ownership interests in B-T One, LLC, a limited liability company formed with Boyd Development Co., to buy and develop residential property in Ocala, Florida. Through Mar. 31, 2003, the company had accounted for B-T One as an equity investment. The company amended the partnership agreement to reflect the economic interests, thus triggering consolidation. There was no material change in the reported results of operations of TECO Energy as a result of the consolidation. No gain or loss was recognized as a result of the modified agreements.

28

At Dec. 31, 2002, TPS had a loan receivable of $137 million from a subsidiary of Panda Energy International. On Jan. 3, 2003, this loan was converted to a partnership interest. See Notes 1 and 15 for additional details regarding the conversion of this loan to an equity interest in PLC. As of June 30, 2003, TPS applied the equity method of accounting to PLC.

20. New Accounting Pronouncements

Accounting for Asset Retirement Obligations

In July 2001, the Financial Accounting Standards Board (FASB) issued FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability at fair value for an asset retirement obligation in the period in which it is incurred. FAS 143 is effective for fiscal years beginning after June 15, 2002. See Note 6 for the full discussion of the impact of adoption.

Exit or Disposal Costs

In July 2002, the FASB issued FAS 146, Accounting for Costs Associated with Exit or Disposal Activities, which addresses the accounting for costs under certain circumstances, including costs to terminate a contract that is not a capital lease, costs to consolidate facilities or relocate employees, and termination benefits provided to employees that are involuntarily terminated under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred compensation contract. FAS 146 is effective for disposal activities initiated after Dec. 31, 2002 with early adoption allowed. TECO Energy opted to early adopt FAS 146 on July 1, 2002. For the three and six months ended June 30, 2003 no costs were recognized in accordance with FAS 146. For the same period in 2002, the accounting standard was not yet effective.

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. See Note 1 for additional details of amounts presented on a net basis.

Guarantees

In November 2002, the FASB issued FIN 45, which modifies the accounting and enhances the disclosure of certain types of guarantees. FIN 45 requires that upon issuance of certain guarantees, the guarantor must recognize a liability for the fair value of the obligation it assumes under the guarantee. The provisions for the initial recognition and measurement are to be applied to guarantees issued or modified after Dec. 31, 2002. The disclosure requirements are effective for financial statements of annual periods that end after Dec. 15, 2002 (see Note 18). On Jan. 1, 2003, the company adopted the prospective measurement provisions without a material effect.

Consolidation of Variable Interest Entities

The equity method of accounting is used to account for significant investments in partnership arrangements in which TECO Energy or its subsidiary companies do not have a majority ownership interest or exercise control. On Jan. 17, 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which imposes a new approach in determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities or VIEs. A legal entity is considered a VIE 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 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. Certain transition disclosures are required for all financial statements issued after Jan. 31, 2003. The on-going disclosure and consolidation requirements are effective for all interim financial periods beginning after June 15, 2003. As of June 30, 2003, significant technical implementation issues remain unresolved by the FASB. It is not possible to predict what impact, if any, these resolutions may have on management’s conclusions regarding the applicability of FIN 46.

Based on its review, TECO Energy believes that FIN 46 will impact the accounting for certain unconsolidated affiliates. Management is continuing to monitor the development of additional technical positions which could impact the appropriateness of conclusions reached. Below is a discussion of the legal entities as of June 30, 2003 that TECO Energy believes will be subject to either 1) additional disclosure requirements, or 2) consolidation by the company, in accordance with FIN 46.

29

TPS has an ownership interest in a joint venture with Panda Energy, PLC, which holds an ownership interest in the TIE partnership (see Note 15). The TIE partnership owns and operates the Odessa and Guadalupe power stations in Texas. PLC may be a VIE in accordance with FIN 46. The estimated maximum loss exposure is approximately $162.1 million, representing primarily TPS’ equity investment as of June 30, 2003.

TPS completed a transaction whereby certain equipment at the Hardee Power Station was sold to a third party (the Lessor) and leased back under an operating lease agreement with an initial term of 12 years. The original cost of the equipment was $46.6 million. The sole purpose of the Lessor is to own and lease back the equipment to Hardee Power. The Lessor may be a VIE in accordance with FIN 46. The lease financing arrangement includes $41.6 million of non-recourse subordinated debt and $1.4 million of equity contributed by an unrelated third party. If the Lessor were to be consolidated, TPS estimates that it would incur after-tax incremental expenses of approximately $9.5 million over the 12 year term of the lease.

TECO Transport entered into two separate sale-leaseback transactions for certain vessels which were recognized as sales at the time of each transaction, and are currently recognized as operating leases for the assets. The sale-leaseback transactions were entered into with a third party that may 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. The estimated maximum loss exposure faced by TECO Transport is the incremental cost of obtaining suitable equipment to meet contractual obligations.

TECO Properties formed a limited liability company with a project developer which may meet 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. Hernando Oaks, LLC had total assets at June 30, 2003 of $21.2 million. TECO Properties’ estimated maximum loss exposure in this project is approximately $3.2 million.

TECO Energy Services (formerly TECO BGA) 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 for use, primarily, in air conditioning systems. The partnership may meet the definition of a VIE in accordance FIN 46. The estimated maximum loss exposure associated with this partnership is approximately $4 million as of June 30, 2003.

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 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 June 30, 2003. The company does not anticipate that the adoption of the additional guidance in FAS 149 will 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 remeasured at fair value on each reporting date.

30

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 June 15, 2003. TECO Energy is continuing to determine the estimated impact of the adoption of this standard.

21. Subsequent Events

In July 2003, the outstanding letters of credit under the TECO Energy bank credit facility maturing in November 2003 related to the construction of the Union and Gila River power stations were further reduced to $58 million with the commercial operation of Gila River Phases 3 and 4. The amounts outstanding are expected to be reduced to $8 million following full commercial operation which occurred in July, and the final acceptance of the units which is expected by October 2003.

In August 2003, TPS received Board approval to sell Hardee Power Partners, Ltd. which holds a 370-MW gas-fired generation facility located in central Florida. The potential sale of Hardee was previously announced on April 11, 2003 as one of the strategic options under consideration. The sale is expected to close before the end of 2003. The sale proceeds are expected to exceed the net book value of $54.6 million recorded at June 30, 2003 (including assets of $171.1 million and liabilities of $116.5 million).

In connection with the arbitration proceeding brought against a TPS subsidiary, TM Delmarva Power, L.L.C. (TMDP), by the non-equity member, NCP of Virginia, L.L.C. (NCP), in the Commonwealth Chesapeake Project (CCC) the arbitration panel in a 2-to-1 decision found in favor of NCP and issued an interim award on Dec.17, 2002, establishing a buy-out of NCP’s rights under the CCC’s operating agreement as the remedy and establishing the method of calculating the buy-out price. The interim award directed the parties to provide briefs and calculations with respect to the buy-out price. At the conclusion of the briefing cycle, TMDP’s experts and calculations placed the buy-out price at the $5-$10 million range, while NCP’s experts placed the value at approximately $44 million. Reopened hearings took place on May 12 and 13, 2003 for expert testimony on the discount rate, final briefs were submitted, and a second interim award was issued on July 11, 2003 establishing a 7 – 9% discount rate and clarifying the calculation methodology. Both parties have submitted their calculations in response to the second interim award which range from $9.5 million by TMDP to $25.5 million by NCP, but with NPC seeking up to $32 million. The panel has asked for further filings by the parties to accommodate the panel’s clarifications, and the panel is expected to issue a final decision within 30 days following the last reply brief due on Aug. 22, 2003.

31

TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the financial position of Tampa Electric Company as of June 30, 2003 and Dec. 31, 2002, and the results of operations and cash flows for the three-month and six-month periods ended June 30, 2003 and 2002. The results of operations for the three-month and six-month periods ended June 30, 2003 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2003. References should be made to the explanatory notes affecting the consolidated income and balance sheet accounts contained in Tampa Electric Company’s Annual Report on Form 10-K for the year ended Dec. 31, 2002 and to the notes on pages 39 to 46 of this report.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page No.
Consolidated Balance Sheets, June 30, 2003 and Dec. 31, 2002	33-34
Consolidated Statements of Income for the three-month and six-month periods ended June 30, 2003 and 2002	35-36
Consolidated Statements of Comprehensive Income for the three-month and six-month periods ended June 30, 2003 and 2002	37
Consolidated Statements of Cash Flows for the six-month periods ended June 30, 2003 and 2002	38
Notes to the Consolidated Financial Statements	39-46

32

TAMPA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

Unaudited

Assets (millions)	June 30, 2003			Dec. 31, 2002
Property, plant and equipment
Utility plant in service
Electric	$	4,627.1		$	4,310.8
Gas		762.5			746.7
Construction work in progress		412.3			768.5
Property, plant and equipment, at original costs		5,801.9			5,826.0
Accumulated depreciation		(2,190.0	)		(2,161.0	)
		3,611.9			3,665.0
Other property		7.8			7.9
Total property, plant and equipment		3,619.7			3,672.9
Current assets
Cash and cash equivalents		40.7			6.9
Receivables, less allowance for uncollectibles of $1.0 million at June 30, 2003 and $1.1 million at Dec. 31, 2002		201.7			186.5
Inventories
Fuel, at average cost		85.8			79.1
Materials and supplies		47.2			48.1
Prepayments and other		22.2			18.4
Total current assets		397.6			339.0
Deferred debits
Deferred income taxes		134.3			133.3
Unamortized debt expense		24.3			23.7
Regulatory assets		178.2			163.2
Other		(1.2	)		5.6
Total deferred debits		335.6			325.8
Total assets	$	4,352.9		$	4,337.7

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

33

TAMPA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

Unaudited

Liabilities and Capital (millions)	June 30, 2003		Dec. 31, 2002
Capital
Common stock	$	1,417.1	$	1,535.1
Retained earnings		259.8		302.9
Total capital		1,676.9		1,838.0
Long-term debt, less amount due within one year		1,595.9		1,345.6
Total capitalization		3,272.8		3,183.6
Current liabilities
Long-term debt due within one year		6.1		81.0
Notes payable		30.0		10.5
Accounts payable		135.8		178.8
Current derivative liabilities		0.9		—
Customer deposits		99.0		94.6
Interest accrued		28.7		18.3
Taxes accrued		33.6		46.9
Total current liabilities		334.1		430.1
Deferred credits
Deferred income taxes		501.2		483.1
Investment tax credits		24.9		27.1
Regulatory liabilities		96.7		98.1
Other		123.2		115.7
Total deferred credits		746.0		724.0
Total liabilities and capital	$	4,352.9	$	4,337.7

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

34

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

Unaudited

	Three months ended June 30,
(millions)	2003			2002
Revenues
Electric (includes franchise fees and gross receipts taxes of $16.4 million in 2003, $16.4 million in 2002)	$	407.5		$	413.1
Gas (includes franchise fees and gross receipts taxes of $3.0 million in 2003, $2.3 million in 2002)		94.8			77.3
Total revenues		502.3			490.4
Expenses
Operations
Fuel		124.9			117.0
Purchased power		50.9			63.5
Cost of natural gas sold		52.3			38.2
Other		61.3			68.0
Maintenance		22.8			27.7
Depreciation		65.4			54.3
Taxes, federal and state income		23.5			26.1
Taxes, other than income		34.2			34.1
Total expenses		435.3			428.9
Income from operations		67.0			61.5
Other income
Allowance for other funds used during construction		4.1			5.7
Other income, net		0.5			0.3
Total other (expense) income		4.6			6.0
Interest charges
Interest on long-term debt		26.3			17.4
Other interest		2.6			2.5
Allowance for borrowed funds used during construction		(1.6	)		(2.2	)
Total interest charges		27.3			17.7
Net income	$	44.3		$	49.8

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

35

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

Unaudited

	Six months ended June 30,
(millions)	2003			2002
Revenues
Electric (includes franchise fees and gross receipts taxes of $30.3 million in 2003, $30.3 million in 2002)	$	749.4		$	758.6
Gas (includes franchise fees and gross receipts taxes of $7.9 million in 2003, $5.6 million in 2002)		221.7			162.7
Total revenues		971.1			921.3
Expenses
Operations
Fuel		204.3			214.3
Purchased power		104.5			102.7
Cost of natural gas sold		123.1			73.5
Other		122.1			131.3
Maintenance		44.2			54.6
Depreciation		119.8			107.3
Taxes, federal and state income		50.2			50.4
Taxes, other than income		68.2			67.2
Total expenses		836.4			801.3
Income from operations		134.7			120.0
Other income
Allowance for other funds used during construction		11.7			10.0
Other income, net		0.2			0.7
Asset impairment (net of income tax benefit of $30.7)		(48.9	)		—
Total other (expense) income		(37.0	)		10.7
Interest charges
Interest on long-term debt		49.9			34.1
Other interest		5.1			4.8
Allowance for borrowed funds used during construction		(4.5	)		(3.8	)
Total interest charges		50.5			35.1
Net income	$	47.2		$	95.6

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

36

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Unaudited

	Three months ended June 30,				Six months ended June 30,
(millions)	2003		2002		2003		2002
Net income	$	44.3	$	49.8	$	47.2	$	95.6
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges		—		—		—		0.1
Other comprehensive income, net of tax		—		—		—		0.1
Comprehensive income	$	44.3	$	49.8	$	47.2	$	95.7

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

37

TAMPA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Unaudited

	Six months ended June 30,
(millions)	2003			2002
Cash flows from operating activities
Net income	$	47.2		$	95.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		119.8			107.3
Deferred income taxes		10.4			(26.0	)
Asset impairment, pretax		79.6			—
Investment tax credits, net		(2.2	)		(2.2	)
Allowance for funds used during construction		(16.2	)		(13.9	)
Deferred recovery clause		(17.4	)		51.3
Refund to customers		—			(2.0	)
Receivables, less allowance for uncollectibles		(15.1	)		(45.3	)
Inventories		(5.9	)		(17.2	)
Prepayments		(2.9	)		(3.2	)
Taxes accrued		(17.6	)		45.3
Interest accrued		10.3			4.2
Accounts payable		(43.0	)		(2.1	)
Other		31.4			17.1
Cash flows from operating activities		178.4			208.9
Cash flows from investing activities
Capital expenditures		(147.0	)		(379.6	)
Allowance for funds used during construction		16.2			13.8
Cash flows from investing activities		(130.8	)		(365.8	)
Cash flows from financing activities
Proceeds from contributed capital from parent		—			199.0
Return of capital		(118.0	)		—
Proceeds from long-term debt		250.0			147.1
Repayment of long-term debt		(75.0	)		(0.4	)
Funds held by trustee – restricted cash		—			(146.3	)
Net increase (decrease) in short-term debt		19.5			32.2
Payment of dividends		(90.3	)		(87.2	)
Cash flows from financing activities		(13.8	)		144.4
Net (decrease) in cash and cash equivalents		33.8			(12.5	)
Cash and cash equivalents at beginning of period		6.9			15.4
Cash and cash equivalents at end of period	$	40.7		$	2.9

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

38

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

The significant accounting policies are as follows:

Principles of Consolidation

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc, and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP).

Revenue Recognition

The regulated utilities’ (Tampa Electric and Peoples Gas System) retail businesses and the prices charged to customers are regulated by the Florida Public Service Commission (FPSC). Tampa Electric’s wholesale business is regulated by the Federal Energy Regulatory Commission (FERC). As a result, the regulated utilities qualify for the application of Financial Accounting Standard No. (FAS) 71, Accounting for the Effects of Certain Types of Regulation. See Note 3 for a discussion of the applicability of FAS 71 to the company.

Purchased Power

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. For the three and six months ended June 30, 2003, Tampa Electric purchased power of $50.9 million and $104.5 million, respectively, compared to purchases of $63.5 million and $102.7 million, respectively, for the same periods last year. These purchased power costs are recoverable through an FPSC-approved cost recovery clause.

Depreciation

Tampa Electric 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. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property was 4.3% and 4.2% for the six months ended June 30, 2003 and 2002, respectively. For the three months ended June 30, 2003, Tampa Electric recognized depreciation expense of approximately $13 million related to accelerated depreciation of certain Gannon power station coal-fired assets, in accordance with a regulatory order issued by the FPSC. This amount reflects two quarters of accelerated depreciation expense, as required to be recognized under the regulatory order issued in the second quarter of 2003.

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. As regulated utilities, Tampa Electric and Peoples Gas must file depreciation and dismantlement studies periodically and receive approval from the Florida Public Service Commission 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. At Jan. 1, 2003, the estimated accumulated cost of removal and dismantlement included in net accumulated depreciation was approximately $442.0 million. At June 30, 2003, the cost of removal and dismantlement component of accumulated depreciation was approximately $451 million.

The implementation of FAS 143, Accounting for Asset Retirement Obligations in 2003 resulted in an increase in the carrying amount of long-lived assets. The adjusted capitalized amount is depreciated over the remaining useful life of the asset (see Note 4).

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Tampa Electric Company is allowed to recover certain costs incurred from customers through prices approved by the regulatory process. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statement of Income. For the three months ended June 30, 2003 and 2002 these amounts totaled $19.4 million, and $18.7 million, respectively, and for the six months ended June 30, 2003 and 2002 these amounts totaled $38.2 million and $35.9 million, respectively. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statement of Income in “Taxes, other than income”. For the three months ended June 30, 2003 and 2002, these totaled $19.4 million and $18.7 million, respectively, and for the six months ended June 30, 2003 and 2002, they totaled $38.1 million and $35.9 million, respectively.

39

Asset Impairments

Effective Jan. 1, 2002, Tampa Electric Company adopted FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes 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 segment of a business.

In accordance with FAS 144, the company assesses whether there has been an other-than-temporary impairment of its long-lived assets and certain intangibles held and used by the company when such impairment indicators exist. Except as discussed in Note 7 relating to certain long-term turbine purchase contracts, no significant events or changes in circumstances occurred during the six months ended June 30, 2003 to indicate an impairment of long-lived assets.

Restrictions on Dividend Payments and Transfer of Assets

Tampa Electric’s first mortgage bonds and certain of PGS’ long-term debt issues contain provisions that limit the dividend payment on Tampa Electric Company’s common stock. At June 30, 2003, substantially all of the company’s retained earnings were available for dividends on its common stock.

2. Derivatives and Hedging

At June 30, 2003, the company had a net derivative liability of $0.9 million compared to a net derivative asset of $3.5 million at Dec. 31, 2002. The amounts recorded in accumulated other comprehensive income (OCI), as of June 30, 2003 and Dec. 31, 2002, are fully offset by regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the results of hedging activities.

As of June 30, 2003, the company had transactions in place to hedge commodity price risk that qualify for cash flow hedge accounting treatment under FAS 133. During the three and six months ended June 30, 2003, the company reclassified net pretax losses of $0.2 million and gains of $7.2 million, respectively, to earnings for cash flow hedges, compared to pretax losses of $0.1 million for the six months ended June 30, 2002. No amounts were reclassified to earnings for the three months ended June 30, 2002. Amounts reclassified from OCI were primarily related to cash flow hedges of physical purchases of natural gas. For these types of hedge relationships, the gain or loss on the derivative, reclassified from OCI to earnings, is offset by a regulatory asset or liability, reflecting the fact that all fuel hedging activity is subject to the fuel recovery clause (see Note 3).

Based on the fair values of derivatives at June 30, 2003, pretax gains of $7.2 million are expected to be reversed from OCI to the Consolidated Statement of Income within the next twelve months. However, these gains 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 2004.

3. 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 generally accepted accounting principles 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 June 30, 2003 and Dec. 31, 2002 are presented in the following table:

40

Regulatory Assets and Liabilities

(millions)	June 30, 2003		Dec. 31, 2002
Regulatory assets:
Regulatory tax asset (1)	$	58.3	$	54.9
Other:
Cost recovery clauses		51.1		34.7
Coal contract buy-out (2)		4.1		5.4
Unamortized refinancing costs (3)		34.0		35.9
Environmental remediation		20.7		20.3
Competitive rate adjustment		5.5		7.4
Other		4.5		4.6
		119.9		108.3
Total regulatory assets	$	178.2	$	163.2
Regulatory liabilities:
Regulatory tax liability (1)	$	33.5	$	36.6
Other:
Deferred allowance auction credits		2.1		2.1
Cost recovery clauses		1.2		2.2
Environmental remediation		20.7		20.3
Transmission and distribution storm reserve		38.0		36.0
Deferred gain on property sales (4)		1.2		0.9
		63.2		61.5
Total regulatory liabilities	$	96.7	$	98.1

(1) Related primarily to plant life. Includes excess deferred taxes of $18.9 million and $20.9 million as of June 30, 2003 and Dec. 31, 2002, respectively.

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

(3) Unamortized refinancing costs:

Related to debt transactions as follows (millions):	Amortized until:
$  50.0	2004
$  51.6	2005
$  22.1	2007
$  25.0	2011
$  50.0	2011
$150.0	2012
$150.0	2012
$  85.9	2014
$  25.0	2021
$100.0	2022

(4) Amortized over a 5-year period with various ending dates.

4. Asset Retirement Obligations

On Jan. 1, 2003, Tampa Electric Company 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 for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under existing or enacted law, statute, 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.

41

As a result of the adoption of FAS 143, Tampa Electric Company recorded an increase to net property, plant and equipment of $0.1 million (net of accumulated depreciation), an increase in regulatory asset of $0.2 million, and an increase to asset retirement obligation of $0.3 million. The after-tax charge recorded as a change in accounting principle was not material.

For the three and six months ended June 30, 2003, accretion expense associated with asset retirement obligations for Tampa Electric Company was not material. During this period, no new retirement obligations were incurred and no revisions were made to estimated cash flows used in determining the recognized asset retirement obligations. FAS 143 was not effective for the three and six months ended June 30, 2002.

5. Short-term Debt

Notes payable Dec. 31, 2002 consisted of $10.5 million of commercial paper with a weighted average interest rate of 1.86%. Tampa Electric Company has a bank credit facility of $300 million with a maturity date of November 2003. At June 30, 2003, $30.0 million of the credit facility was drawn, while none was drawn at Dec. 31, 2002. The credit facility requires commitment fees of 15 basis points, and drawn amounts are charged interest at LIBOR plus 105-117.5 basis points at current ratings.

6. Long-term Debt

In April 2003, Tampa Electric Company issued $250 million of 6.25% Senior Notes, due in 2016, in a private placement. This transaction was in lieu of a previously announced sale/leaseback of the Polk gasifier facility. Net proceeds of $248.4 million were used to repay short-term indebtedness and for general corporate purposes at Tampa Electric Company. Those 6.25% Senior Notes contain covenants that (1) require Tampa Electric Company to maintain, as of the last day of each fiscal quarter, a debt-to-capital ratio, as defined in the agreement, that does not exceed 60%, and (2) prohibit the creation of any lien on any of its property in excess of $787 million, with certain exceptions as defined, without equally and ratably securing the 6.25% Senior Notes.

In April and May 2003, Tampa Electric Company’s senior secured and unsecured debt ratings were lowered to A3 and Baa1, respectively, with a stable outlook by Moody’s, A- and BBB+, respectively, with a negative outlook by Fitch, and BBB- for both, with a negative outlook, by Standard and Poor’s.

7. Asset Impairments

For the six months ended June 30, 2003, Tampa Electric Company recorded a $48.9 million, after-tax charge ($79.6 million pretax) to reflect the impact of the cancellation of turbine purchase commitments. As reported previously and in Note 10 certain turbine rights had been transferred from TPS 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.

8. Income Tax Expense

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes, primarily due to amortization of investment tax credits and AFUDC equity.

As discussed in Note 7, Tampa Electric Company recorded a $48.9 million after-tax charge for the cancellation of turbine purchase commitments. The provision for income taxes as a percent of income from unusual and infrequently occurring items for the six months ended June 30, 2003 was 38.58%.

42

Effective Income Tax Rate

	Three months ended June 30,						Six months ended June 30,
(millions)	2003			2002			2003			2002
Net income from continuing operations, excluding unusual and infrequently occurring item, net of tax (1)	$	44.1		$	49.8		$	96.1		$	95.6
Total income tax provision (benefit), excluding tax associated with unusual and infrequently occurring item (1)		23.5			26.1			50.2			50.4
Income from continuing operations before income taxes, excluding unusual and infrequently occurring item (1)	$	67.6		$	75.9		$	146.3		$	146.0
Income taxes on above at federal statutory rate of 35%	$	23.7		$	26.6		$	51.2		$	51.1
Increase (decrease) due to
State income tax, net of federal income tax		2.5			2.8			5.2			5.2
Amortization of investment tax credits		(1.1	)		(1.1	)		(2.2	)		(2.2	)
AFUDC Equity		(1.4	)		(2.0	)		(4.1	)		(3.5	)
Other		(0.2	)		(0.2	)		0.1			(0.2	)
Total income tax provision from continuing operations	$	23.5		$	26.1		$	50.2		$	50.4
Provision for income taxes as a percent of income from continuing operations, before income taxes		34.8	%		34.4	%		34.3	%		34.5	%

(1) Excludes $48.9 million after-tax ($79.6 million pretax) charges recorded for cancellation of turbine purchase commitments noted above.

9. Comprehensive Income

As discussed in Note 2, Tampa Electric Company records gains and losses on derivative instruments classified as cash flow hedges in OCI until the hedged transaction is recognized in earnings. When the hedged transaction is recognized in earnings, the company reclassifies the gain or loss from OCI to earnings. However, an equal and offsetting regulatory asset or liability is recognized in OCI and then earnings to reflect the company’s obligation to reflect such gains or losses in regulatory cost recovery clauses. As a result, the reclassification from OCI gains or losses on derivatives and the recognition of the offsetting regulatory impact, detailed below, had no net impact on the results of operations.

Tampa Electric Company reported the following comprehensive income (loss) in 2003 and 2002 related to changes in the fair value of cash flow hedges.

Comprehensive Income (loss)

(millions)
Three months ended June 30,	Gross			Tax			Net
2003
Unrealized (loss) gain on cash flow hedges	$	(0.2	)	$	(0.1	)	$	(0.1	)
Less: Loss (gain) reclassified to net income		0.2			0.1			0.1
Total other comprehensive income (loss)	$	—		$	—		$	—
2002
Unrealized (loss) gain on cash flow hedges	$	—		$	—		$	—
Less: Loss (gain) reclassified to net income		—			—			—
Total other comprehensive income (loss)	$	—		$	—		$	—
Six months ended June 30,
2003
Unrealized (loss) gain on cash flow hedges	$	7.2		$	2.8		$	4.4
Less: Loss (gain) reclassified to net income		(7.2	)		(2.8	)		(4.4	)
Total other comprehensive income (loss)	$	—		$	—		$	—
2002
Unrealized (loss) gain on cash flow hedges	$	—		$	—		$	—
Less: Loss (gain) reclassified to net income		0.1			—			0.1
Total other comprehensive income (loss)	$	0.1		$	—		$	0.1

43

10. Related Party Transactions

In February 2002, Tampa Electric and TECO-Panda Generating Company II (TPGC II), an affiliate of TECO Power Services, Inc., entered into an assignment and assumption agreement whereby Tampa Electric obtained TPGC II’s rights and interests to four combustion turbines being purchased from General Electric Company, and assumed the corresponding liabilities and obligations for such equipment. Tampa Electric planned to use this equipment for future generation expansion. 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. During the first quarter of 2003, Tampa Electric recorded a $48.9 million after-tax charge related to the cancellation of turbine purchase commitments.

In the second quarter of 2003, Tampa Electric returned to TECO Energy $118 million of capital which was previously contributed by TECO Energy to support Tampa Electric’s construction program.

11. Segment Information

Contribution by operating division is presented below:

Segment Information

(millions) Three months ended June 30,	Tampa Electric			Peoples Gas		Other & Eliminations			Tampa Electric Company
2003
Revenues - outsiders	$	406.9		$	94.8	$	—		$	501.7
Sales to affiliates		0.8			—		(0.2	)		0.6
Total revenues	$	407.7		$	94.8	$	(0.2	)	$	502.3
Depreciation		57.3			8.1		—			65.4
Interest charge		23.4			3.9		—			27.3
Provision (benefit) for taxes		20.7			3.0		—			23.7
Net income	$	39.5		$	4.8	$	—		$	44.3
2002
Revenues - outsiders	$	403.8		$	77.3	$	—		$	481.1
Sales to affiliates		9.5			—		(0.2	)		9.3
Total revenues	$	413.3		$	77.3	$	(0.2	)	$	490.4
Depreciation		46.6			7.7		—			54.3
Interest charge		14.2			3.5		—			17.7
Provision (benefit) for taxes		23.3			2.8		—			26.1
Net income	$	45.4		$	4.4	$	—		$	49.8
(millions)
Six months ended June 30,
2003
Revenues - outsiders	$	748.0		$	221.7	$	—		$	969.7
Sales to affiliates		1.8			—		(0.4	)		1.4
Total revenues	$	749.8		$	221.7	$	(0.4	)	$	971.1
Depreciation		103.3			16.5		—			119.8
Interest charge		42.6			7.9		—			50.5
Provision (benefit) for taxes		8.9	(1)		10.6		—			19.5
Net income	$	30.5	(1)	$	16.7	$	—		$	47.2
2002
Revenues - outsiders	$	742.5		$	162.7	$	—		$	905.2
Sales to affiliates		16.5			—		(0.4	)		16.1
Total revenues	$	759.0		$	162.7	$	(0.4	)	$	921.3
Depreciation		92.2			15.1		—			107.3
Interest charge		28.1			7.0		—			35.1
Provision (benefit) for taxes		41.5			8.9		—			50.4
Net income	$	81.4		$	14.2	$	—		$	95.6

(1) Net income includes a $48.9 million after-tax ($79.6 million pretax) asset impairment related to turbine purchase cancellations (see Note 7).

44

12. Commitments and Contingencies

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company is a potentially responsible party 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 June 30, 2003, Tampa Electric Company has estimated its ultimate financial liability to be approximately $21 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 potentially responsible parties (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.

Guarantees and Letters of Credit

Tampa Electric Company has outstanding letters of credit of $0.9 million at June 30, 2003.

In addition, Tampa Electric Company enters into commercial agreements in the normal course of business that typically contain standard indemnification clauses. Tampa Electric Company may sometimes agree to make payments to compensate or indemnify the counter-party for legal fees, environmental remediation costs and other similar costs arising from possible future events or changes in laws or regulations. These agreements cover a variety of goods and services, and have varying triggering events dependent on actions by third parties.

Tampa Electric Company is unable to estimate the maximum potential future exposure under these clauses because the events that would obligate Tampa Electric Company have not occurred, or if such event has occurred, Tampa Electric Company has not been notified of its occurrence. As claims are made or changes in laws or regulations indicate, an amount related to the indemnification is reflected in the financial statements.

Financial Covenants

A summary of Tampa Electric Company’s significant financial covenants as of June 30, 2003 is as follows:

Tampa Electric Company’s Significant Financial Covenants

(millions) Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at June 30, 2003
Tampa Electric
Mortgage bond indenture	Dividend restriction	Cumulative distributions cannot exceed cumulative net income plus $4	$147 unrestricted
PGS senior notes	EBIT/interest	Minimum of 2.0 times	3.4 times
	Restricted payments	Shareholder equity at least $500	$1,677
	Funded debt/capital	Cannot exceed 65%	50.7%
	Sale of assets	Less than 20% of total assets	0%
Credit facility	Debt/capital	Cannot exceed 60%	49.3%
	EBITDA/interest	Minimum of 2.5 times	7.3 times
6.25% senior notes	Debt/capital	Cannot exceed 60%	49.3%
	Limit on liens	Cannot exceed $787	$362

1) As defined in each applicable instrument.

45

13. New Accounting Pronouncements

Accounting for Asset Retirement Obligations

In July 2001, the FASB issued FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability at fair value for an asset retirement obligation in the period in which it is incurred. FAS 143 is effective for fiscal years beginning after June 15, 2002. See Note 4 for the full discussion of the impact of adoption.

Exit or Disposal Costs

In July 2002, the FASB issued FAS 146, Accounting for Costs Associated with Exit or Disposal Activities, which addresses the accounting for costs under certain circumstances, including costs to terminate a contract that is not a capital lease, costs to consolidate facilities or relocate employees, and termination benefits provided to employees that are involuntarily terminated under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred compensation contract. FAS 146 is effective for disposal activities initiated after Dec. 31, 2002 with early adoption allowed. Tampa Electric Company opted to early adopt FAS 146 on July 1, 2002. For the three and six months ended June 30, 2003 no costs were recognized in accordance with FAS 146. For the same period in 2002, the accounting standard was not yet effective.

Guarantees

In November 2002, the FASB issued FIN 45, which modifies the accounting and enhances the disclosure of certain types of guarantees. FIN 45 requires that upon issuance of certain guarantees, the guarantor must recognize a liability for the fair value of the obligation it assumes under the guarantee. The provisions for the initial recognition and measurement are to be applied to guarantees issued or modified after Dec. 31, 2002. The disclosure requirements are effective for financial statements of annual periods that end after Dec. 15, 2002 (see Note 12). On Jan. 1, 2003, Tampa Electric Company adopted the prospective measurement provisions without a material effect.

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 C16, “Applying the Normal Purchases and Normal Sales Exception to Contracts That Combine a Forward Contract and a Purchased Option Contract”. In limited circumstances when the criteria are met and documented, Tampa Electric designates option-type and combined option and forward contracts 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 C16 into the standard will not have a material impact on the financial statements of Tampa Electric Company.

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 June 30, 2003. The company does not anticipate that the adoption of the additional guidance in FAS 149 will have a material impact on its 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 remeasured 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 June 15, 2003. Tampa Electric Company is continuing to determine the estimated impact of the adoption of this standard.

46

Item 2. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. These forward-looking statements include references to TECO Energy’s anticipated capital investments, financing requirements, project completion dates, future transactions and other plans. These statements are subject to the inherent uncertainties in predicting future results and conditions. Certain factors that could cause actual results to differ materially from those projected in these forward-looking statements include the following: energy price changes affecting TECO Power Services’ (TPS’) plants; TPS’ ability to sell the output of its merchant plants and to complete commercial operation of the Gila River facility on time and on budget; any unanticipated need for additional debt or equity capital that might result from lower than expected cash flow or higher than projected capital requirements; and TECO Energy’s ability to successfully complete the sale of interests in its synthetic fuel business and other assets. The sale of TECO Coal’s synthetic fuel business and TECO Coal’s ability to successfully operate its synthetic fuel production facilities in a manner qualifying for Section 29 federal income tax credits could be impacted by changes in law, regulation or administration, such as the current suspension of the issuance of private letter rulings (PLRs) by the Internal Revenue Service (IRS). Other factors include: general economic conditions, particularly those in Tampa Electric’s service area affecting energy sales; weather variations affecting energy sales and operating costs; and commodity price changes affecting Tampa Electric, Peoples Gas System, and TECO Coal. Taxable income in 2003 could be lower than forecast, which could impact the company’s ability to utilize Section 29 tax credits, and in such event, earnings could be reduced and the intra-period tax benefit deferral might not be fully reversed. Some of these factors and others are discussed more fully under “Investment Considerations” in TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2002, and reference is made thereto.

Earnings Summary - Unaudited

	Three months ended June 30,					Six months ended June 30,
(millions, except per share amounts)	2003			2002		2003			2002
Consolidated revenues	$	737.2		$	677.7	$	1,395.7		$	1,284.3
Net (loss) income from continuing operations (1)	$	(101.9	)	$	80.9	$	(121.2	)	$	150.8
Discontinued operations (2)		—			4.8		23.1			10.3
Cumulative effect of change in accounting		—			—		(1.1	)		—
Net (loss) income	$	(101.9	)	$	85.7	$	(99.2	)	$	161.1
Average common shares outstanding
Basic		176.4			144.2		176.2			142.3
Diluted		176.6			144.7		176.5			142.7
Earnings per share - basic
Continuing operations (1)	$	(0.58	)	$	0.56	$	(0.69	)	$	1.06
Discontinued operations (2)		—			0.03		0.13			0.07
Cumulative effect of change in accounting		—			—		—			—
Earnings per share - basic	$	(0.58	)	$	0.59	$	(0.56	)	$	1.13
Earnings per share - diluted
Continuing operations (1)	$	(0.58	)	$	0.56	$	(0.69	)	$	1.06
Discontinued operations (2)		—			0.03		0.13			0.07
Cumulative effect of change in accounting		—			—		—			—
Earnings per share - diluted	$	(0.58	)	$	0.59	$	(0.56	)	$	1.13

(1) Results for the three months ended June 30, 2003 include the effect of after-tax charges of $155.9 million related to the joint venture termination and goodwill impairments. Results for the six months ended June 30, 2003 include these items and $64.2 million after-tax related to turbine purchase cancellations in 2003.

(2) Includes results from discontinued operations (TECO Coalbed Methane).

47

Operating Results

Three Months Ended June 30, 2003:

TECO Energy, Inc. (the company) reported a second quarter net loss of $101.9 million, compared with net income of $85.7 million for the same period in 2002. The loss on an earnings per share basis was $0.58 for the second quarter, compared with earnings per share of $0.59 in the 2002 period. These results include $94.7 million of after-tax ($153.9 million pretax) accounting charges related to the partnership termination and resulting consolidation of Panda Energy’s interest in the Union and Gila River power stations; $61.2 million after-tax ($95.2 million pretax) of goodwill impairments required under FAS 142, Goodwill and Other Intangible Assets, for the Frontera Power Station in Texas and the Commonwealth Chesapeake Power Station in Virginia; and the recognition of $15.4 million of previously deferred tax credits for the production of synthetic fuel deferred in the first quarter. See TECO Energy’s Form 8-K dated July 23, 2003, for a reconciliation of net income in accordance with generally accepted accounting principles (GAAP) to a non-GAAP income that adjusts for the items discussed above. The company believes that non-GAAP net income from continuing operations that excludes the impact of these charges provides useful supplemental information because it assists in an evaluation of the company’s ongoing operations.

The $153.9 million of pretax charges recorded in the second quarter primarily related to the partnership termination and the resulting consolidation of TECO-Panda Generating Company (TPGC) that would have occurred in the normal course of business in the third quarter as the consolidation of TPGC would have been required under FIN 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, effective July 1, 2003.

Tampa Electric Company - Electric division (Tampa Electric)

Tampa Electric’s net income for the second quarter was $39.5 million, compared with $45.4 million for the same period in 2002. The equity component of allowance for funds used during construction (AFUDC, which represents allowed equity cost capitalized to construction costs), primarily from the Gannon to Bayside repowering project, decreased to $4.1 million for the quarter from $5.7 million for the same period in 2002, reflecting the commercial operation of Bayside Unit 1 in April 2003. Retail energy sales decreased 1.7% in the quarter, as average customer growth of 2.5% was offset by milder weather and decreased sales to industrial phosphate customers. Lower operations and maintenance expenses for the quarter reflected lower expenditures on generating units and costs associated with a small-scale employee retirement program recorded in 2002. Depreciation expense increased, reflecting $13 million pretax, or two quarters, of accelerated depreciation on the Gannon coal assets scheduled for retirement at the end of 2003 and normal electric plant additions to support customer growth. Interest expense increased due to higher long-term debt balances.

A summary of operating statistics for the three months ended June 30, 2003 and 2002 follows:

(in millions, except retail customers) Three months ended June 30,	Operating Revenues							Kilowatt-hour sales
	2003		2002			% Change		2003	2002	% Change
Residential	$	190.7	$	193.5		(1.4	)	2,028.7	2,069.2	(2.0	)
Commercial		118.9		119.5		(0.5	)	1,496.1	1,525.0	(1.9	)
Industrial – Phosphate		17.2		21.5		(20.0	)	329.4	376.8	(12.6	)
Industrial – Other		22.9		21.7		5.5		331.1	319.2	3.7
Other sales of electricity		32.1		29.6		8.4		390.5	364.2	7.2
Deferred and other revenues		6.5		(0.4	)	—		—	—	—
		388.3		385.4		0.8		4,575.8	4,654.4	(1.7	)
Sales for resale		11.2		18.6		(39.8	)	184.4	321.3	(42.6	)
Other operating revenue		8.2		9.3		(11.8	)	—	—	—
	$	407.7	$	413.3		(1.3	)	4,760.2	4,975.7	(4.3	)
Retail customers (thousands)		602.9		588.4		2.5		—	—
Retail output to line (kilowatt hours)								5,006.0	4,968.8	0.7

Tampa Electric Company – Natural Gas Division (Peoples Gas System)

Peoples Gas System reported net income of $4.8 million for the quarter, compared with $4.4 million recorded in the same period in 2002. Quarterly results reflected customer growth of 5.2%, offset by mild weather early in the quarter and lower volumes for the low-margin transportation service for interruptible customers and electric power generators due to higher gas prices. These customers are sensitive to the commodity price of gas, and many have the ability to switch to alternative fuels or to simply alter consumption patterns.

48

A summary of operating statistics for the three months ended June 30, 2003 and 2002 follows:

(in millions, except average customers) Three months ended June 30,	Operating revenues						Therms
	2003		2002		% Change		2003	2002	% Change
By Customer Segment:
Residential	$	20.1	$	14.9	34.9		10.6	10.2	3.9
Commercial		31.7		28.6	10.9		80.3	76.5	5.0
Industrial		2.4		3.1	(22.6	)	54.7	64.5	(15.2	)
Off system sales		29.5		20.7	42.5		47.7	52.5	(9.2	)
Power generation		2.7		3.0	(10.0	)	91.1	136.9	(33.4	)
Other revenues		8.4		7.0	20.0		—	—	—
	$	94.8	$	77.3	22.6		284.4	340.6	(16.5	)
By Sales Type:
System supply	$	68.3	$	51.8	31.8		76.2	84.2	(9.5	)
Transportation		18.1		18.5	(2.2	)	208.2	256.4	(18.8	)
Other revenue		8.4		7.0	20.0		—	—	—
	$	94.8	$	77.3	22.6		284.4	340.6	(16.5	)
Average customers (thousands)		291.2		276.7	5.2		—	—	—

Unregulated Companies – Operating Results

TECO Power Services’ (TPS) net loss for the second quarter of 2003 was $179.4 million, compared with net income of $8.9 million for the same period in 2002. Excluding the $155.9 million of after-tax charges recorded in the quarter, the loss for the second quarter was $23.5 million. Included in reported results were the operating losses from the Union and Gila River stations, higher interest expense due to lower capitalized interest and the end of interest income on the loan to Panda related to the Texas Independent Energy projects (TIE) and the notes receivable from TPGC, which were reduced by improved operating results at the Hardee and Frontera power stations and continued strong earnings at the Guatemalan operations. See Notes 4, 11 and 15 to the TECO Energy Consolidated Financial Statements for additional details related to the joint venture termination and associated charges.

TECO Transport recorded net income of $5.2 million in the second quarter, compared with $4.2 million for the same period last year. These results include a $1.5 million after-tax gain on the disposition of ocean-going equipment no longer used by TECO Ocean Shipping, and reflect weak pricing and lower northbound river shipments, lower Tampa Electric volumes as a result of the Bayside repowering, and higher fuel and repair costs.

TECO Coal achieved second quarter net income of $20.8 million, compared to $19.7 million in the same period in 2002. Results for the quarter were driven primarily by lower volumes of conventional metallurgical and steam coals, which were more than offset by higher volumes of synthetic fuel. These results also reflect gains recognized on the installment sale of the 49.5-percent interest in the synfuel facilities to a third party. See the Liquidity, Capital Resources section for a discussion of factors related to synfuel which could impact future results.

TECO Energy’s other unregulated companies recorded a net loss of $1.8 million for the second quarter, compared to net income of $2.1 million for the same period in 2002. Results for the quarter were driven primarily by lower results at TECO Energy Services and Prior Energy.

Other Charges Affecting Net Income

In April 2003, TECO Energy reported that it would terminate its partnership with Panda Energy and consolidate the partnership which owns the Union and Gila River power stations in the second quarter and that it expected to record charges as a result of that termination and resulting consolidation. In the second quarter, TECO Power Services recorded $94.7 million, $0.54 on a per share basis, in after-tax charges as a result of that transaction for items that included the cost of the termination, Panda’s negative equity balance and other charges as a result of the consolidation. In addition, this termination, and the resulting significant change in defined reporting units, triggered a review of goodwill on all domestic generating projects under FAS 142, which resulted in the write off of all goodwill associated with the Frontera and Commonwealth Chesapeake power stations totaling $61.2 million after-tax, or $0.35 on a per share basis. See Notes 4 and 11 to the TECO Energy Consolidated Financial Statements for additional details related to the termination and associated charges.

49

Other Income (Expense)

Other income (expense) for the second quarter was $113.2 million of expense, compared with $19.1 million of income for the same period last year. Excluding the $153.9 million pretax expense ($94.7 million after-tax) recorded for the loss on the joint venture termination as discussed above, Other income was $40.7 million for the three months ended June 30, 2003.

Equity AFUDC at Tampa Electric, which is included in Other income, was $4.1 million and $5.7 million for the three months ended June 30, 2003 and 2002, respectively. AFUDC has decreased, primarily as a result of the commercial operation of Bayside Unit 1 in April 2003.

Interest Charges

Interest expense was $86.7 million for the three months ended June 30, 2003, compared with $41.6 million for the same period last year. The significant increase reflects the additional interest expense on the non-recourse project debt at TPGC which is now consolidated as a result of the termination of the joint venture with Panda Energy, lower capitalized interest due to suspension of construction on the Dell and McAdams power stations at the end of 2002, and higher overall levels of debt in support of TECO Energy’s capital investment program.

Income Taxes

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before taxes, primarily due to the recognition of non-conventional fuels tax credits and other miscellaneous items. The full-year-estimate of the non-conventional fuels tax credit for 2003 is approximately $44 million.

Results for the quarter included a $15.4 million intra-period tax benefit to adjust the company’s effective tax rate for the period to reflect the estimated annual tax rate in accordance with GAAP. The intra-period tax benefit is primarily due to Section 29 tax credits from the production of synfuel at TECO Coal and represents reversal of a portion of the $25.9 million deferred in the first quarter. In prior years, synfuel production and recognition of the associated tax credits occurred more ratably throughout the year and thus did not result in an intra-period effect. Due to TECO Energy’s sale of its interest in the company’s synthetic fuel production capabilities, announced April 11, 2003, the amount of tax credits generated for the company’s use will be significantly less in the last three quarters of 2003 than in the first quarter of 2003. Based on the company’s annual effective income tax rate expected for 2003, the remainder of the first quarter deferral of $25.9 million is expected to reverse by year-end, having no net impact for the full year 2003 results.

The provision for income taxes as a percent of income from unusual and infrequently occurring items for the three months ended June 30, 2003 was 37.2%. The income tax effect of gains and losses from the discontinued operations of TECO Coalbed Methane is shown as a component of results from discontinued operations.

Six Months Ended June 30, 2003:

TECO Energy’s year-to-date net loss was $99.2 million, compared with net income of $161.1 million for the same period in 2002. The loss on an earnings per share basis was $0.56, compared with earnings per share of $1.13 for the same period in 2002. In addition to the second quarter charges, these results also include a $64.2 million after-tax write-off in the first quarter related to turbine purchase cancellations, $10.5 million of net intra-period tax benefit deferrals and a $1.1 million after-tax charge for the cumulative effect of an accounting change to reflect the adoption of FAS 143, Accounting for Asset Retirement Obligations. These results also include a $23.1 million after-tax gain from discontinued operations, primarily from the completion of the sale of TECO Coalbed Methane in the first quarter.

Tampa Electric Company - Electric division (Tampa Electric)

Tampa Electric’s year-to-date net income was $30.5 million, compared to $81.4 million in 2002. Year-to-date net income for 2003 excluding the $48.9 million charge recorded in the first quarter related to turbine purchase cancellations was $79.4 million. The equity component of AFUDC increased to $11.7 million, from $10.0 million for the same period in 2002, primarily from the Gannon to Bayside repowering project. These results also reflect customer growth of 2.4% and retail energy sales 1.4% higher than in the same period in 2003. Depreciation expense increased, and operations and maintenance expense decreased as a result of the factors discussed for the quarter.

50

A summary of operating statistics for the six months ended June 30, 2003 and 2002 follows:

(in millions, except average customers) Six months ended June 30,	Operating Revenues							Kilowatt-hour sales
	2003		2002			% Change		2003	2002	% Change
Residential	$	359.8	$	356.2		1.0		3,907.4	3,783.6	3.3
Commercial		215.7		222.3		(3.0	)	2,762.7	2,810.7	(1.7	)
Industrial - Phosphate		33.1		37.7		(12.2	)	664.4	693.6	(4.2	)
Industrial - Other		42.1		40.8		3.2		630.4	602.5	4.6
Other sales of electricity		58.6		55.8		5.0		721.8	676.1	6.8
Deferred and other revenues		1.2		(9.8	)	(112.2	)	—	—	—
		710.5		703.0		1.1		8,686.7	8,566.5	1.4
Sales for resale		22.4		31.9		(29.8	)	386.3	486.8	(20.6	)
Other operating revenue		16.9		24.1		(29.9	)	—	—	—
	$	749.8	$	759.0		(1.1	)	9,073.0	9,053.3	0.2
Retail customers (thousands)		601.9		587.8		2.4		—	—	—
Retail output to line (kilowatt hours)								9,291.0	9,067.3	2.5

Tampa Electric Company – Natural Gas Division (Peoples Gas System)

Peoples Gas System reported year-to-date net income of $16.7 million, compared with $14.2 million in the same period in 2002. Customer growth of approximately 5%, favorable winter weather in the first quarter and a base rate increase effective in January 2003 contributed to these results.

A summary of operating statistics for the six months ended June 30, 2003 and 2002 follows:

(in millions, except average customers) Six months ended June 30,	Operating revenues						Therms
	2003		2002		% Change		2003	2002	% Change
By Customer Segment:
Residential	$	61.7	$	40.7	51.6		40.3	35.4	13.8
Commercial		79.4		64.3	23.5		186.4	172.4	8.1
Industrial		5.4		6.5	(16.9	)	114.1	131.9	(13.5	)
Off system sales		51.4		31.1	65.3		81.8	85.9	(4.8	)
Power generation		5.1		5.8	(12.1	)	177.7	253.1	(29.8	)
Other revenues		18.7		14.3	30.8		—	—	—
	$	221.7	$	162.7	36.2		600.3	678.7	(11.5	)
By Sales Type:
System supply	$	163.9	$	109.6	49.5		170.5	175.8	(3.0	)
Transportation		39.1		38.8	0.8		429.8	502.9	(14.5	)
Other revenue		18.7		14.3	30.8		—	—	—
	$	221.7	$	162.7	36.2		600.3	678.7	(11.5	)
Average customers (thousands)		290.4		276.3	5.1		—	—	—

Unregulated Companies – Operating Results

TECO Power Services’ (TPS) year-to-date net loss was $197.9 million, compared with net income of $13.8 million for the same period in 2002. The 2003 year-to-date net loss excluding the $15.3 million charge recorded in the first quarter related to turbine purchase cancellations and the second quarter charges previously discussed was $26.7 million. These results reflect the recognition of TPS’ share of operating losses on the TIE projects beginning in 2003, lower net income from Frontera due to a major maintenance outage in the first quarter, and improved results at the Commonwealth Chesapeake station in the first quarter due to favorable winter weather, as well as the previously discussed factors affecting the second quarter.

TECO Transport’s year-to-date net income for 2003 was $9.0 million, compared to $11.1 million for the same period in 2002. Excluding a $0.8 million after-tax charge due to the adoption of FAS 143, year-to-date 2003 net income was $9.8 million. As noted for the second quarter results, year-to-date results include a $1.5 million after-tax gain on the disposition of ocean-going equipment no longer used by TECO Ocean Shipping, and reflect weak pricing and lower northbound river shipments, lower Tampa Electric volumes as a result of the Bayside repowering, and higher fuel and repair costs.

51

TECO Coal achieved year-to-date net income of $46.2 million, compared to $37.1 million reported in 2002. Excluding a $0.3 million after-tax charge due to the adoption of FAS 143, year-to-date 2003 net income was $46.5 million. Results were driven primarily by higher volumes of synthetic fuel and the sale of a 49.5-percent interest in the synfuel production facilities, which more than offset lower volumes of conventional metallurgical and steam coals and higher mining costs due to the use of marginal coals for the production of synfuel. See the Liquidity, Capital Resources section for a discussion of factors related to synfuel which could impact future results.

TECO Energy’s other unregulated companies’ year-to-date loss was $1.0 million, compared with net income of $4.6 million for the same period in 2002. These results reflect lower net income at Prior Energy and TECO Energy Services, more than offsetting increased earnings from TECO Propane Ventures.

Discontinued Operations

Year-to-date income from discontinued operations of $23.1 million reflect primarily the after-tax gain on the final installment on the sale of TECO Coalbed Methane, which was sold in December 2002 for $140 million. The final $98 million installment completing the sale was paid in January 2003.

Other Charges Affecting Net Income

As previously reported in the second quarter results, TPS recorded $94.7 million in after-tax charges ($153.9 million pretax) as a result of the termination of its partnership with Panda Energy and resulting consolidation of TPGC and a $61.2 million after-tax ($95.2 million pretax) charge to write off all goodwill associated with the Frontera and Commonwealth Chesapeake power stations. Year-to-date results also include recognition of $15.4 million of tax credits deferred in the first quarter and a $64.2 million after-tax charge related to turbine purchase cancellations recorded in the first quarter, comprised of $15.3 million at TPS and $48.9 million at Tampa Electric.

Other Income (Expense)

Year-to-date Other income (expense) was $98.5 million of expense, compared with $38.4 million of income for the same period last year. Excluding the $153.9 million pretax charge for the loss on the joint venture termination, Other income was $55.4 million for the six months ended June 30, 2003.

Equity AFUDC at Tampa Electric, which is included in Other income, was $11.7 million and $10.0 for the six months ended June 30, 2003 and 2002, respectively. AFUDC increased due to Tampa Electric’s repowering of the Gannon Station to become Bayside Station.

Interest Charges

Interest expense was $151.2 million for the six months ended June 30, 2003, compared with $88.5 million for the same period last year. Interest expense increased due to lower capitalized interest due to suspension of construction on the Dell and McAdams power stations at the end of 2002, and higher overall levels of debt in support of TECO Energy’s capital investment program. In addition, 2003 results include interest on non-recourse project debt of TPGC which was consolidated effective April 1, 2003.

Income Taxes

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before taxes, primarily due to the recognition of non-conventional fuels tax credits and other miscellaneous items. The full-year-estimate of the non-conventional fuels tax credit for 2003 is approximately $44 million.

Year-to-date results included a $10.5 million intra-period tax benefit deferral to adjust the company’s effective tax rate for the period to reflect the estimated annual tax rate in accordance with GAAP. The intra-period tax benefit deferral is primarily due to Section 29 tax credits from the production of synfuel at TECO Coal. In prior years, synfuel production and recognition of the associated tax credits occurred more ratably throughout the year and this had no significant intra-period effect. Due to TECO Energy’s sale of its interest in the company’s synthetic fuel production capabilities, announced April 11, 2003, the amount of tax credits generated for the company’s use will be significantly less in the last three quarters of 2003 than in the first quarter of 2003. The remainder of the year-to-date deferral of $10.5 million is expected to reverse by year-end, having no net impact for the full year 2003 results.

In the six months ended June 30, 2003, TECO Energy recorded charges for cancellation of turbine purchase commitments by Tampa Electric and TECO Power and charges for goodwill impairment and joint venture termination losses at TECO Power. The provision for income taxes as a percent of income from unusual and infrequently occurring items for the six months ended June 30, 2003 was 37.5%. For the six months ended June 30, 2003, net income from discontinued operations was $23.2 million and the provision for income taxes as a percent of income from discontinued operations was 39.4%.

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

52

Liquidity, Capital Resources

At June 30, 2003, TECO Energy had cash and cash equivalents of $267.9 million, excluding all restricted cash, and $611 million of availability under its bank credit facilities, net of letters of credit of $159 million outstanding under these facilities. The availability under the bank credit facilities included $270 million of the Tampa Electric $300 million facility; the $150 million undrawn Merrill Lynch facility; and the $350 million TECO Energy multi-year facility, undrawn except for the $159 million of letters of credit.

Restricted cash is comprised of $38 million of cash held in escrow under the sale agreement for the 49.5-percent interest of TECO Coal’s synfuel production facilities pending a private letter ruling (PLR) from the IRS, and $53 million at TPS primarily related to cash to be used only for construction-related purposes at the Union and Gila River power stations. Following the delivery of a PLR, approximately $28 million will be released. However, over time, up to $50 million of cash from the synfuel facility sale will accumulate in escrow to provide credit support for the company’s obligations under the sale agreement due to the company’s current credit rating.

In April 2003, TECO Coal sold a 49.5-percent interest in its synthetic fuel production facilities located at its operations in eastern Kentucky. 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 tax credit for which the production qualifies. Because the transaction was structured on a “pay-as-you-go” basis typical of similar transactions in the industry, TECO Coal received no significant cash at the time of sale. The sale is contingent upon receipt of a positive response to a PLR request, and the proceeds from this transaction are held in escrow pending resolution of this contingency. Through June 30, 2003, $38.4 million of the proceeds have been escrowed pending receipt of the PLR. The current PLR request was made to reflect the revised ownership structure, location of facilities and other terms of previous PLRs. On June 27, 2003, the IRS announced suspension of the issuance of PLRs when the audit side of the IRS raised questions about whether taxpayers were achieving “significant chemical change” and questioned the validity of the science used in the testing. TECO Energy believes that it is operating its facilities in a manner that promotes the intent of the program and in compliance with and reliance on its PLRs, and is working to achieve a successful resolution to the latest IRS suspension of issuance of PLRs in the next 45-60 days.

Cash flow from operations was a deficit of $18 million for the quarter, driven primarily by the accounting for the sale of the synfuel production facilities at TECO Coal, the benefits of which are recorded in financing and investing activities as described more fully below; the collateral posting required for energy management activities at TPS upon the downgrade to non-investment grade; the impact on working capital due to the consolidation of the Union and Gila River power stations in the second quarter; and, normal quarterly cycles in working capital primarily at Tampa Electric.

Cash flow from operations includes the operating losses of $9.00 - $11.00 per ton (pretax) normally associated with the production of synfuel, while the benefits from the sale of the synfuel production facilities of $25.00 - $30.00 per ton (pretax) are included in the investing and financing activities on the Consolidated Statement of Cash Flows. The sale of the synfuel facilities includes the cash from the gain on the sale of the assets, which is included in investing activities and is included in restricted cash. The company expects to record a quarterly gain on the sale of assets through the life of the contract. The cash paid by the owner for its portion of the operating loss from the production of synfuel is included in financing activities as a minority interest. Both of these amounts are included in restricted cash pending delivery of a PLR reflecting the revised ownership structure.

TPS was required to post collateral for its energy management operations due to the downgrade to non-investment grade in April 2003. As of June 30, 2003, collateral posted of $40 million is included in working capital as a prepaid item.

Accounts payable reflects both the effect of the April 1, 2003 consolidation of the Union and Gila River power stations at TPS, and the normal accrual and payment cycle related to year-end accruals at Tampa Electric. With the major construction activities nearing completion in the second quarter at TPS there was a higher than normal level of payments. These activities are now reflected in TECO Energy’s financial statements where they were previously recorded at the unconsolidated joint venture level.

The $250 million early repayment of the equity bridge loan that was required in April due to the downgrade to non-investment grade by Moody’s and the planned $125 million payment in April are reflected in repayment of long-term debt under financing activities in the second quarter. Also included in repayment of long-term debt are $75 million of first mortgage bonds at Tampa Electric, a $25 million capital lease repayment at TECO Transport, and non-recourse project debt payments at TPS. Proceeds from long-term debt include the net proceeds from the $250 million of thirteen year notes at Tampa Electric, the $300 million of seven year notes at TECO Energy and $106 million of non-recourse project debt at TPS. The proceeds of project debt at TPS, related to the Union and Gila power projects, reflects amounts drawn to fund project construction since the April 1, 2003 consolidation date.

TECO Energy expects to sell its Enron bankruptcy claims for approximately 15.5 cents on the dollar which would amount to a recovery of about $42 million. There will be a holdback of 20% to be released at the time of payment by Enron to the purchaser. The cash in excess of the holdback of approximately $33.5 million is expected to be paid within the next month. Under the arrangement, the pending adversary proceedings would still be prosecuted to the extent practicable with the excess recovery, if any, returned to TECO Energy. This recovery would primarily offset increases in construction costs associated with the effect of Enron’s bankruptcy on its subsidiary NEPCO, the engineering, procurement and construction contractor of four TPS projects.

53

As a result of TPS having received Panda’s interest in TPGC and the resulting consolidation, Panda owes TPS approximately $20 million pursuant to a Make-Whole and Reimbursement Agreement entered into in early 2002 and a note receivable, both of which were secured by Panda’s interest in PLC which holds a 50% interest in the Texas Independent Energy (TIE) projects, Odessa and Guadalupe. TPS currently owns 50% of PLC. TPS has initiated a strict foreclosure proceeding against Panda with respect to Panda’s interest in PLC which is expected to be concluded in the third quarter.

Estimated cash needs for 2003 include a November bank loan maturity of $350 million, and net capital spending of $442 million for normal renewal and replacement capital as well as project commitments of Tampa Electric and TPS. TECO Energy expects to rely on cash on hand, draws under credit facilities, internally generated cash from operations and proceeds from asset sales to fund these cash needs and the payment of dividends to shareholders. (See the Bank Credit Facilities and Covenants in Financing Agreements sections.) Based on its cash flow forecasts, TECO Energy expects to have at least $600 million of cash and capacity under the bank credit facilities through each quarter of 2003.

TECO Energy has identified in this Management’s Discussion & Analysis several factors that could cause its operating cash flow to be lower than forecasted. One of these factors is the margins it may realize for production from its merchant power facilities. Another factor is the timing and ultimate outcome of the Section 29 uncertainty. The company’s cash forecasts include an expectation that the sale of its synfuel facilities will provide an incremental cash benefit of $40 - $50 million in 2003 and approximately $80 million annually in 2004 - 2007. Likewise, earnings in these future periods could be affected by this uncertainty. Although TPS’ net loss in the second quarter is larger than anticipated and this pattern may continue, it is not expected to have a significant impact on expected cash flows in 2003, primarily due to the financing structure of the two largest projects.

In the second quarter of 2003, Tampa Electric returned to TECO Energy $118 million of capital which was previously contributed by TECO Energy to support Tampa Electric’s construction program.

On April 11, 2003, Tampa Electric issued $250 million of senior unsecured notes, due in 2016, in a private placement. This transaction was in lieu of a previously announced sale/leaseback of the Polk gasifier facility which was subsequently modified to be an unsecured debt transaction. Net proceeds of $248.4 million were used to repay short-term indebtedness and for general corporate purposes at Tampa Electric. On June 13, 2003, TECO Energy issued $300 million principal amount of 7.5% unsecured notes. Net proceeds of $293 million were used to repay short-term debt and for general corporate purposes including increasing cash on hand.

TECO Energy has not made a contribution to its defined benefit pension plan since the 1995 plan year because investment returns had been sufficient to cover liability growth. Negative stock market returns over the past three years reduced the over-funding of the defined benefit plan. Based on plan asset values at Jan. 1, 2003, it is estimated that TECO Energy will be required to make a $15 million contribution to its defined benefit plan in September 2004.

Bank Credit Facilities

At June 30, 2003, TECO Energy had a bank credit facility of $350 million, and Tampa Electric had a bank credit facility of $300 million, with maturity dates of November 2004 and November 2003, respectively. At June 30, 2003, $30 million was drawn on the Tampa Electric credit facility and the TECO Energy credit facility was undrawn. In November 2002, TECO Energy converted another $350 million bank credit line then in effect into a one-year term loan due November 2003.

The TECO Energy bank credit facility maturing November 2004 includes a $250 million sublimit for letters of credit. At June 30, 2003, $159.2 million of letters of credit were outstanding against that line, including $110 million related to the construction of the Union and Gila River power stations. These letters of credit of $20 million and $90 million for Union and Gila River, respectively, decline as units reach commercial operation and final acceptance is achieved. In addition, at June 30, 2003, TECO Energy and its subsidiaries had $0.2 million of letters of credit outside of its bank credit line facility outstanding. (See the Covenants in Financing Agreements section.)

On April 9, 2003, TECO Energy entered into a $350 million unsecured credit facility with Merrill Lynch that will be available if required to refinance the one-year term loan maturing in November 2003. In addition, $150 million of the facility is available for general corporate purposes until November 2003. The credit facility expires in October 2004. This facility, if drawn, could limit the payment of dividends exceeding $40 million in any quarter unless, prior to the payment of any dividends, the company delivers to Merrill Lynch liquidity projections satisfactory to Merrill Lynch demonstrating that the company will have sufficient cash or cash equivalents to pay both the dividends contemplated and each of the three quarterly dividends next scheduled to be paid on its common stock.

On June 24, 2003, TECO Energy entered into a $37.5 million credit facility with four banks, secured by the Union and Gila River assets. The proceeds from the credit facility were used in the termination of the partnership with Panda. This credit facility has covenants similar to those of the other TECO Energy credit facilities but also includes an earnings before interest, taxes, depreciation and amortization (EBITDA) to interest coverage requirement of 2.5 times, a limitation on liens of not more than 60% of the fair value of assets and a restriction on the sale of any of our interest in the Union or Gila River projects. This loan can be repaid without penalty at any time with three business days’ notice. See Note 18 to the TECO Energy Consolidated Financial Statements for a summary of performance against significant financial covenants.

54

The Tampa Electric Company bank credit facility requires commitment fees of 15 basis points, and drawn amounts are charged interest at LIBOR plus 105-117.5 basis points at current credit ratings. The TECO Energy credit facility requires commitment fees of 20-25 basis points, and drawn amounts incur interest expense at LIBOR plus 55-80 basis points at current credit ratings.

In May 2003, the Financial Accounting Standards Board issued a new accounting standard, Financial Accounting Standard No. (FAS) 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which could have a material impact on the classification and measurement of certain financial instruments. This standard could require that certain financial instruments, such as the company preferred securities, might be included in the liabilities section of the balance sheet. While management is continuing to assess and determine the impact the standard may have on the classification and potential measurement of TECO Energy’s consolidated financial statements, the adoption of the standard will not impact the calculation of previously discussed significant financial covenants, as these are calculated in accordance with the terms defined in the relevant agreements. See Note 20 to the TECO Energy Consolidated Financial Statements for a discussion of the new accounting guidance included in FAS 150.

Credit Ratings/Senior Unsecured Debt

On April 21, 2003, Moody’s Investor Service (Moody’s) lowered TECO Energy’s senior unsecured debt rating to Ba1 with a negative outlook. This debt ratings change triggered requirements to, within fifteen days, post letters of credit or repay the $250 million unpaid balance of the equity bridge loan and to provide security for certain obligations associated with the nearly complete Union and Gila River power stations. These requirements are discussed below in the Covenants in Financing Agreements section. Fitch also lowered TECO Energy’s senior unsecured debt rating on April 25, 2003 to BB+ with a negative outlook, as did Standard & Poor’s (S&P) in late May 2003. These debt rating changes did not affect any additional requirements related to TECO Energy’s financial obligations or debt covenants.

Also in April 2003, Tampa Electric Company’s senior secured and unsecured debt ratings were lowered to A3 and Baa1, respectively, with a stable outlook by Moody’s and A- and BBB+, respectively, with a negative outlook by Fitch. In late May 2003, S&P lowered Tampa Electric Company’s senior secured and unsecured debt ratings both to BBB- with a negative outlook. These actions did not affect requirements related to debt covenants or obligations. Tampa Electric Company continues to be rated an investment-grade company.

On July 10, 2003, S&P placed the ratings of TECO Energy and Tampa Electric Company on Credit Watch with negative implications as a result of the IRS suspending issuance of PLR’s for synthetic fuel plants and the potential effect of this action on TECO Energy’s sale of interests in its synfuel plants. Because S&P generally bases its ratings on the consolidated corporate entity, any action is likely to impact the rating of Tampa Electric Company as well as TECO Energy. As a result, any reduction in TECO Energy’s debt rating by S&P would likely cause Tampa Electric Company to lose its investment grade rating status from that agency. Such a reduction would likely increase Tampa Electric Company’s incremental cost of capital if new capital were required to be issued, which is not expected in the short to medium term, and could require Tampa Electric Company to provide additional assurances to vendors, regulators or others with whom it conducts business. The company cannot predict with certainty the financial impact of such event.

TECO Energy’s and Tampa Electric Company’s current senior unsecured credit ratings are summarized as follows:

Senior Unsecured Credit Ratings as of June 30, 2003

	Fitch	Moody’s	Standard & Poor’s
Tampa Electric Company	BBB+(1)	Baa1	BBB-(1)
TECO Energy / TECO Finance	BB+   (1)	Ba1   (1)	BB+  (1)

(1) Negative outlook

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric Company must meet certain financial tests. TECO Energy’s credit facilities require that, at each quarter-end, TECO Energy’s debt-to-capital ratio, as defined in the applicable agreements, not exceed 65%. Under Tampa Electric Company’s 364-day credit facility, its debt-to-capital ratio may not exceed 60% at the end of the applicable quarter and its EBITDA to interest coverage ratio (as defined in the agreement) cannot be less than 2.5 times. Certain long-term debt at PGS contains a prohibition on the incurrence of funded debt if Tampa Electric Company’s debt-to-capital ratio, as defined in the applicable agreement, exceeds 65%. The PGS debt also contains a Tampa Electric Company interest coverage requirement, as defined in the applicable agreement, of 2.0 times or greater for four consecutive quarters. At June 30, 2003, Tampa Electric Company’s debt-to-capital ratio was 49.3%, and interest coverage was 7.3 times.

55

Various agreements with the Union and Gila project debt lenders relating to the completion of construction are guaranteed by TECO Energy and require a TECO Energy consolidated interest coverage, as defined in the applicable agreement, equal to or exceeding 3.0 times for the twelve-month period ended each quarter and a debt-to-total capital ratio, as defined in the applicable agreement, of not more than 65%. Compliance with these covenants is measured on the last day of each quarter. At June 30, 2003, TECO Energy’s debt-to-total capital ratio was 57.5% and EBITDA to interest coverage was 3.2 times. Should either ratio in future quarters fall outside the required level, TECO Energy would be in default under these guarantees which could trigger a cross-default on the Union and Gila River non-recourse project debt.

The ratings downgrade by Moody’s triggered the requirement to, within fifteen days, post letters of credit for, or repay, the $250 million unpaid balance of the equity bridge loan associated with the construction of the Union and Gila River power projects. In satisfaction of this requirement, the $250 million equity bridge loan was paid in full. In addition, this ratings change also triggered a requirement to post letters of credit, in an amount satisfactory to the majority of lenders, to secure the projects and project lenders for the remaining potential cost to complete the projects. The company reached an agreement with the majority of the project lending banks for a total security amount of $234 million (including amounts for the remaining construction, liquidated damages for delays and performance shortfalls), $62 million of which was not required to be posted due to the achievement of commercial operation of Gila River Phase 1 and Union Power Phase 3 prior to May 31, 2003. The company replaced and amended existing letters of credit (including retainage letters of credit) such that total letters of credit of $172 million were in place by May 20, 2003.

Subsequent to that posting, the outstanding letters of credit under these agreements were reduced by $62 million to $110 million in June with the commercial operation of Union Power Phase 4 and Gila River Phase 2. In July 2003, the outstanding letters of credit under these agreements were further reduced to $58 million with the commercial operation of Gila River Phases 3 and 4. The amounts outstanding are expected to be reduced to $8 million following full commercial operation which occurred in July, and the final acceptance of the units which is expected by October 2003.

As a result of the ratings actions, TPS and Prior Energy were required to post collateral or margins with counterparties in order to continue to transact in the forward markets for electricity and natural gas. Collateral or margin postings may fluctuate based on either (1) the fair value of open forward positions or (2) credit assurance assessments negotiated with counterparties. Counterparties with the right to call for collateral or margin postings are not obligated to do so. See Note 18 to the TECO Energy Consolidated Financial Statements for a summary of the maximum theoretical obligation or the face value of outstanding letters of credit and guarantees issued to counterparties. Based on the fair value of existing contractual obligations as of June 30, 2003, the maximum collateral obligation, if all counterparties exercised their full rights, would be approximately $69 million. The collateral obligation, if the most probable rights were exercised, would be approximately $44 million (including actual collateral posted of $40 million).

TECO Energy’s 10.5% Notes issued in November 2002 contain covenants that limit the ability of the company to incur additional liens and require the company to achieve certain interest coverage levels in order to pay dividends or make distributions or certain investments, or issue additional indebtedness. The 7.5% Notes issued in June 2003 contain the same limitation on liens covenant. The covenants apply only if either the notes are rated non-investment grade by either S&P or Moody’s or the notes are rated below the levels required by the equity bridge loan and Union and Gila River construction undertaking while those obligations are outstanding. The covenants became applicable upon Moody’s downgrade of TECO Energy’s senior unsecured debt in April 2003. 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 contemplated dividend payments, distributions or investments. The operating cash flow and restricted payments are calculated on a cumulative basis since the issuance of the 10.5% Notes in November 2002. At June 30, 2003, $139.1 million was accumulated and available for future restricted payments, representing two quarters’ accumulation. The company is not permitted, with certain exceptions as defined in that agreement, to create any lien upon any of its property in excess of 5% of consolidated net tangible assets as defined in the relevant agreements, without equally and ratably securing the 10.5% and 7.5% Notes. As of June 30, 2003 this limitation would apply to certain liens exceeding $176.2 million. The company’s EBITDA to interest coverage for the immediate preceding four quarters must exceed a ratio of 2.0 to 1.0 for the Company to be able to issue additional indebtedness. As of June 30, 2003, the company’s EBITDA to interest coverage for the immediate preceding four quarters was 3.0 times.

The Merrill Lynch facility contains covenants that (1) require TECO Energy to maintain as of the last day of each fiscal quarter a debt-to-capitalization ratio, as defined in the agreement, that does not exceed 65%, and (2) limit the payment of dividends exceeding $40 million in any quarter unless, prior to the payment of any dividends, the company delivers to Merrill Lynch liquidity projections satisfactory to Merrill Lynch demonstrating that the company will have sufficient cash or cash equivalents to pay both the dividends contemplated and each of the three quarterly dividends next scheduled to be paid on its common stock.

The Tampa Electric Company 6.25% Senior Notes issued in April 2003 contain covenants that (1) require Tampa Electric Company to maintain, as of the last day of each fiscal quarter, a debt-to-capitalization ratio, as defined in the agreement, that does not exceed 60%, and (2) prohibit the creation of any liens on any of its property in excess of $787 million in the aggregate, with certain exceptions as defined, without equally and ratably securing the 6.25% Senior Notes.

56

Off-Balance Sheet Financing

Unconsolidated affiliates in which TPS has a 50-percent ownership interest or less have non-recourse project debt balances as follows at June 30, 2003. This debt is recourse only to the unconsolidated affiliate, and TECO Energy has no debt payment obligations with respect to these financings. Although TECO Energy is not obligated on the debt, TECO Energy’s equity interest in those unconsolidated affiliates and its commitments with respect to those power projects are at risk if those projects are not successfully developed.

Affiliate	Affiliate Debt Balance (millions)		TPS Ownership Interest
EEGSA	$	200	24%
Hamakua	$	86	50%

The equity method of accounting is used to account for investments in partnership and corporate entities in which TECO Energy or its subsidiary companies do not have either a majority ownership or exercise control. On Jan. 17, 2003, the Financial Accounting Standards Board issued FASB Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which requires a new approach in determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities or VIEs. Based on a preliminary review, TECO Energy believes that FIN 46 will impact the accounting for certain unconsolidated affiliates. (See Note 20 to the TECO Energy Consolidated Financial Statements.)

Critical Accounting Policies and Estimates

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

See Note 1 to the TECO Energy Consolidated Financial Statements for a description of TECO Energy’s accounting policies and the estimates and assumptions used in the preparation of the TECO Energy Consolidated Financial Statements.

Asset Impairments

TECO Energy and its subsidiaries periodically evaluate whether there has been a permanent impairment of an asset as follows:

• Long-lived assets, when indicators of impairment exist, in accordance with Financial Accounting Standard (FAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (see the Long-Lived Assets section); and

• Recognized goodwill and other intangible assets with indefinite lives, at least annually, in accordance with FAS 142, Goodwill and Other Intangible Assets (see the Goodwill and Other Intangible Assets section); and

• Equity investments, when a decline in fair value below the carrying value is determined to be other than temporary, in accordance with Accounting Principles Board Opinion (APB) No. 18, The Equity Method of Accounting for Investments in Common Stock.

The company believes that the accounting estimate related to asset impairments is a critical estimate for the following reasons: 1) it is highly susceptible to change each reporting period as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then-current market conditions in such periods; 2) electricity markets continue to experience significant price uncertainty with respect to market fundamentals; 3) the ongoing expectations of management regarding probable future uses of the asset; and 4) the impact of an impairment on reported assets and earnings would be material. The company’s assumptions relating to future results of operations are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. (See Notes 1, 4, 10, 11 and 19 to the TECO Energy Consolidated Financial Statements.)

Long-Lived Assets

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 segment of a business.

57

In accordance with FAS 144, the company assesses whether there has been an other-than-temporary impairment of its long-lived assets and certain intangibles held and used by the company when indicators of other than temporary impairment exist. Except as discussed in Note 10 to the TECO Energy Consolidated Financial Statements relating to certain long-term turbine purchase contracts, no significant events or changes in circumstances occurred during the three months ended June 30, 2003 to indicate an impairment of long-lived assets.

Goodwill and Other Intangible Assets

In accordance with FAS 142, TECO Energy continues to review goodwill and intangibles at least annually for each reporting unit. Reporting units are generally determined as one level below the operating segment level; however, reporting units with similar characteristics may be grouped under the accounting standard for the purpose of determining the impairment, if any, of goodwill and other intangible assets. For each reporting unit evaluated, the fair value exceeded the carrying value, including goodwill, as of the valuation date, Jan. 1, 2003. The fair value for the reporting units evaluated was generally determined using discounted cash flow models appropriate for the business model of each significant group of assets within each reporting unit. For the three months ended June 30, 2003, a $61.2 million after-tax impairment loss was recorded to write off all goodwill associated with the Frontera and Commonwealth Chesapeake power stations. (See Note 4 to the TECO Energy Consolidated Financial Statements.)

Asset Retirement Obligations

On Jan. 1, 2003, TECO Energy adopted FAS 143, Accounting for Asset Retirement Obligations, which requires the recognition of a liability at fair value for an asset retirement obligation in the period in which it is incurred. Retirement obligations associated with long-lived assets included within the scope of FAS 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are included in the scope of the standard 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 useful life of the asset. The liability must be revalued each period based on current market prices. FAS 143 is effective for fiscal years beginning after June 15, 2002.

Asset retirement obligations are comprised of significant estimates which, if different, could materially impact the results of TECO Energy. The company believes these are critical estimates because: 1) the fair value of the costs associated with meeting the obligation are impacted by assumptions on discount rates and estimated profit mark-ups by third-party contractors; 2) probability factors associated with the future sale, abandonment or retirement of an asset must be forecasted and considered in the calculations; 3) the expectations and intent of management regarding the future use of long-lived assets; and 4) the impact of the recognition of an asset impairment obligation could be significant. Upon adoption, effective Jan. 1, 2003, TECO Energy and affiliates maintain and periodically review all new legal arrangements and contractual commitments to ensure that any new potential asset retirement obligations are reviewed and recognized as appropriate. (See Note 6 to the TECO Energy Consolidated Financial Statements.)

Unconsolidated Affiliates

TECO Energy has investments in unconsolidated affiliates that are accounted for using the equity method of accounting. (See Note 1 to the TECO Energy Consolidated Financial Statements.)

Employee Postretirement Benefits

TECO Energy has a funded non-contributory defined benefit retirement plan covering substantially all employees. The company’s policy is to fund the plan based on actuarially determined contributions within the guidelines set by the Employee Retirement Income Security Act of 1974, as amended (ERISA), for the minimum annual contribution and the maximum allowable as a tax deduction by the Internal Revenue Service (IRS). Plan assets are invested in a mix of equity and fixed income securities. In addition, 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. In addition, the company has unfunded supplemental executive retirement benefit plans—non-qualified, non-contributory defined benefit retirement plans available to certain senior management.

The determination of the benefit expense is a critical estimate due to the following factors: 1) management must make significant assumptions regarding the discount rate, return on assets, rate of salary increases and health care cost trend rates; 2) costs are based on actual employee demographics, including the turnover rate, retirement rate, mortality rate, employment periods, compensation levels and age, each of which are subject to change in any given period; 3) the plan provisions may be changed by management action in future periods; and 4) the impact of changes in any of these assumptions is likely to result in a material impact on the recorded pension obligation and expense. Management reviews these assumptions periodically to reflect the company’s actual experience.

58

Derivative Instruments and Hedging

From time to time, TECO Energy enters into derivative instruments to reduce the exposure to market risks. The company does not enter into derivatives for speculative purposes. See the Disclosures About Market Risk section for a discussion of variables used in estimating the fair value of derivative instruments, assumptions made with respect to forecasted transactions, and a discussion of the strategy and objectives related to the use of energy derivatives to mitigate various exposures to risk and uncertainty. (See Note 2 to the TECO Energy Consolidated Financial Statements.)

Deferred Income Taxes

TECO Energy uses the liability method in the measurement of deferred income taxes. Under the liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differing treatment of items, such as depreciation for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. The company assesses the likelihood that deferred tax assets will be recovered from future taxable income and to the extent recovery of some portion or all of the deferred tax asset is not believed to be likely, the company would establish a valuation allowance.

At June 30, 2003, TECO Energy had deferred income tax assets of $483 million attributable primarily to two items: property-related items and alternative minimum tax credit carryover of Section 29 non-conventional fuel tax credits. The carrying value of the company’s deferred income tax assets assumes that the company will be able to realize this asset as an offset to future income taxes payable. The company periodically reviews the deferred income tax assets and, to the extent that recovery would be determined to be unlikely, a valuation reserve would be charged to income. The company believes that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: 1) recoverability of future Section 29 non-conventional fuel tax credits is dependent on the generation of sufficient taxable income to use these credits; 2) administrative actions of the IRS or the U.S. Treasury or changes in law or regulation could eliminate or reduce the availability of Section 29 tax credits; and 3) a change in the recoverability of Section 29 tax credits could have a material impact on reported assets and results of operations. (See Note 12 to the TECO Energy Consolidated Financial Statements.)

Cost Capitalization

During 2003, TECO Energy devoted resources to the completion and construction of additional generation capacity at Tampa Electric and TPS, extension of the transmission network and enhancement to the system’s reliability at Tampa Electric, expansion of the pipeline distribution infrastructure at PGS, normal river barge replacement at TECO Transport and expansion of production capacity at TECO Coal. The cost of additions, including improvements and replacements of property, is charged to plant. TECO Energy capitalizes direct costs and certain indirect costs, including the cost of debt and equity capital as appropriate, associated with its construction and retirement activity as prescribed by generally accepted accounting principles and recognized policies prescribed or permitted by the FPSC and/or the FERC. The amount of capitalized overhead construction costs is based upon analysis of company and affiliate construction activity. Costs are capitalized based on the activity level of resources allocated to construction activities. As a result, the company’s net income could be impacted by the manner and timing of the deployment of resources to construction activities. However, total cash flow is not impacted by the allocation of these costs to the various construction or maintenance activities. Due to the magnitude of construction undertakings, fluctuations in net income, as a result of cost capitalization, could be significant. Capitalized costs will be expensed as a component of depreciation when the assets are placed in service. (See Notes 1 and 13 to the TECO Energy Consolidated Financial Statements.)

Depreciation Expense

TECO Energy provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage, of depreciable property over its estimated service life. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.9% and 4.2% for the six months ended June 30, 2003 and 2002. The company believes the estimated service life corresponds to the anticipated physical life for most assets. However, the company’s estimation of service life is a critical estimate for the following reasons: 1) forecasting the salvage value for long-lived assets over a long timeframe is subjective; 2) changes may take place that could render a technology obsolete or uneconomical; and 3) a change in the useful life of a long-lived asset could have a material impact on reported results of operations and reported assets. Although it is difficult to predict values far into the future, TECO Energy has a long history of actual costs and values that are considered in reaching a conclusion as to the appropriate useful life of an asset. (See Note 1 to the TECO Energy Consolidated Financial Statements.)

59

Regulatory Accounting

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

TECO Energy periodically assesses whether the regulatory assets are probable of future recovery by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on reported assets and the results of operations. (See Notes 1 and 5 to the TECO Energy Consolidated Financial Statements.)

Revenue Recognition

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

The determination of the physical delivery of energy sales to individual customers is based on the reading of meters, which occurs on a regular basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading may be estimated and the corresponding unbilled revenue is estimated. Unbilled revenue is estimated each month primarily based on historical experience, customer-specific factors, customer rates, and daily generation volumes, as applicable. These revenues are subsequently adjusted to reflect actual results. Revenues for regulated activities at Tampa Electric and PGS are subject to the actions of regulatory agencies.

The percentage of completion method is used to recognize revenues for certain transportation services at TECO Transport and for long-term engineering or construction-type contracts at TECO Energy Services (formerly known as TECO BGA and BCH Mechanical). The percentage of completion method requires management to make estimates regarding the distance traveled and/or time elapsed for TECO Transport and total costs and work-in-progress for TECO Energy Services. Revenue is recognized by comparing the estimated current total distance traveled or work completed with the total distance or cost estimate for each project. Each month, revenue recognition and realized profit are adjusted to reflect only the percentage of distance traveled or work completed.

Revenues for energy marketing services 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, to reflect the nature of the contractual relationships with customers and suppliers. Revenues for merchant power sales and expenses for fuel purchases at TPS are reported on a gross basis, except for derivative gains or losses related to hedge accounting, which are reported net of the hedged item or transaction. Likewise, expenses arising from purchased power or revenues arising from fuel sales at TPS are reported net of power revenues and fuel expense, respectively.

TECO Energy estimates certain amounts related to revenues on a variety of factors, as described above. Actual results may be different from these estimates. (See Note 1 to the TECO Energy Consolidated Financial Statements.)

Recently Issued Accounting Standards

In accordance with recently issued accounting pronouncements, TECO Energy will be required to comply with certain changes in accounting rules and regulations. (See Note 20 to the TECO Energy Consolidated Financial Statements.)

Disclosures About Market Risk

Interest Rate Risk

TECO Energy is exposed to changes in interest rates primarily as a result of its borrowing activities. TECO Energy or its affiliates may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt. As of June 30, 2003, there was no significant change in the company’s exposure to interest rate risk since Dec. 31, 2002.

60

Credit Risk

Financial instability and significant uncertainties relating to liquidity in the entire merchant energy sector have increased the perceived credit risk. Below is a summary of TECO Energy’s credit risk exposure to counterparties on energy contracts related to merchant generation activities at June 30, 2003.

(millions) Rating(1)	Exposure Before Credit Collateral(2)		Credit Collateral(3)		Net Exposure		Number of Counterparties >10% (4)	Net Exposure Counterparties >10%(4)
Investment grade	$	45.4	$	—	$	45.4	2	$	21.8
Split rating		13.5		—		13.5	1		13.5
Non-investment grade		4.6		—		4.6	—		—
No external ratings (internally rated)
Investment grade		0.7		—		0.7	—		—
Non-investment grade		—		—		—	—		—
Total	$	64.2	$	—	$	64.2	3	$	35.3

(1) Ratings are principally determined based on publicly available credit ratings, as determined by independent ratings agencies. If the counterparty has provided a guarantee by a higher rated entity, the assigned rating is that of the guarantor. Included in Investment grade are those counterparties with a minimum S&P or Fitch’s rating of BBB- or higher and a Moody’s rating of Baa3 or higher.

(2) Exposure before credit collateral includes the fair value of net energy contract assets for open positions and the net accounts receivable for realized energy contracts. Exposures are offset by a legal counterparty where legally enforceable netting and set-off arrangements are in place.

(3) Credit collateral is required from time-to-time based on contractual provisions and may generally include cash deposits and letters of credit. At June 30, 2003, no credit collateral was required from non-investment grade counterparties.

(4) The number of counterparties that individually, after considering legally enforceable netting arrangements, represent a significant concentration of credit risk (i.e., more than 10% of the total credit exposure) at TECO EnergySource. Also, the combined exposure, less credit collateral, if any, of each significant concentration.

Commodity Risk

TECO Energy and its affiliates face varying degrees of exposure to commodity risks—including coal, natural gas, fuel oil and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. The company assesses and monitors risk using a variety of state-of-the-art measurement tools. Management uses different risk measurement and monitoring tools based on the degree of exposure of each operating company to commodity risk. As of June 30, 2003, the commodity risk exposure at the Regulated Utilities was not significantly different from that as of Dec. 31, 2002.

Unregulated Companies

Most of the unregulated subsidiaries at TECO Energy are subject to significant commodity risk. These include TECO Coal, TECO Transport, TECO Gas Services, Prior Energy and TPS. The unregulated companies do not speculate using derivative instruments. However, not all derivative instruments receive hedge accounting treatment due to the strict requirements and narrow applicability of the accounting literature to dynamic transactions. For TECO Coal, TECO Transport, Prior Energy and TECO Gas Services, as of June 30, 2003 there was no significant change from Dec. 31, 2002 for commodity risks.

For TPS, results of operations are impacted primarily by changes in the market prices for electricity and natural gas. TPS uses derivative instruments to reduce the commodity price risk exposure of the merchant plants. The commodity price risk of each plant is managed on both a portfolio and asset-specific basis. The following table summarizes the impact of a hypothetical 10% change in commodity prices on the fair value of merchant energy derivative contracts at June 30, 2003 and Dec. 31, 2002.

Sensitivity of the Fair Value of Merchant Energy Derivative Contracts

(millions)	June 30, 2003			Dec. 31, 2002
Change in Fair Value due to a 10%: (1)
Decrease in natural gas prices	$	(28.0	)	$	(16.9	)
Increase in electricity prices		(33.7	)		(24.4	)
Increase in electricity and natural gas prices		(5.7	)		(7.5	)

(1) Reflects the fair value associated with merchant energy derivative contracts only. The change shown for the contracts due to price movements would be more than offset by a change in the fair value of the underlying physical plant assets.

The following tables summarize the changes in and the fair value balances of energy derivative assets (liabilities) for the

61

quarter ended June 30, 2003:

Changes in Fair Value of Energy Derivatives (millions)
Net fair value of derivatives as of Dec. 31, 2002	$	8.4
Net change in unrealized fair value of derivatives		(5.0	)
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		(9.4	)
Net fair value of derivatives as of June 30, 2003	$	(6.0	)
Roll-Forward of Energy Derivative Net Assets (Liabilities) (millions)
Total energy derivative net assets (liabilities) as of Dec. 31, 2002	$	8.4
Change in fair value of net derivative assets (liabilities):
Recorded in OCI		(3.7	)
Recorded in earnings		(14.1	)
Net option premium payments		10.2
Net purchase (sale) of existing contracts		(6.8	)
Net fair value of derivatives as of June 30, 2003	$	(6.0	)

When available, the company uses quoted market prices to record the fair value of energy derivative contracts. However, certain energy derivative contracts are not exchange-traded, but rather, are traded in the over-the-counter (OTC) market, through multiple-party on-line trading platforms, or in the bilateral market. TECO Energy uses industry-accepted valuation techniques based on pricing models or matrix pricing for energy derivative contracts when third-party price data is infrequent or not available. Prices, inputs, assumptions and the results of valuation techniques are validated by the Middle Office, independently of the Front Office, on a daily basis. Significant inputs and assumptions used by the company to determine the fair value of energy derivative contracts are: 1) the physical delivery location of the commodity; 2) the correlation between different basis points and/or different commodities; 3) rational, economic behavior in the markets and by counterparties; 4) on- and off-peak curve shapes and correlations; 5) observed market information; and 6) volatility forecasts and estimates for and between commodities. Mathematical approaches are applied on a frequent basis to validate and corroborate the results of valuation calculations.

Below is a summary table of sources of fair value, by maturity period, for energy derivative contracts at June 30, 2003.

Maturity and Source of Energy Derivative Contracts Net Assets (Liabilities) at June 30, 2003

Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value (millions)
Actively quoted prices	$	38.7		$	7.8		$	46.5
Other external sources(1)		(50.6	)		(11.7	)		(62.3	)
Model prices(2)		6.5			3.3			9.8
Total	$	(5.4	)	$	(0.6	)	$	(6.0	)

(1) Information from external sources includes information obtained from OTC brokers, industry price services or surveys and multiple-party on-line platforms.

(2) Model prices are used for determining the fair value of energy derivatives where price quotes are infrequent or the market is illiquid. Significant inputs to the models are derived from market observable data and actual historical experience.

For all unrealized energy derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

62

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See the discussion entitled “Disclosures about Market Risk” in Item 2. Management’s Discussion and Analysis.

Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

(a) Evaluation of Disclosure Controls and Procedures. TECO Energy’s management, with the participation of its Chief Executive Officer and Chief Financial Officer has evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this quarterly report (the “Evaluation Date”). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to TECO Energy (including its consolidated subsidiaries) required to be included in TECO Energy’s reports filed or submitted under the Exchange Act.

(b) Changes in Internal Controls. There have not been any significant changes in TECO Energy’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, such controls during the period covered by this report.

Tampa Electric Company

(a) Evaluation of Disclosure Controls and Procedures. Tampa Electric Company’s management, with the participation of its Chief Executive Officer and Chief Financial Officer has evaluated the effectiveness of Tampa Electric Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this quarterly report (the “Evaluation Date”). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the Evaluation Date, Tampa Electric Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to Tampa Electric Company required to be included in Tampa Electric Company’s reports filed or submitted under the Exchange Act.

(b) Changes in Internal Controls. There have not been any significant changes in Tampa Electric Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, such controls during the period covered by this report.

63

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

In connection with the arbitration proceeding brought against a TECO Power Service Corporation subsidiary, TM Delmarva Power, L.L.C. (“TMDP”), by the non-equity member, NCP of Virginia, L.L.C. (“NCP”), in the Commonwealth Chesapeake Project (the “Project”) the arbitration panel in a 2-to-1 decision found in favor of NCP and issued an interim award on December 17, 2002, establishing a buy-out of NCP’s rights under the Project’s operating agreement as the remedy and establishing the method of calculating the buy-out price. The interim award directed the parties to provide briefs and calculations with respect to the buy-out price. At the conclusion of the briefing cycle, TMDP’s experts and calculations placed the buy-out price at the $5-$10 million range, while NCP’s experts placed the value at approximately $44 million. Reopened hearings took place on May 12 and 13, 2003 for expert testimony on the discount rate, final briefs were submitted, and a second interim award was issued on July 11, 2003 establishing a 7 – 9% discount rate and clarifying the calculation methodology. Both parties have submitted their calculations in response to the second interim award which range from $9.5 million by TMDP to $25.5 million by NCP, but with NPC seeking up to $32 million. The panel has asked for further filings by the parties to accommodate the panel’s clarifications, and the panel is expected to issue a final decision within 30 days following the last reply brief due on August 22, 2003.

See the discussion of environmental matters in Notes 5 and 18 to the TECO Energy Consolidated Financial Statements and Notes 3 and 12 to the Tampa Electric Company Consolidated Financial Statements.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits - See index on page 68.

(b) Reports on Form 8-K

TECO Energy, Inc. filed or furnished the following reports on Form 8-K during the second quarter of 2003.

1. The registrant filed a Current Report on Form 8-K dated April 9, 2003, under “Item 5. Other Events”, “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, and “Item 9. Regulation FD Disclosure”, reporting that TECO Energy, Inc. had entered into a Credit Agreement with Merrill Lynch Bank USA for a new credit facility, and providing under “Item 12. Results of Operations and Financial Condition”, that the Company had met its cash generation target and outlining steps to further bolster its financial position.

2. The registrant filed a Current Report on Form 8-K dated April 11, 2003, under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting that Tampa Electric Company sold $250 million principal amount of Senior Notes pursuant to Note Purchase Agreements between Tampa Electric Company and each of the Purchasers of the Notes.

3. The registrant filed a Current Report on Form 8-K dated April 21, 2003, under “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, “Item 9. Regulation FD Disclosure”, and “Item 12. Results of Operations and Financial Condition”, furnishing TECO Energy, Inc.’s financial results for the quarter ended March 31, 2003, and reporting TECO Energy, Inc.’s response to the action taken by Moody’s Investor Service to downgrade TECO Energy, Inc.’s senior unsecured debt rating.

4. The registrant filed a Current Report on Form 8-K dated May 6, 2003, under “Item 5. Other Events”, reporting that TECO Energy had taken action to repay the equity bridge loan and to provide security for certain obligations associated with the nearly completed Union and Gila River power stations.

5. The registrant filed a Current Report on Form 8-K dated May 14, 2003, under “Item 5. Other Events”, reporting that TECO Energy had reached an agreement in principle regarding the amounts to be posted under the project completion undertaking for Union and Gila River power stations, and extended the deadline for the posting.

64

6. The registrant filed a Current Report on Form 8-K dated May 16, 2003, under “Item 5. Other Events”, reporting that TECO Energy had received the requisite approval from the majority of the non-recourse project lending banks regarding the amounts to be posted under the project completion undertaking for the Union and Gila River power stations.

7. The registrant filed a Current Report on Form 8-K dated June 9, 2003, under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting that TECO Energy planned to offer unsecured notes to the public through underwriters Merrill Lunch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Morgan Stanley &Co. Incorporated and J.P. Morgan Securities Inc.

8. The registrant filed a Current Report on Form 8-K dated June 10, 2003, under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, furnishing certain exhibits for incorporation by reference into the Registration Statements on Form S-3 of TECO Energy, Inc. previously filed with Securities and Exchange Commission (File No. 333-102018).

9. The registrant filed a Current Report on Form 8-K dated June 13, 2003, under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, furnishing certain exhibits for incorporation by reference into the Registration Statements on Form S-3 of TECO Energy, Inc. previously filed with Securities and Exchange Commission (File No. 333-102018).

10. The registrant filed a Current Report on Form 8-K dated June 26, 2003, under “Item 2. Acquisition or Disposition of Assets”, “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibit”, reporting that TECO Power Services Corporation, TECO Energy’s unregulated power generation subsidiary, had acquired the interests in TECO-Panda Generating Company, L.P. owned by subsidiaries of Panda Energy International, Inc.

TECO Energy, Inc. filed or furnished the following reports on Form 8-K subsequent to June 30, 2003.

1. The registrant filed a Current Report on Form 8-K dated July 3, 2003, under “Item 5. Other Events”, to address an IRS announcement regarding the production of synthetic fuel.

2. The registrant filed a Current Report on Form 8-K dated July 23, 2003, under “Item 9. Regulation FD Disclosure”, and “Item 12. Results of Operations and Financial Condition”, furnishing TECO Energy, Inc.’s financial results for the quarter ended June 30, 2003.

Tampa Electric Company filed the following report on Form 8-K during the second quarter of 2003.

1. The registrant filed a Current Report on Form 8-K dated June 11, 2003, under “Item 5. Other Events”, and “Item 7. Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting that Tampa Electric sold $250 million principal amount of Senior Notes pursuant to Note Purchase Agreements between Tampa Electric Company and each of the Purchasers of the Notes.

65

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 13^th day of August, 2003.

	TECO ENERGY, INC.
		(Registrant)
Date:  August 13, 2003	By:	/s/ G. L. GILLETTE
		G. L. GILLETTE
		Senior Vice President - Finance and Chief Financial Officer
		(Principal Financial Officer)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 13^th day of August, 2003.

	TAMPA ELECTRIC COMPANY
		(Registrant)
Date:  August 13, 2003	By:	/s/ G. L. GILLETTE
		G. L. GILLETTE
		Senior Vice President - Finance and Chief Financial Officer
		(Principal Financial Officer)

INDEX TO EXHIBITS

Exhibit No.	Description	Page No.
3.1	Articles of Incorporation of TECO Energy, Inc., as amended on April 30, 1993 (Exhibit 3, Form 10-Q for the quarter ended Mar. 31, 1993 of TECO Energy, Inc., File No. 1-8180).	*
3.2	Bylaws of TECO Energy, Inc., as amended effective Jan. 18, 2001 (Exhibit 3.2, Form 10-K for the year ended Dec. 31, 2000 of TECO Energy, Inc., File No. 1-8180).	*
3.3	Articles of Incorporation of Tampa Electric Company (Exhibit 3, Registration Statement No. 2-70653 of Tampa Electric Company, File No. 1-5007).	*
3.4	Bylaws of Tampa Electric Company, as amended effective April 16, 1997 (Exhibit 3, Form 10-Q for the quarter ended June 30, 1997 of Tampa Electric Company, File No. 1-5007).	*
4.1	Credit Agreement dated June 24, 2003, among TECO Energy, Inc., as Borrower, Bayerische Hypo-Und Vereinsbank AG, as Administrative Agent and Co-Lead Arranger, Dexia Credit Local, New York Agency, as Co-Lead Arranger and Syndication Agent, BMO Nesbitt Burns Financings, Inc., as Arranger, and Royal Bank of Canada, as Arranger.	[	]
12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.	[	]
12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.	[	]
31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14 and 15d-14 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	[	]
31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14 and 15d-14 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	[	]
31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14 and 15d-14 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	[	]
31.4	Certification of the Chief Financial Officer of Tampa Electric Company to Securities Exchange Act Rules 13a-14 and 15d-14 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	[	]
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)	[	]
32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)	[	]

(1) This certification accompanies the Quarterly Report on Form 10-Q and is not filed as part of it.

 * Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.