TECO Energy 10-Q 2003 Q3 Quarterly report

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 endedSeptember 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.	Exact name of each Registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-8180	TECO ENERGY, INC. (a Florida corporation) TECO Plaza 702 N. Franklin Street Tampa, Florida 33602 (813) 228-4111	59-2052286
1-5007	TAMPA ELECTRIC COMPANY (a Florida corporation) TECO Plaza 702 N. Franklin Street Tampa, Florida 33602	59-0475140

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.

YESx        NO¨

Indicate by check mark whether TECO Energy, Inc. is an accelerated filer (as defined in Exchange Act Rule 12b-2).

YESx        NO¨

Indicate by check mark whether Tampa Electric Company is an accelerated filer (as defined in Exchange Act Rule 12b-2).

YES¨        NOx

Number of shares of TECO Energy, Inc.’s common stock outstanding as of October 31, 2003 was 187,818,891.

As of October 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.

Page 1 of 74

Index to Exhibits appears on page 74

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 Sept. 30, 2003 and 2002, and the results of their operations and cash flows for the periods ended Sept. 30, 2003 and 2002. The results of operations for the three-month and nine-month periods ended Sept. 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 35 of this report.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page No.
Consolidated Balance Sheets, Sept. 30, 2003 and Dec. 31, 2002	3-4
Consolidated Statements of Income for the three-month and nine-month periods ended Sept. 30, 2003 and 2002	5-6
Consolidated Statements of Comprehensive Income for the three-month and nine-month periods ended Sept. 30, 2003 and 2002	7
Consolidated Statements of Cash Flows for the nine-month periods ended Sept. 30, 2003 and 2002	8
Notes to the Consolidated Financial Statements	9-35

2

TECO ENERGY, INC.

Consolidated Balance Sheets

	Sept. 30, 2003			Dec. 31, 2002
Assets (millions)	Unaudited
Current assets
Cash and cash equivalents	$	409.2		$	411.1
Restricted cash		113.9			—
Short-term investments		15.8			—
Receivables, less allowance for uncollectibles of $5.3 million and $6.6 million at Sept. 30, 2003 and Dec. 31, 2002, respectively		546.8			414.5
Current notes receivable		—			235.1
Current derivative assets		12.6			12.4
Inventories, at average cost
Fuel		96.9			110.7
Materials and supplies		96.8			92.5
Prepayments and other current assets		68.7			30.3
Total current assets		1,360.7			1,306.6
Property, plant and equipment
Utility plant in service
Electric		7,719.9			4,856.5
Gas		768.5			746.7
Construction work in progress		1,177.4			1,556.8
Other property		851.4			857.4
Property, plant and equipment, at original cost		10,517.2			8,017.4
Accumulated depreciation		(2,800.6	)		(2,694.5	)
Property, plant and equipment (net)		7,716.6			5,322.9
Property held for sale (net)		—			163.0
Total property, plant and equipment (net)		7,716.6			5,485.9
Other assets
Deferred income taxes		507.5			340.2
Long-term derivative asset		5.2			0.1
Other investments		697.3			845.3
Regulatory assets		184.4			163.2
Investment in unconsolidated affiliates		344.4			149.2
Goodwill		100.2			193.7
Intangible assets		11.3			11.1
Deferred charges and other assets		171.0			142.5
Total other assets		2,021.3			1,845.3
Total assets	$	11,098.6		$	8,637.8

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

3

TECO ENERGY, INC.

Consolidated Balance Sheets—continued

Liabilities and capital (millions)	Sept. 30, 2003			Dec. 31, 2002
	Unaudited
Current liabilities
Long-term debt due within one year
Recourse	$	6.0		$	106.4
Non-recourse		1,442.2			12.6
Notes payable		397.5			360.5
Accounts payable		421.0			374.5
Customer deposits		99.0			94.6
Current derivative liability		44.8			3.9
Interest accrued		97.3			49.1
Taxes accrued		56.1			93.4
Total current liabilities		2,563.9			1,095.0
Other liabilities
Deferred income taxes		527.8			495.0
Investment tax credits		24.0			27.5
Long-term derivative liability		43.0			0.2
Regulatory liabilities		96.4			98.1
Property held for sale		—			119.0
Deferred credits and other liabilities		275.3			319.6
Long-term debt, less amount due within one year
Recourse		3,658.7			3,112.7
Non-recourse		759.0			108.7
Preferred securities		649.1			—
Minority interest		(0.1	)		1.2
Total other liabilities		6,033.2			4,282.0
Preferred securities		—			649.1
Capital
Common equity (400 million shares authorized; par value $1; 187.8 million shares and 175.8 million shares outstanding at Sept. 30, 2003 and Dec. 31, 2002, respectively)		187.8			175.8
Additional paid in capital		1,220.8			1,094.5
Retained earnings		1,200.3			1,413.7
Accumulated other comprehensive income		(86.7	)		(41.2	)
Common equity		2,522.2			2,642.8
Unearned compensation		(20.7	)		(31.1	)
Total capital		2,501.5			2,611.7
Total liabilities and capital	$	11,098.6		$	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 Sept. 30,
						2003			2002
Revenues
Regulated electric and gas (includes franchise fees and gross receipts
taxes of $21.0 million in 2003 and $19.5 million in 2002)						$	558.6		$	512.7
Unregulated							382.1			212.9
Total revenues							940.7			725.6
Expenses
Regulated operations
Fuel							111.0			96.2
Purchased power							64.9			66.6
Cost of natural gas sold							63.1			37.6
Other							67.0			64.9
Other operations							356.7			169.8
Maintenance							44.3			34.8
Depreciation							102.7			78.1
Restructuring charges							11.0			—
Taxes, other than income							45.6			41.0
Total expenses							866.3			589.0
Income from operations							74.4			136.6
Other income (expense)
Allowance for other funds used during construction							3.9			6.9
Other income							5.9			15.5
TMDP arbitration reserve							(32.0	)		—
Income (loss) from equity investments							1.4			(1.3	)
Total other (expense) income							(20.8	)		21.1
Interest charges
Interest expense							101.0			32.9
Distribution on preferred securities							10.0			10.0
Allowance for borrowed funds used during construction							(1.5	)		(2.7	)
Total interest charges							109.5			40.2
(Loss) income before provision for income taxes							(55.9	)		117.5
(Benefit) provision for income taxes							(25.4	)		6.9
Net (loss) income from continuing operations before minority interests							(30.5	)		110.6
Minority interest							11.3			—
Net (loss) income from continuing operations							(19.2	)		110.6
Discontinued operations
Income from discontinued operations (including gain on disposal of $56.2 million in 2003)							60.9			7.4
Income tax provision (benefit)							23.5			(0.9	)
Total discontinued operations							37.4			8.3
Cumulative effect of change in accounting principle, net of tax							(3.2	)		—
Net income						$	15.0		$	118.9
	Basic					Diluted
	Three months ended Sept. 30,					Three months ended Sept. 30,
	2003			2002		2003			2002
Average common shares outstanding		179.5			156.1		179.8			156.1
Earnings per share from continuing operations	$	(0.11	)	$	0.71	$	(0.11	)	$	0.71
Earnings per share	$	0.08		$	0.76	$	0.08		$	0.76
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)						Nine months ended Sept. 30,
						2003			2002
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $59.1 million in 2003 and $55.4 million in 2002)						$	1,528.4		$	1,432.7
Unregulated							793.7			561.7
Total revenues							2,322.1			1,994.4
Expenses
Regulated operations
Fuel							256.3			250.2
Purchased power							169.4			169.3
Cost of natural gas sold							186.2			111.1
Other							189.5			196.6
Other operations							749.8			483.5
Maintenance							114.6			111.4
Depreciation							275.8			229.8
Asset impairment							104.1			—
Goodwill impairment							95.2			—
Restructuring charges							11.0			3.2
Taxes, other than income							131.5			127.6
Total expenses							2,283.4			1,682.7
Income from operations							38.7			311.7
Other (expense) income
Allowance for other funds used during construction							15.6			16.9
Other income							53.0			43.9
Loss on joint venture termination							(153.9	)		—
TMDP arbitration reserve							(32.0	)		—
Loss from equity investments							(2.0	)		(1.2	)
Total other (expense) income							(119.3	)		59.6
Interest charges
Interest expense							232.4			101.8
Distribution on preferred securities							30.0			28.9
Allowance for borrowed funds used during construction							(6.1	)		(6.5	)
Total interest charges							256.3			124.2
(Loss) income before provision for income taxes							(336.9	)		247.1
(Benefit) for income taxes							(155.6	)		(9.8	)
Net (loss) income from continuing operations before minority interests							(181.3	)		256.9
Minority interest							34.7			—
Net (loss) income from continuing operations							(146.6	)		256.9
Discontinued operations
Income from discontinued operations (including gain on disposal of $93.6 million in 2003)							109.1			18.4
Income tax provision (benefit)							42.4			(4.7	)
Total discontinued operations							66.7			23.1
Cumulative effect of change in accounting principle, net of tax							(4.3	)		—
Net (loss) income						$	(84.2	)	$	280.0
	Basic					Diluted
	Nine months ended Sept. 30,					Nine months ended Sept. 30,
	2003			2002		2003			2002
Average common shares outstanding		177.5			146.4		177.8			146.7
Earnings per share from continuing operations	$	(0.83	)	$	1.75	$	(0.83	)	$	1.75
Earnings per share	$	(0.47	)	$	1.91	$	(0.47	)	$	1.91
Dividends paid per common share outstanding	$	0.735		$	1.055

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 Sept. 30,					Nine months ended Sept. 30,
	2003		2002			2003			2002
Net income (loss)	$	15.0	$	118.9		$	(84.2	)	$	280.0
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments		—		—			1.2			—
Net unrealized gains (losses) on cash flow hedges		7.8		(7.8	)		(46.7	)		(3.6	)
Other comprehensive income (loss), net of tax		7.8		(7.8	)		(45.5	)		(3.6	)
Comprehensive income (loss)	$	22.8	$	111.1		$	(129.7	)	$	276.4

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

7

TECO ENERGY, INC.

Consolidated Statements of Cash Flows

Unaudited

	Nine months ended Sept. 30,
(millions)	2003			2002
Cash flows from operating activities
Net (loss) income	$	(84.2	)	$	280.0
Adjustments to reconcile net (loss) income to net cash from operating activities:
Depreciation		275.8			229.8
Deferred income taxes		(113.1	)		(66.9	)
Investment tax credits, net		(3.5	)		(3.4	)
Allowance for funds used during construction		(21.7	)		(23.4	)
Amortization of unearned compensation		12.6			8.7
Cumulative effect of change in accounting principle, pretax		7.1			—
Gain on sales of business/assets, pretax		(138.5	)		—
Equity in earnings of unconsolidated affiliates		5.7			3.9
Minority loss		(34.7	)		—
Asset impairment, pretax		104.1			4.9
Goodwill impairment, pretax		95.2			—
Loss on joint venture termination, pretax		153.9			—
TMDP arbitration reserve		32.0			—
Deferred recovery clause		(24.5	)		75.2
Refunded to customers		—			(6.1	)
Receivables, less allowance for uncollectibles		17.5			(90.9	)
Inventories		19.5			(34.5	)
Prepayments and other deposits		(36.8	)		7.3
Taxes accrued		(38.9	)		30.2
Interest accrued		(35.1	)		44.0
Accounts payable		(0.5	)		29.3
Other		78.0			11.3
Cash flows from operating activities		269.9			499.4
Cash flows from investing activities
Capital expenditures		(460.5	)		(791.8	)
Allowance for funds used during construction		21.7			23.4
Purchase of minority interest		—			(9.9	)
Net proceeds from sales of business/assets		168.0			—
Restricted cash		(63.4	)		—
Investment in unconsolidated affiliates		(29.2	)		0.1
Other non-current investments		(36.7	)		(531.7	)
Cash flows from investing activities		(400.1	)		(1,309.9	)
Cash flows from financing activities
Dividends		(129.5	)		(153.4	)
Common stock		135.8			362.9
Proceeds from long-term debt		649.4			1,384.5
Minority interest		32.2			—
Restricted cash		(32.2	)		—
Repayment of long-term debt		(515.7	)		(721.9	)
Settlement of joint venture termination obligation		(33.5	)		—
Net increase (decrease) in short-term debt		37.0			(408.1	)
Issuance of preferred securities		—			435.7
Equity contract adjustment payments		(15.2	)		(10.2	)
Cash flows from financing activities		128.3			889.5
Net (decrease) increase in cash and cash equivalents		(1.9	)		79.0
Cash and cash equivalents at beginning of period		411.1			108.4
Cash and cash equivalents at end of period	$	409.2		$	187.4

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. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. 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 are included in the consolidated financial statements through Dec. 31, 2002.

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

Restricted Cash

Restricted cash at Sept. 30, 2003 is comprised of $68 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 $46 million at TECO Power Services (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 $59 million related to the sale will be released. However, over time, up to $50 million of cash from the synfuel facility sale will accumulate in escrow to provide working capital credit due to the company’s current credit rating. SeeNote 22 for information on TECO Energy’s receipt of the PLR subsequent to Sept. 30, 2003.

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 are transferred to construction in progress when financing has been obtained and construction activity has commenced. In accordance with Statement of Position (“SOP”) 98-5,Reporting on the Costs of Start-up Activities, start-up costs and organization costs are expensed as incurred.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt. TECO-Panda Generating Company, L.P. (TPGC) capitalized a portion of amortized debt financing costs in the amount of $2.4 million for the three months ended Sept. 30, 2002, and $2.6 million and $6.7 million, respectively, for the nine months ended Sept. 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

	Sept. 30, 2003	Dec. 31, 2002
TECO Power Services (TPS)
TPGC (1)	100	50
PLC Development Holdings, LLC, (PLC) (2)	100	—
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, LLC (3)	38	38
TECO Energy Services
TECO Thermal Systems, Inc.	50	50

9

TECO Energy and Subsidiaries’ Investments in Unconsolidated Affiliates—continued

	Sept. 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
B-T One, LLC (4)	80	50

(1) TPS consolidated TPGC effective April 1, 2003 and received Panda’s 50-percent interest in June 2003. See Note 12 for a detailed discussion.

(2) In September 2003, TPS obtained the remaining ownership interests in PLC which were outstanding as of June 30, 2003. Consequently, TPS consolidated PLC as of Sept. 30, 2003. PLC, a wholly-owned subsidiary of TPS, holds a 50-percent ownership interest in Texas Independent Energy, L.P. (TIE). See Notes 12, 16 and 20 for additional details.

(3) See Note 22 for information regarding a recent agreement to sell the interests of TPV.

(4) During April 2003, the company renegotiated the terms of the partnership agreement of B-T One, LLC, to reflect the economic interests of the partners. Effective April 1, 2003, TECO Properties owns an 80-percent interest in the partnership. See Note 20 for additional information.

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). SeeNote 5for 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 nine months ended Sept. 30, 2003 were $145.4 million and $684.1 million, respectively, compared to $120.3 million and $377.9 million, respectively, for the three and nine months ended Sept. 30, 2002.

Purchased Power

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. As a result of TPS’ sale of Hardee Power Partners, Ltd. (HPP) in September 2003 (seeNotes 19 and20), all periods presented reflect the reclassification of power purchases from HPP as non-affiliate purchases. Tampa Electric’s long-term power purchase agreement from HPP was not affected by TPS’ sale of HPP. Under the existing agreement, which has been approved by the FPSC, Tampa Electric has the right to purchase, on average, approximately 52% of the total output of the Hardee power station. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.9 million and $169.4 million, respectively, for the three months and nine months ended Sept. 30, 2003, compared to $66.6 million and $169.3 million, respectively, for the three months and nine months ended Sept. 30, 2002. These purchased power costs are recoverable through an FPSC-approved cost recovery clause.

Total unregulated purchased power at TPS, for the three months and nine months ended Sept. 30, 2003 were $64.8 million and $90.5 million, respectively, compared to purchases of $9.2 million and $13.5 million, respectively for the three months and nine months ended Sept. 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 total regulated and unregulated plant in service, expressed as a percentage of the original cost of depreciable property,

10

was 4.0% for the nine months ended Sept. 30, 2003 and 4.2% for the nine months ended Sept. 30, 2002. For the nine months ended Sept. 30, 2003, Tampa Electric recognized depreciation expense of approximately $19 million related to accelerated depreciation of certain Gannon power station coal-fired assets, in accordance with a regulatory order issued by the FPSC.

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 PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation. At Jan. 1, 2003, the estimated accumulated cost of removal and dismantlement included in net accumulated depreciation was approximately $442 million. At Sept. 30, 2003, the cost of removal and dismantlement component of accumulated depreciation was approximately $459 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. SeeNote 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 Statements of Income. These amounts totaled $21.0 million and $19.5 million, respectively, for the three months ended Sept. 30, 2003 and 2002, and $59.1 million and $55.4 million, respectively, for the nine months ended Sept. 30, 2003 and 2002. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income.” For the three months ended Sept. 30, 2003 and 2002, these totaled $20.9 million and $19.5 million, respectively, and for the nine months ended Sept. 30, 2003 and 2002, they totaled $58.9 million and $55.4 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. As discussed inNote 10, indicators of impairment existed for certain long-term turbine purchase contracts and merchant power plants, triggering a requirement to test for an impairment of these assets. SeeNote 22 for subsequent events which may cause management to reconsider an asset impairment test.

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,Accounting for Stock Issued to Employees, and related interpretations in accounting for its stock-based compensation plans. SeeNote 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 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. TECO Energy’s $380 million note indenture contains a covenant that requires the company to achieve certain interest coverage levels in order to pay dividends; and TECO Energy’s Merrill Lynch credit facility contains a covenant that could limit the payment of dividends exceeding $40 million in any quarter under certain circumstances if the facility is drawn. SeeNotes 7, 8 and19 for a more detailed description of significant financial covenants.

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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 and other distributions 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 and distributions on the common stock of Tampa Electric (seeNote 19). 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 Sept. 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 20% and 19%, respectively, of consolidated common equity. SeeNote 22 for an update on Tampa Electric Company’s credit line renewal and additional covenants included.

Reclassifications

Certain prior year amounts were reclassified to conform with the current year presentation. In September 2003, TECO Energy’s TPS subsidiary sold Hardee Power Partners, Ltd. Results for all prior periods have been reclassified from Continuing operations to Discontinued operations, and all assets and liabilities to Assets held for sale. See alsoRevenue Recognition accounting policy related to reporting energy marketing operations on a net basis.

2. Derivatives and Hedging

At Sept. 30, 2003, the company had derivative assets totaling $17.8 million and liabilities totaling $87.8 million. At Dec. 31, 2002, the company had derivative assets totaling $12.5 million and liabilities totaling $4.1 million. At Sept. 30, 2003 and Dec. 31, 2002, accumulated other comprehensive income (OCI) included $79.1 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 Sept. 30, 2003 is an unrealized after-tax loss of $69.0 million on interest rate swaps designated as cash flow hedges, reflecting the fully consolidated amount included in OCI at TPGC (seeNote 8) and the company’s proportionate share of OCI at TIE. At Dec. 31, 2002 the unrealized after-tax loss of $37.3 million, included in OCI, represented the company’s proportionate share of OCI at TPGC, in accordance with the equity method of accounting. 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 Sept. 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,Accounting for Derivative Instruments and Hedging Activities. TECO Energy reclassified net pretax gains of $18.4 million and losses of $3.6 million, respectively, for the three months ended Sept. 30, 2003 and 2002, and net pretax gains of $37.1 million and losses of $26.3 million, respectively, for the nine months ended Sept. 30, 2003 and 2002. 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 Sept. 30, 2003, pretax losses of $36.6 million are expected to be reversed from OCI to the Consolidated Statements of Income within the next twelve months. However, these losses and other future reclassifications from OCI will fluctuate with movements in the underlying market price of the derivative instruments. 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 Sept. 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 nine months ended Sept. 30, 2003, the company recognized pretax gains of $0.1 million and losses of $1.4 million, respectively, compared to pretax losses of $0.2 million and gains of $0.7 million, respectively, for the three and nine months ended Sept. 30, 2002. For the three months and nine months ended Sept. 30, 2003, the company also recognized pretax losses of $2.5 million and $6.6 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 $0.7 million and $3.1 million, respectively, for the three and nine months ended Sept. 30, 2002.

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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 (the County). As of Sept. 30, 2003, UPP’s investment in the bonds from the County totaled $696.1 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 provides an incentive to and a means through which the company can invest in the County. As of Dec. 31, 2002, TECO Energy did not include TPGC in the Consolidated Balance Sheet (seeNote 12).

For the three months and nine months ended Sept. 30, 2003, UPP recognized $13.1 million and $26.2 million, respectively, of interest income on the investment in the Union County bonds, and the same amounts of interest expense on the Union County financings since the consolidation of TPGC as of Apr. 1, 2003. For all other periods presented, income or loss at TPGC was recognized on a net basis by TECO Energy as a result of the previous application of equity method accounting. Interest income on the investment and interest expense on the related long-term debt have been presented on a net basis in the Consolidated Statements of Income, and have no net impact on the company’s results of operations. 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. The obligation to pay cash under the long-term debt is fully offset by the right to receive cash from the bond issuer. The interest rate on the bonds and the related long-term debt is 7.5% per year.

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 Sept. 30, 2002 and thereafter are as follows:

Future Minimum Payments for Union County Industrial Revenue Bonds

Year ended Dec. 31:	Amount (millions)
2003	$	3.9
2004		16.2
2005		17.6
2006		19.5
2007		21.4
2008 and beyond		617.6
Total minimum payments	$	696.2

4. Goodwill and Other Intangible Assets

As required under FAS 142,Goodwill and Other Intangible Assets, 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 (seeNote 12), 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 acquisitions of the Commonwealth Chesapeake power station in Virginia and the Frontera power station in Texas. TPS has no remaining domestic goodwill, and as of Sept. 30, 2003, TECO Energy’s net consolidated goodwill was $100.2 million compared to $193.7 million as of Dec. 31, 2002.

The amount of intangible assets recorded at Sept. 30, 2003 was $11.3 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 Sept. 30, 2003, no amortization was recorded compared to $3.3 million for the same period in 2002. For the nine months ended Sept. 30, 2003 and 2002, the company recognized amortization expense of $4.7 million and $9.3 million, respectively.

Intangible assets at Sept. 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.

The potential unfavorable resolution of a legal contingency arising from a contested final award in an arbitration proceeding, as more fully described inNote 19, resulted in the company recording a reserve in which an additional intangible asset

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of $4.9 million was recognized. This amount relates to the forced acquisition of legal interests in the Commonwealth Chesepeake Project (CCC), as required under the final award of an arbitration proceeding. As of Sept. 30, 2003, the company has not made a cash payment under the award, but has reserved for the full amount of the award and has initiated certain legal proceedings seeking to vacate the award. SeeNote 19 for complete details.

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 Sept. 30, 2003 and Dec. 31, 2002 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Sept. 30, 2003		Dec. 31, 2002
Regulatory assets:
Regulatory tax asset (1)	$	58.5	$	54.9
Other:
Cost recovery clauses		58.2		34.7
Coal contract buy-out (2)		3.4		5.4
Unamortized refinancing costs (3)		33.1		35.9
Environmental remediation		20.7		20.3
Competitive rate adjustment		4.9		7.4
Other		5.6		4.6
		125.9		108.3
Total regulatory assets	$	184.4	$	163.2
Regulatory liabilities:
Regulatory tax liability (1)	$	32.0	$	36.6
Other:
Deferred allowance auction credits		2.0		2.1
Cost recovery clauses		1.3		2.2
Environmental remediation		20.7		20.3
Transmission and distribution storm reserve		39.0		36.0
Deferred gain on property sales (4)		1.3		0.9
Other		0.1		—
		64.4		61.5
Total regulatory liabilities	$	96.4	$	98.1

(1) Related primarily to plant life. Includes excess deferred taxes of $18.0 million and $20.9 million as of Sept. 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.

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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 an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

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

TECO Energy has recognized asset retirement obligations for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. Prior to the adoption of FAS 143, TECO Coal accrued reclamation costs for such activities. For TECO Coal, the adoption of FAS 143 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 nine months ended Sept. 30, 2003, TECO Energy recognized $0.3 million and $0.9 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 nine months ended Sept. 30, 2002.

7. Short-Term Debt

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, however, conversion will not occur during the Suspension Period, as agreed under the Suspension Agreement described inNote 19. 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. As a result of the terms and rights associated with the Suspension Agreement, discussed inNote 19, and the various related guarantees, the company reclassified the outstanding non-recourse financing for the Union and Gila River projects of $1,395.0 million from long-term to current liabilities (see alsoNote 8).

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

Credit Facilities	Sept. 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 (1)	$	300.0	$	10.0	$	—	$	300.0	$	—	$	—
TECO Energy:
1-year term loan (1)		350.0		350.0		—		350.0		350.0		—
18-month facility		150.0		—		—		—		—		—
1-year facility		37.5		37.5		—		—		—		—
3-year facility (1)		350.0		—		115.6		350.0		—		179.8
		1,187.5		397.5		115.6		1,000.0		350.0		179.8

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Credit Facilities – continued	Sept. 30, 2003						Dec. 31, 2002
(millions)	Credit Facilities		Borrowings Outstanding		of Credit Outstanding		Credit Facilities		Letters Borrowings Outstanding		Letters of Credit Outstanding
Non-recourse: (2)
TECO Power Services
5-yr TPGC project facilities (3) (4)		200.0		—		139.3		—		—		—
5-yr TPGC project facilities (4)		80.0		—		—		—		—		—
		280.0		—		139.3		—		—		—
Total	$	1,467.5	$	397.5	$	254.9	$	1,000.0	$	350.0	$	179.8

(1) SeeNote 22 for recent information about the renewal of Tampa Electric’s facility, the repayment of TECO Energy’s maturing 1-year term loan, and the amendment to TECO Energy’s 3-year facility.

(2) Non-recourse to TPS and TECO Energy.

(3) Letter of credit facility only.

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

The weighted average interest rate on outstanding notes payable at Sept. 30, 2003 and Dec. 31, 2002 was 2.71% and 1.88%, respectively. At Sept. 30, 2003 and Dec. 31, 2002, notes payable consisted of the following:

Notes Payable

(millions)	Sept. 30, 2003		Dec. 31, 2002
Credit facilities outstanding	$	397.5	$	350.0
Commercial paper		—		10.5
Total notes payable	$	397.5	$	360.5

On April 9, 2003, TECO Energy entered into a three-year $350 million unsecured credit facility with Merrill Lynch. The term of the 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. Current quarterly dividends are $35.5 million.

On June 24, 2003, TECO Energy entered into a one-year $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. SeeNote 19 for a summary of performance against significant financial covenant requirements.

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. (SeeNote 22 for information on the recent renewal of the Tampa Electric facility and repayment of the TECO Energy 1-year facility.) Within its 3-year facility, TECO Energy has $250 million of capacity to issue letters of credit, of which $115.6 million was utilized at Sept. 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, depending on the amount of the draw. The Tampa Electric Company bank facility requires commitment fees of 20 basis points, and drawn amounts are charged interest at LIBOR plus 105-117.5 basis points at current credit ratings, depending on the amount of the draw.

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. SeeNote 19 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.

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8. Long-Term Debt

The Union and Gila River projects entered into interest rate swap agreements, in connection with the non-recourse borrowings, to effectively convert a portion of the floating rate debt to a fixed rate basis (seeNote 2). At Sept. 30, 2003 and Dec. 31, 2002, the Union and Gila River projects had interest rate swap agreements with notional amounts totaling $697.5 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.

In April 2003, Tampa Electric issued $250 million of 6.25% Senior Notes due in 2016, in a private 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.

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. SeeNote 19 for a summary of performance against significant financial covenant requirements.

As a result of the adoption of FAS 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, on July 1, 2003, the preferred securities are classified and presented as long-term debt for external financial reporting purposes only. The cumulative effect of the adoption of FAS 150 was a loss of $3.2 million, reflecting an adjustment to recognize interest expense ratably over the life of the instruments in accordance with the new guidance.

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

Long-term Debt (millions)	Due	Sept. 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		—
Preferred securities: 8.50% (7)	2041		200.0		—
Preferred securities: 9.50% (8)	2007		449.1		—
			2,629.1		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% Refunding bonds (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 4.22%) (6)	2025		51.6		51.6
4% (effective rate of 4.17%) (6)	2018		54.2		54.2
4.25% (effective rate of 4.44%) (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 7.35%) (2)	2012		330.0		330.0
Notes: 5.375% (effective rate of 5.59%) (2)	2007		125.0		125.0
Notes: 6.25% (effective rate of 6.31%) (2)	2016		250.0		—
			1,423.9		1,248.9

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Long-term Debt—continued (millions)	Due	Sept. 30, 2003			Dec. 31, 2002
Peoples Gas System
Senior Notes (6)
10.35%	2007		3.4			4.2
10.33%	2008		4.8			5.6
10.3%	2009		6.4			7.2
9.93%	2010		6.6			7.4
8%	2012		23.3			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
			179.5			184.8
TECO Power Services
Non-recourse secured facility notes, variable rate: 4.36% (1)	2003-2007		36.4			50.1
Non-recourse secured facility notes: 10.1%	2003-2009		15.9			16.4
Non-recourse secured facility notes: 9.629%	2003-2010		19.9			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 (12)	2003-2006		1,395.0			—
Non-recourse financing facility—Union County: 7.5% (9)	2021		696.1			—
			2,193.3			121.3
Diversified companies
Dock and wharf bonds, 5% (3)	2007		110.6			110.6
Non-recourse mortgage notes: 4.40% (effective rate of 4.56%) (10)	2003-2004		5.3			—
Non-recourse mortgage notes: 3.90% (effective rate of 4.16%) (10)	2003-2004		2.5			—
Capital lease: implicit rate of 8.5%	2003		—			25.3
			118.4			135.9
Unamortized debt premium (discount), net			(29.2	)		(30.5	)
			6,515.0			3,340.4
Less amount due within one year—Recourse (11)			6.0			106.4
—Non-recourse (12)			1,442.2			12.6
Total long-term debt		$	5,066.8		$	3,221.4

(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 19).

(7) These securities may be redeemed in whole or in part, at the option of the company on or after Dec. 20, 2005.

(8) These securities are comprised of two components—an equity contract which pays a coupon of 4.39%, adjusted quarterly, and a note obligation which pays a coupon of 5.11% (effective rate of 5.85%). The note obligation is subject to a potential rate reset on Oct. 15, 2004.

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

(10) 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.

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

(12) Due to the terms and rights associated with the Suspension Agreement and various guarantees related to the non-recourse debt at the Union and Gila River projects (seeNotes 7 and19), the company reclassified the outstanding non-recourse financing from long-term to current liabilities.

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9. Common Stock

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 Sept. 30,						Nine months ended Sept. 30,
(millions, except per share amounts)	2003			2002			2003			2002
Net (loss) income from continuing operations
As reported	$	(19.2	)	$	110.6		$	(146.6	)	$	256.9
Pro forma expense (1)		1.0			1.2			3.2			3.4
Pro forma	$	(20.2	)	$	109.4		$	(149.8	)	$	253.5
Net (loss) income
As reported	$	15.0		$	118.9		$	(84.2	)	$	280.0
Pro forma expense (1)		1.0			1.2			3.2			3.4
Pro forma	$	14.0		$	117.7		$	(87.4	)	$	276.6
Net (loss) income from continuing operations—EPS, basic
As reported	$	(0.11	)	$	0.71		$	(0.83	)	$	1.75
Pro forma	$	(0.11	)	$	0.70		$	(0.85	)	$	1.73
Net (loss) income from continuing operations—EPS, diluted
As reported	$	(0.11	)	$	0.71		$	(0.83	)	$	1.75
Pro forma	$	(0.11	)	$	0.70		$	(0.85	)	$	1.73
Net income (loss)—EPS, basic
As reported	$	0.08		$	0.76		$	(0.47	)	$	1.91
Pro forma	$	0.08		$	0.75		$	(0.49	)	$	1.89
Net income (loss)—EPS, diluted
As reported	$	0.08		$	0.76		$	(0.47	)	$	1.91
Pro forma	$	0.08		$	0.75		$	(0.49	)	$	1.89
Assumptions
Risk-free interest rate		4.33	%		5.09	%		4.33	%		5.09	%
Expected lives (in years)		6			6			6			6
Expected stock volatility		36.0	%		25.9	%		36.0	%		25.9	%
Dividend yield		5.53	%		5.47	%		5.53	%		5.47	%

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

Common Stock Issuance

On September 10, 2003, TECO Energy sold 11 million shares of common stock to funds managed by Franklin Advisers, Inc. of San Mateo, California at a price of $11.76 per share. Net proceeds of about $129 million will be used to repay short-term indebtedness and general corporate purposes.

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 inNote 16, 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.

In September 2003, as a result of the market conditions for merchant assets, management tested the merchant plants for impairment. This test was performed using undiscounted cash flows based on assumptions which included long-term gross margin

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projections, long-term forecasts of supply and demand growth rates, and reasonably available information to develop long term expectations. No impairment was indicated based on the undiscounted cash flows of the merchant assets tested, in accordance with FAS 144. For all other long-lived assets, no significant events or changes in circumstances occurred during the nine months ended Sept. 30, 2003 to indicate an impairment. SeeNote 22 for subsequent events which may cause management to reconsider an asset impairment test.

11. Restructuring Costs

In early September 2003, TECO Energy announced a corporate reorganization to restructure the company along functional lines, consistent with its objectives to grow the core utility operations, maintain liquidity, generate cash and maximize the value in the existing assets. As part of this restructuring phase and the additional actions taken in October 2003 (seeNote 22), the company is now aligned to provide for centralized oversight along functional lines for power plant operations, energy delivery, energy management, and human resources and technology/support services. This phase included the involuntary termination or retirement of 83 employees, including officers and other personnel from plant operations, support services, certain regional offices and two call centers. The company recognized an expense of $11.0 million for accrued benefits including severance and salary continuation through the end of 2003 and other termination and retirement benefits. The table below details the expense recognized by the operating segments.

(millions)	Tampa Electric		Peoples Gas		TPS		TECO Transport		TECO Coal		Other Unregulated		Eliminations & Other		TECO Energy
Termination and retirement benefit expense	$	2.2	$	1.7	$	4.3	$	—	$	—	$	2.8	$	—	$	11.0

The company expects to complete this phase of restructuring activities by the end of 2003. As of Sept. 30, 2003, no adjustments have been made to the benefits initially accrued for and $1.4 million of the accrued benefits have been paid or otherwise settled.

12. 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 occur 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 (seeNotes 1 and16 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 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. Prior to April 1, 2003, TPS recognized assets of $839.1 million, liabilities of $48.9 million and an unrealized loss in OCI of $69.0 million, to reflect the equity method of accounting for its investment in TPGC. As a result of the consolidation on April 1, 2003, the company recognized additional assets of $2,446.9

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million, primarily relating to utility plant and construction work in progress, additional liabilities of $1,976.8 million (including the non-recourse debt discussed inNotes 3,7 and8), and an additional unrealized loss in OCI of $69.0 million for interest rate swaps designated as hedges.

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 inNote 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. Foreclosure proceedings were consummated on Panda’s remaining interests in PLC in September 2003 (seeNotes 1,16 and20for additional details).

For the nine months ended Sept. 30, 2003, TECO Energy recorded total after-tax charges of $155.9 million ($249.1 million pretax) at TPS as a direct result of the consolidation of TPGC. 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 (seeNote 16), 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 (seeNote 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 prior to July 2003.

(Unaudited) Pro Forma Results of Operations

	Three months ended Sept. 30,					Nine months ended Sept. 30,
(millions, except per share amounts)	2003			2002		2003			2002
Revenues	$	940.7		$	725.6	$	2,339.8		$	1,994.5
Net (loss) income from continuing operations (1)		(19.2	)		103.4		(146.0	)		240.1
Cumulative effect of change in accounting principle, net		(3.2	)		(		(4.3	)		(
Net (loss) income (1)	$	15.0		$	111.7	$	(86.7	)	$	263.1
Earnings per share, basic (1)(2)	$	0.08		$	0.72	$	(0.49	)	$	1.80

(1) Includes pretax charges of $353.2 million for the nine months ended Sept. 30, 2003. These charges are the result of the partnership termination and the related goodwill impairment recorded in the second quarter and an asset impairment associated with turbine purchase commitment cancellation recorded in the first quarter (see Note 10).

(2) Average common shares outstanding, basic, were 179.5 million and 177.5 million for the three months and nine months ended Sept. 30, 2003, respectively, and 156.1 million and 146.4 million, respectively, for the same periods in 2002.

13. 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.

In the first and third quarters of 2003, tax credits generated related to the production and sale of synthetic fuel (synfuel) at TECO Coal for its behalf were significantly greater than the second quarter 2003. Generally accepted accounting principles require that income tax expense be recognized in interim periods at the expected consolidated annual effective income tax rate and that valuation allowances be established as needed to account for uncertainties regarding utilizing tax assets or benefits. TECO Energy recorded an $18.0 million intra-period tax deferral to recognize income taxes at the expected annualized rate and to account for uncertainties that existed at Sept. 30, 2003 regarding Section 29 credit utilization. At Sept. 30, 2003, the total intra-period tax deferral was $28.5 million ($10.5 million remaining from the first quarter deferral and $18.0 million from the third quarter deferral). SeeNote 22for information on the Company’s recent receipt of the PLR regarding Section 29 utilization.

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In the first quarter of 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 of 2003, TECO Energy considered $167.2 million as unusual and infrequently occurring items for tax purposes only, including after-tax charges for goodwill impairment and joint venture termination losses at TPS. In the third quarter of 2003, TECO Energy recorded a $20.0 million after-tax charge ($32.0 million pretax) for a legal contingency reserve at TMDP. The provision for income taxes as a percent of these items for the nine months ended Sept. 30, 2003 was 37.5%.

In the quarter ended Sept. 30, 2003, TECO Energy recorded a $34.5 million after-tax gain ($56.2 million pretax) associated with the sale of Hardee Power Partners. Results from Hardee Power have been reflected as discontinued operations for all periods presented. For the nine months ended Sept. 30, 2003, net income from discontinued operations was $66.7 million and the provision for income taxes, as a percent of income from discontinued operations, was 38.9%.

Effective Income Tax Rate

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions)	2003			2002			2003			2002
Income from continuing operations before income taxes	$	(55.9	)	$	117.5		$	(336.9	)	$	247.1
Plus:  Minority interest		11.3			—			34.7			—
Less (1):  Asset impairment charge		—			—			104.5			—
Goodwill impairment		—			—			95.2			—
Joint venture termination related losses		—			—			170.8			—
TMDP arbitration reserve		32.0			—			32.0			—
Income from continuing operations before income taxes, including minority interest, excluding unusual and infrequently occurring items (1)	$	(12.6	)	$	117.5		$	100.3		$	247.1
Income taxes on above at federal statutory rate of 35%	$	(4.4	)	$	41.1		$	35.1		$	86.5
Increase (decrease) due to
State income tax, net of federal income tax		(1.3	)		2.8			(0.1	)		6.2
Foreign income taxes		0.9			0.7			4.7			1.6
Amortization of investment tax credits		(1.2	)		(1.1	)		(3.5	)		(3.4	)
Non-conventional fuels tax credit (2)		(3.1	)		(28.1	)		(28.7	)		(81.9	)
Permanent reinvestment-foreign income		(3.2	)		(3.6	)		(10.8	)		(9.3	)
AFUDC equity		(1.4	)		(2.4	)		(5.5	)		(5.9	)
Other		0.3			(2.5	)		4.1			(3.6	)
Total income tax provision from continuing operations	$	(13.4	)	$	6.9		$	(4.7	)	$	(9.8	)
Provision for income taxes as a percent of income from continuing operations, before income taxes		N/A	(3)		5.9	%		(4.6	)%		(4.0	)%

(1) Excludes for tax purposes only, after-tax charges recorded in the three months ended Mar. 31, 2003 for an asset impairment (see Note 10), goodwill impairment and TPGC transaction related losses recorded in the three months ended June 30, 2003 (see Note 12), legal contingency reserve recorded in the three months ended Sept. 30, 2003 (see Notes 4 and 19).

(2) Non-conventional fuels tax credit for the three months ended Sept. 30, 2003 was decreased by the $18.0 million deferral of tax credits related to the synthetic fuel production at TECO Coal. The deferral of tax credits for the nine months ended Sept. 30, 2003 was $28.5 million.

(3) Not applicable due to the fact that the calculation is meaningless because of the interaction between tax losses and tax credits in the third quarter.

14. Discontinued Operations

Hardee Power Partners, Ltd. (HPP), a subsidiary of TECO Power Services, generates and sells electricity to Seminole Electric and Tampa Electric under a long-term power purchase agreement. On Sept. 30, 2003, TPS closed the sale of HPP to an affiliate of Invenergy LLC and GTCR Golder Rauner LLC (seeNote 20). Results for the three and nine months ended Sept. 30, 2003 and 2002 have been reclassified from continuing operations to discontinued operations. For the three and nine months ended Sept. 30, 2003, operating revenues from HPP were $25.9 million and $71.8 million, respectively compared to $24.3 million and $80.4 million for the same periods in 2002, and pre-tax operating income for the three and nine months ended Sept. 30, 2003 were $4.6 million and $14.7 million, respectively compared to $3.6 million and $10.9 million for the same periods in 2002.

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,

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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 nine months ended Sept. 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 nine months ended Sept. 30, 2002. For the three and nine months ended Sept. 30, 2002, operating revenues from TECO Coalbed Methane were $10.7 million and $28.3 million, respectively, and pretax operating income was $7.6 million and $19.3 million, respectively.

SeeNote 20 for additional details regarding the HPP and TECO Coalbed Methane transactions.

15. Comprehensive Income

TECO Energy reported the following comprehensive income (loss) for the three months and nine months ended Sept. 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:

Comprehensive Income (Loss)

(millions)
Three months ended Sept. 30,	Gross			Tax			Net
2003
Unrealized gain (loss) on cash flow hedges (1)	$	39.5		$	13.8		$	25.7
Portion of equity investee’s unrealized loss on cash flow hedges		(7.8	)		(2.7	)		(5.1	)
Less: (Gain) loss reclassified to net income		(18.4	)		(5.6	)		(12.8	)
Total other comprehensive income	$	13.3		$	5.5		$	7.8
2002
Unrealized (loss) gain on cash flow hedges (1)	$	(16.3	)	$	(6.0	)	$	(10.3	)
Less: Loss (gain) reclassified to net income		3.6			1.1			2.5
Total other comprehensive (loss) income		(12.7	)		(4.9	)		(7.8	)
Nine months ended Sept. 30,	Gross			Tax			Net
2003
Unrealized (loss) gain on cash flow hedges (1)	$	(29.6	)	$	(12.3	)	$	(17.3	)
Portion of equity investee’s unrealized loss on cash flow hedges		(7.8	)		(2.7	)		(5.1	)
Less: (Gain) loss reclassified to net income		(37.1	)		(12.8	)		(24.3	)
(Loss) gain on cash flow hedges		(74.5	)		(27.8	)		(46.7	)
Foreign currency adjustments		1.2			—			1.2
Total other comprehensive (loss) income	$	(73.3	)	$	(27.8	)	$	(45.5	)
2002
Unrealized (loss) gain on cash flow hedges	$	(32.8	)	$	(6.8	)	$	(9.7	)
Less: Loss (gain) reclassified to net income		26.3			8.8			13.9
Total other comprehensive income (loss)	$	(6.5	)	$	(2.9	)	$	(3.6	)

(1) Amounts include interest rate swaps designated as cash flow hedges 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.

16. 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 nine months ended Sept. 30, 2003 and 2002. No material balances were payable as of Sept. 30, 2003 or Dec. 31, 2002.

In the second and third quarters of 2003, Tampa Electric returned $158 million of capital to TECO Energy. TECO Energy had previously contributed capital to Tampa Electric in support of Tampa Electric’s construction program in the wholesale business, which has been scaled back.

In February 2002, Tampa Electric and TECO-Panda Generating Company II (TPGC II) entered into an assignment and assumption agreement under which Tampa Electric obtained TPGC II’s rights and interests to four combustion turbines being purchased from General Electric, and assumed the corresponding liabilities and obligations for such equipment. In accordance with

23

the terms of the assignment and assumption agreement, Tampa Electric paid $62.5 million to TPGC II as reimbursement for amounts already paid to General Electric by TPGC II for such equipment. No gain or loss was incurred on the transfer. In the first quarter of 2003, Tampa Electric recorded a $48.9 million after-tax charge related to the cancellation of these turbine purchase commitments. SeeNote 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 Sept. 30, 2003, TPS had a note receivable from an unconsolidated affiliate of $8.1 million due from EEGSA, bearing a current effective interest rate of 6.20%.

On Jan. 3, 2003, the $137 million 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. In September 2003, TPS completed the foreclosure proceedings against Panda Energy for their ownership interest in PLC as a result of Panda’s default under a $23.0 million note receivable. Consequently, as of Sept. 30, 2003, PLC is fully consolidated and the $23.0 million note receivable was converted to an equity interest. See alsoNotes 1,12 and20 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 nine months ended Sept. 30, 2003 and 2002, “Other income” includes pretax income of $9.1 million and $21.5 million, respectively, from construction-related and loan agreements with Panda Energy. For the three months ended Sept. 30, 2002, “Other income” includes $10.1 million, pretax. No amounts were recorded for the three months ended Sept. 30, 2003. SeeNote 12 for the additional details of the impact of consolidation on the company.

17. Earnings Per Share

For the three and nine months ended Sept. 30, 2003 stock options for 6.4 million shares and 6.4 million shares, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect compared to 6.2 million and 4.0 million, respectively, for the same periods in 2002. 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 nine months ended Sept. 30, 2003 and 2002 due to their antidilutive effect.

Earnings Per Share

(millions, except per share amounts)	Three months ended Sept. 30,						Nine months ended Sept. 30,
	2003			2002			2003			2002
Numerator
Net (loss) income from continuing operations, basic	$	(19.2	)	$	110.6		$	(146.6	)	$	256.9
Effect of contingent performance shares		—			—			—			—
Net (loss) income from continuing operations, diluted	$	(19.2	)	$	110.6		$	(146.6	)	$	256.9
Discontinued operations, net of tax		37.4			8.3			66.7			23.1
Cumulative effect of a change in accounting principle, net		(3.2	)		—			(4.3	)		—
Net (loss) income, basic	$	15.0		$	118.9		$	(84.2	)	$	280.0
Effect of contingent performance shares		—			—			—			—
Net (loss) income, diluted	$	15.0		$	118.9		$	(84.2	)	$	280.0
Denominator
Average number of shares outstanding—basic		179.5			156.1			177.5			146.4
Plus: Incremental shares for assumed conversions:
Stock options at end of period and contingent performance shares		2.8			0.4			2.8			2.6
Less: Treasury shares which could be purchased		(2.5	)		(0.4	)		(2.5	)		(2.3	)
Average number of shares outstanding—diluted		179.8			156.1			177.8			146.7

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Earnings Per Share—continued

	Three months ended Sept. 30,					Nine months ended Sept. 30,
(millions, except per share amounts)	2003			2002		2003			2002
Earnings per share from continuing operations
Basic	$	(0.11	)	$	0.71	$	(0.83	)	$	1.75
Diluted	$	(0.11	)	$	0.71	$	(0.83	)	$	1.75
Earnings per share from discontinued operations, net
Basic	$	0.21		$	0.05	$	0.38		$	0.16
Diluted	$	0.21		$	0.05	$	0.38		$	0.16
Earnings per share from cumulative effect of change in accounting principle, net
Basic	$	(0.02	)	$	—	$	(0.02	)	$	—
Diluted	$	(0.02	)	$	—	$	(0.02	)	$	—
Earnings per share
Basic	$	0.08		$	0.76	$	(0.47	)	$	1.91
Diluted	$	0.08		$	0.76	$	(0.47	)	$	1.91

18. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets. All significant intercompany transactions are eliminated in the consolidated financial statements of TECO Energy but are included in determining reportable segments. In September 2003, HPP (previously consolidated by TPS) was sold, and in December 2002, the assets of TECO Coalbed Methane were sold. The information presented here excludes HPP from TPS’ results and TECO Coalbed Methane’s results, which are reflected in the consolidated financial statements as discontinued operations.

Segment Information (1)

(millions) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		TPS			TECO Transport		TECO Coal			Other Unregulated			Eliminations & Other			TECO Energy
2003
Revenues—outsiders (2)	$	455.4	$	103.2	$	240.6		$	43.8	$	72.3		$	25.3		$	0.1		$	940.7
Sales to affiliates (2)		0.8		—		—			20.1		—			3.9			(24.8	)		—
Total revenues (2)	$	456.2	$	103.2	$	240.6		$	63.9	$	72.3		$	29.2		$	(24.7	)	$	940.7
Depreciation		54.8		8.2		26.1			5.0		8.3			0.3			—			102.7
Restructuring costs (3)		2.2		1.7		4.3			—		—			0.8			2.0			11.0
Interest charges (4)		23.6		3.9		52.7			1.1		2.7			1.5			24.0			109.5
(Benefit) provision for taxes		29.2		1.5		(42.6	)(6)		1.8		(23.2	)		(0.5	)		8.4	(7)		(25.4	)
Net income (loss) from continuing operations (4)	$	53.3	$	2.9	$	(62.2	)(6)	$	2.6	$	18.4		$	—		$	(34.2	)(7)	$	(19.2	)
2002
Revenues—outsiders (2)	$	438.3	$	74.4	$	74.3		$	36.1	$	82.9		$	19.6		$	0.0		$	725.6
Sales to affiliates (2)		0.8		—		—			26.7		—			5.3			(32.8	)		—
Total revenues (2)	$	439.1	$	74.4	$	74.3		$	62.8	$	82.9		$	24.9		$	(32.8	)	$	725.6
Depreciation		49.3		7.7		5.2			5.6		8.2			2.1			—			78.1
Restructuring costs		—		—		—			—		—			—			—			—
Interest charges (4)		12.1		3.7		11.7			1.6		2.0			1.0			8.1			40.2
(Benefit) provision for taxes		33.4		1.9		8.3			2.4		(32.8	)		(3.6	)		(2.7	)		6.9
Net income (loss) from continuing operations (4)	$	63.1	$	3.1	$	23.4		$	4.7	$	21.7		$	(1.0	)	$	(4.4	)	$	110.6

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Segment Information—continued

(millions) Nine months ended Sept. 30,	Tampa Electric			Peoples Gas		TPS			TECO Transport		TECO Coal			Other Unregulated			Eliminations & Other			TECO Energy
2003
Revenues—outsiders (2)	$	1,203.5		$	324.9	$	376.0		$	116.4	$	225.9		$	75.1		$	0.3		$	2,322.1
Sales to affiliates (2)		2.5			—		—			79.1		—			10.4			(92.0	)		—
Total revenues (2)	$	1,206.0		$	324.9	$	376.0		$	195.5	$	225.9		$	85.5		$	(91.7	)	$	2,322.1
Depreciation		158.1			24.7		47.3			15.2		25.0			5.5			—			275.8
Restructuring costs (3)		2.2			1.7		4.3			—		—			0.8			2.0			11.0
Interest charges (4)		66.2			11.7		113.6			3.6		8.0			4.3			48.9			256.3
(Benefit) provision for taxes		38.1	(5)		12.0		(166.0	)(6)		8.3		(53.5	)		(1.9	)		7.4	(7)		(155.6	)
Net income (loss) from continuing operations (4)	$	83.8	(5)	$	19.6	$	(266.3	)(6)	$	12.4	$	64.9		$	(1.0	)	$	(60.0	)(7)	$	(146.6	)
2002
Revenues—outsiders (2)	$	1,195.6		$	237.1	$	148.9		$	100.8	$	244.1		$	67.9		$	0.0		$	1,994.4
Sales to affiliates (2)		2.5			—		—			86.9		—			16.4			(105.8	)		—
Total revenues (2)	$	1,198.1		$	237.1	$	148.9		$	187.7	$	244.1		$	84.3		$	(105.8	)	$	1,994.4
Depreciation		141.5			22.8		16.2			16.8		23.9			8.6			—			229.8
Restructuring costs		3.2			—		—			—		—			—			—			3.2
Interest charges (4)		40.2			10.8		35.0			4.8		6.1			3.4			23.9			124.2
(Benefit) provision for taxes		74.9			10.9		6.5			8.2		(98.2	)		(1.6	)		(10.5	)		(9.8	)
Net income (loss) from continuing operations (4)	$	144.5		$	17.3	$	32.7		$	15.8	$	58.8		$	3.6		$	(15.8	)	$	256.9
Three months ended Sept. 30,
At Sept. 30, 2003
Goodwill, net	$	—		$	—	$	59.3		$	—	$	—		$	40.9		$	—		$	100.2
Investment in unconsolidated affiliates		—			—		306.1			—		—			43.4			—			349.5
Other non-current investments		—			—		688.4			—		—			8.9			—			697.3
Total Assets	$	3,787.5		$	582.7	$	5,401.1		$	310.1	$	345.4		$	316.9		$	360.0		$	11,103.7
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. All periods have been adjusted to reflect the reclassification of HPP’s results (previously part of TPS) and TECO Coalbed Methane’s results as discontinued operations.

(2) Revenues for all periods have been adjusted to reflect the reclassification of HPP’s results (previously part of TPS) to discontinued operations, 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) In early September 2003, TECO Energy announced a corporate reorganization to restructure the company along functional lines, consistent with its objectives to grow the core utility operations, maintain liquidity, generate cash and maximize the value in the existing assets (seeNote 11).

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

(5) Net income for the nine months ended Sept. 30, 2003 includes a $48.9 million after-tax ($79.6 million pretax) asset impairment charge related to the turbine purchase cancellations (seeNote 10).

(6) Net income for the three months ended Sept. 30, 2003 includes $25.9 million after-tax ($40.7 million pretax) in charges related to TMDP’s arbitration proceeding with NCP, including a $32.0 million pretax reserve (see theLegal Contingencies section ofNote 19). In addition to this, the nine months ended Sept. 30, 2003 also includes a $61.2 million after-tax ($95.2 million pretax) charge for goodwill impairment, a $94.7 million after-tax charge ($153.9 million pretax) related to the partnership termination and resulting consolidation of TPGC, and a $15.3 million after-tax ($24.5 million pretax) asset impairment related to the turbine purchase cancellations (seeNote 10).

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(7) Provision for income taxes and net income for the three months and nine months ended Sept. 30, 2003 includes the deferral of $18.0 million and $28.5 million, respectively, of tax credits for the production of synthetic fuel in the first quarter of 2003 (seeNote 13).

19. Commitments and Contingencies

Capital Investments

TECO Energy has made certain commitments in connection with its continuing capital expenditure program. At Sept. 30, 2003, these estimated capital investments for the full year 2003 were approximately $440 million, and are summarized below. These investments are net of proceeds from asset and business sales of $253 million, including the TECO Coalbed Methane asset sale of $98 million; the sale of a 49.5-percent interest in TECO Coal synfuel assets of $50 million; the sale of HPP of $72 million, net of restricted cash amounts; and the sale of TPS’ interest in ECKG of $27 million.

Forecasted Full-Year Capital Investments

(millions)	Estimated 2003
Tampa Electric	$	266.4
Peoples Gas		40.0
TECO Power Services		330.3
TECO Transport		19.1
TECO Coal		31.7
Other		5.1
Total capital investments		692.6
Less: proceeds from asset sales		(252.9	)
Net capital investments	$	439.7

Legal Contingencies

A dispute resulting in an arbitration proceeding was 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. The interim award establishes a buy-out of NCP’s rights under the CCC operating agreement as the remedy and 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. A second interim award was issued on July 11, 2003 establishing a 7 – 9% discount rate and clarifying the calculation methodology.

In September 2003, the panel reached a final award in which TMDP is obligated to acquire NCP’s voting and other rights, pay NCP interest on the deemed acquisition price from a pre-determined date, and pay NCP’s legal fees as prescribed under the final award. The forced acquisition creates an intangible asset of $4.9 million relating to specific contractual rights previously held by NCP and a loss of $32.0 million, representing the excess of the purchase price over the fair value of the interests acquired. TMDP is seeking to vacate the arbitration award in the U.S. District Court for the District of Columbia and has not yet paid the amount of the award. As of Sept. 30, 2003, the company recorded a contingent liability of $45.5 million reflecting the maximum payment obligation under the final award. Of the $45.5 million recorded, $8.6 million was expensed, $4.9 million was recognized as an intangible asset to be amortized over 20 years, and $32.0 million was expensed to establish a reserve, reflecting the maximum obligation under the final award.

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 Sept. 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.

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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

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; and/or

• Disclosure of specific details of the guarantee.

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

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

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A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Sept. 30, 2003 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 Sept. 30, 2003
Tampa Electric
Letters of credit	$	—	$	—	$	—	$	0.9	$	0.9	$	—
TECO Power Services
Letters of credit (1)		69.5		2.6		—		14.6		86.7		—
Guarantees:
Debt related		—		—		—		19.2		19.2		—
Tax related		—		—		—		1.3		1.3		—
Fuel purchase/energy management (2)		—		20.0		—		469.5		489.5		12.4
Construction/Investment related		5.0		—		—		—		5.0		—
		74.5		22.6		—		504.6		601.7		12.4
TECO Transport
Letters of credit		—		—		—		1.5		1.5		—
TECO Coal
Letters of credit		—		—		—		20.0		20.0		—
Guarantees: Fuel purchase related		—		—		—		1.5		1.5		0.9
		—		—		—		21.5		21.5		0.9
Other unregulated subsidiaries
Letters of credit		4.0		—		—		2.7		6.7		—
Guarantees:
Debt related		—		—		—		8.5		8.5		—
Fuel purchase/energy management (2)		—		—		—		194.0		194.0		38.4
		4.0		—		—		205.2		209.2		38.4
Total	$	78.5	$	22.6	$	—	$	733.7	$	834.8	$	51.7

(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 Sept. 30, 2003. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities. See Note 22 for recent activities that reduced the guarantees.

In addition to the financial and non-financial guarantees listed above, TECO Energy provided a guarantee, in connection with the Hardee transaction, as described inNote 20, of the residual value of certain leased turbines with a maximum payment obligation of $6.0 million if each of the following conditions is met at Dec. 31, 2012:

• Neither Seminole Electric nor Tampa Electric exercise their respective purchase options;

• Hardee Power Partners, the lessee, does not exercise its purchase option; and

• The fair value of the leased turbines, in a competitive sale, is less than $12.0 million.

The fair value of this obligation, using expected present value techniques in accordance with FIN 45, is not significant as of Sept. 30, 2003.

TECO Energy and its subsidiaries also 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 Sept. 30, 2003 was $139.3 million. Each project also has a $40 million debt service reserve facility, neither of which has been drawn upon at Sept. 30, 2003. See alsoNote 7.

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Financial Covenants

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

TECO Energy Significant Financial Covenants

(millions) Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Sept. 30, 2003
Tampa Electric
Mortgage bond indenture	Dividend restriction	Cumulative distributions cannot exceed cumulative net income plus $4	$42 unrestricted (2)
PGS senior notes	EBIT/interest	Minimum of 2.0 times	3.8 times
	Restricted payments	Shareholder equity at least $500	$1,687
	Funded debt/capital	Cannot exceed 65%	50.2%
	Sale of assets	Less than 20% of total assets	0%
Credit facility (8)	Debt/capital	Cannot exceed 60%	48.8%
	EBITDA/interest	Minimum of 2.5 times	6.2 times
6.25% senior notes	Debt/capital	Cannot exceed 60%	48.8%
	Limit on liens	Cannot exceed $787	$362
TECO Energy
Credit facilities (3) (8)	Debt/capital	Cannot exceed 65%	56.3%
$37.5 credit facility	EBITDA/interest	Minimum of 2.5 times	2.8 times
	Limit on liens	Cannot exceed 60% of fair value of assets	23.3% (4)
	Debt/capital	Cannot exceed 65%	56.3%
$380 million note indenture	Limit on restricted payments (5)	Cumulative operating cash flow in excess of 1.7 times interest	$310 unrestricted
	Limit on liens	Cannot exceed 5% of tangible assets	$182 unrestricted
	Limit on indebtedness	Interest coverage at least 2.0 times	2.8 times
$300 million note indenture	Limit on liens	Cannot exceed 5% of tangible assets	$182 unrestricted
TPGC guarantees (6)	Debt/capital	Cannot exceed 65%	56.3%
	EBITDA/interest	Minimum of 3.0 times	(7)
TECO Diversified
Energy management services agreement guarantee	Consolidated tangible net worth	Minimum of $200	$504
	Consolidated funded debt	Cannot exceed 60%	19.0%
Coal supply agreement guarantee	Dividend restriction		$504

(1) As defined in each applicable instrument.

(2) Reflects determination as of Sept. 30, 2003, after giving effect to $158 million distributed to TECO Energy as a return of capital during 2003. There are $75 million principal amount of bonds outstanding under the indenture as of Sept. 30, 2003.

(3) 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.

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

(5) The limitation on restricted payments restricts the company from paying dividends or making distributions or certain investments unless there is sufficient cumulative operating cash flow, as defined, in excess of 1.7 times interest to make such distribution or investment. The operating cash flow and restricted payments are calculated on a cumulative basis since the issuance of the 10.5% Notes in the fourth quarter of 2002. This calculation, at Sept. 30, 2003, reflects the amount accumulated and available for future restricted payments, representing the accumulation of three quarters’ activities.

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

(7) This calculation is not required for Sept. 30 or Dec. 31, 2003 until Feb. 1, 2004, as provided by the terms of the Suspension Agreement entered into between the lenders, the project companies and TECO Energy, as discussed below. SeeNote 8.

(8) SeeNote 22 for recent information about the renewal of Tampa Electric’s facility, the repayment of TECO Energy’s 1-year term facility, and the amendment of TECO Energy’s Merrill Lynch facility

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 payment 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.

Suspension Agreement

TECO Energy and the Union and Gila River project companies entered into a Suspension Agreement with the lending group for the Union and Gila River projects to suspend until Feb. 1, 2004 the quarterly calculation of the 3.0 times EBITDA to interest coverage ratio covenant in the TECO Energy Construction Undertakings for the performance by the construction contractor for those projects and other project-related TECO Energy guarantee agreements. The Suspension Agreement contemplates discussions among TECO Energy, the Union and Gila River project companies and the lending group to reach an understanding regarding the projects’ operating budgets and performance before expiration of the suspension period on Jan. 31, 2004. At the end of the suspension period, the Sept. 30 and Dec. 31, 2003 quarterly calculations would be performed. In the absence of an understanding, the lenders could seek to accelerate the non-recourse project debt starting as early as Feb. 1, 2004 for non-compliance with the EBITDA to interest covenant requirements for the quarters ended Sept. 30 or Dec. 31, 2003.

The Construction Undertakings entered into in May 2002, provide that TECO Energy stand behind the performance of the construction contractor, replacing Enron as guarantor of NEPCO’s (its subsidiary’s) performance. NEPCO was ultimately replaced by SNC-Lavalin under a performance-based but cost-plus contract. Currently, major construction has been completed and both projects have achieved commercial operation. As a result, the remaining obligations relate to normal construction closeout matters for final acceptance and warranty obligations, the combined exposure for which is estimated to be in the range of $11 to $13 million. This exposure is also secured by letters of credit in favor of the lending group totaling $66 million that were posted pursuant to the Construction Undertakings.

A default under the Construction Undertakings, including violation of the EBITDA to interest coverage covenant or otherwise, is a cross-default under the $1,395 million non-recourse debt on the projects, which entitles the lending group to exercise remedies including accelerating the non-recourse debt and foreclosing on the projects. As a result, the $1,395 million of non-recourse project debt related to the Union and Gila River projects, which was consolidated at TECO Energy upon the buy-out of Panda’s interest in TPGC, has been reclassified from long-term debt to current debt due within one year (seeNote 8). The non-recourse project debt is not an obligation of TECO Energy, but actions by the lenders could adversely affect its investment in the projects, which is currently carried on its books at $1.1 billion.

The Construction Undertakings permit TECO Energy to terminate its obligations thereunder, including the requirement to comply with the covenants, by providing a Substitute Guarantor reasonably satisfactory to the lending group. On September 22, 2003, TECO Energy tendered a Substitute Guarantor, which it believes satisfied the requirements of the Construction Undertakings. TECO Energy’s tender also included continued maintenance of the letters of credit described above. The lending group declined to accept this tender as being satisfactory. TECO Energy disagrees with the basis of their declining to accept the Substitute Guarantor. If the suspension period ends without TECO Energy and the lending group agreeing to an alternative arrangement, TECO Energy would plan to assert that the Construction Undertakings were terminated in the event that the lending group sought to exercise its rights thereunder based on a violation of the EBITDA to interest coverage ratio covenant. As part of the Suspension Agreement, both TECO Energy and the lending group have agreed not to assert their respective positions during the Suspension Period.

20. Mergers, Acquisitions and Dispositions

In September 2003, TPS sold Hardee Power Partners, Ltd. (HPP), which holds a 370-MW gas-fired generation facility located in central Florida, to an affiliate of Invenergy LLC and GTCR Golder Rauner LLC. The potential sale of Hardee was previously announced on April 11, 2003 as one of the strategic options under consideration. The sale closed on Sept. 30, 2003. Under the terms of the sale, TPS will continue to provide service to HPP under the existing operation and maintenance agreement. The new owner may, at any time, choose to cancel this agreement. Also, in connection with the sale, TECO Energy undertook a guarantee, capped at $6.0 million, of the residual value of certain leased turbines as discussed inNote 19. Furthermore, Tampa Electric’s long-term power purchase obligation to receive electricity from HPP remains in effect with no changes as a result of the transaction (seeNote 1). The sale proceeds of approximately $107.7 million exceeded the net book value of $51.5 million recorded at Sept. 30, 2003 (including assets of $149.1 million and liabilities of $97.6 million).

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At Dec. 31, 2002, TPS had a loan receivable of $137 million from PLC, a subsidiary of Panda Energy International. On Jan. 3, 2003, this loan was converted to a partnership interest in PLC. SeeNotes 1and16 for additional details regarding the conversion of this loan to an equity interest in PLC. Furthermore, in September 2003, the company consummated the foreclosure on Panda Energy’s interest in PLC for a default under a $23 million note receivable resulting in TPS’ 100-percent ownership in PLC which owns 50-percent of TIE (seeNotes 1, 12and16). As of Sept. 30, 2003, TPS consolidated PLC resulting in a net increase in investment in unconsolidated affiliates of approximately $18 million and recognition of an unrealized after-tax loss of approximately $5 million in OCI related to interest rate swaps designated as cash flow hedges and held at TIE. For a detailed discussion of the termination of the company’s partnership with Panda Energy in TPGC, seeNote 12.

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 was contingent upon receipt of a positive response to a Private Letter Ruling (PLR) request, and the proceeds from this transaction were held in escrow pending resolution of this contingency. The current PLR request was made to reflect the revised ownership structure, location of facilities and other terms of the two previous PLRs. SeeNote 22 for a discussion of the impact of the subsequent receipt of the PLR from the IRS.

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.

21. 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. SeeNote 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. SeeNote 11 for a discussion of activities subject to this guidance.

Gains and Losses on Energy Trading Contracts

On Oct. 25, 2002, the Emerging Issues Task Force released EITF 02-3,Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, which 1) precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to FAS 133, 2) requires that gains and losses on all derivative instruments within the scope of FAS 133 be presented on a net basis in the income statement if held for trading purposes, and 3) limits the circumstances in which a reporting entity may recognize a “day one” gain or loss on a derivative contract. The measurement provisions of the issue are effective for all fiscal periods beginning after Dec. 15, 2002. The net presentation provisions are effective for all financial statements issued after Dec. 15, 2002. The adoption of the measurement provisions on Jan. 1, 2003 did not have a material impact. SeeNote 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 (seeNote 19). On Jan. 1, 2003, the company adopted the prospective measurement provisions without a material effect.

32

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.

On Oct. 9, 2003, the FASB issued FASB Staff Position (FSP) No. FIN 46-6,Effective Date of FASB Interpretation No. 46,Consolidation of Variable Interest Entities. FSP FIN 46-6 deferred the effective date of the on-going disclosure and consolidation requirements of FIN 46 for VIEs created before Feb. 1, 2003 if the reporting entity had not issued financial statements reporting the VIE as a consolidated entity as of the issuance date of the FSP. The on-going disclosure and consolidation requirements are effective for all interim financial periods beginning after Dec. 15, 2003. As of Sept. 30, 2003, additional technical issues continue to be deliberated by the FASB. Furthermore, as of Oct. 31, 2003, the FASB issued, for public comment, an exposure draft of a proposed interpretation to modify FIN 46.

Based on its review under the existing approved guidance, 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 significantly impact the analysis. Below is a discussion of the legal entities as of Sept. 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.

PLC, a fully consolidated subsidiary of TPS, has a 50-percent ownership interest in the TIE partnership (seeNote 16). The TIE partnership owns and operates the Odessa and Guadalupe power stations in Texas. TIE may be a VIE in accordance with FIN 46. Based on preliminary analyses under the existing approved guidance, TECO Energy does not expect to consolidate TIE as the primary beneficiary if TIE is a VIE. The estimated maximum loss exposure is approximately $162.1 million, representing primarily TPS’ equity investment as of Sept. 30, 2003.

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 Sept. 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 Sept. 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.

33

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 re-measured at fair value on each reporting date.

This standard is effective for all financial instruments entered into or modified after May 31, 2003, and for all other financial instruments, at the beginning of the first interim period beginning after June 15, 2003. SeeNote 8 for a discussion of the impact of the adoption of this standard on July 1, 2003.

22. Subsequent Events

Restructuring Costs

On Oct. 7, 2003, TECO Energy announced phase two of the corporate reorganization discussed inNote 11. As a result of this phase of the restructuring, the company took additional steps towards re-alignment to provide for centralized oversight according to functional lines for power plant operations, energy delivery, energy management, human resources and technology/support services. This phase included the involuntary termination or retirement of 207 employees, including primarily personnel from power plant operations, bulk terminal operations, office staff and support services. The company will recognize an expense in the fourth quarter of approximately $11.2 million for accrued benefits including severance and other termination and retirement benefits. The table below details the expense to be recognized by the operating segments in the fourth quarter.

(millions)	Tampa Electric		Peoples Gas		TPS		TECO Transport		TECO Coal		Other Unregulated		Eliminations & Other		TECO Energy
Termination and retirement benefit expense	$	6.1	$	2.0	$	0.7	$	1.6	$	—	$	0.5	$	0.3	$	11.2

The company expects to complete the second phase of restructuring activities by the end of 2003.

Section 29 Private Letter Ruling

On Oct. 31, 2003, TECO Coal received a PLR from the IRS that resolves any uncertainty related to the previous sale of the 49.5-percent interest in its synfuel facilities, triggers the release of certain cash escrows related to this sale, and confirms that synthetic fuel produced by TECO Coal is eligible for Section 29 credits and that its test procedures are in compliance with the requirements of the IRS. Receipt of this PLR will result in the reversal of $28.5 million of previously deferred tax credits in future periods (seeNote 13). On Nov. 5, 2003, $58.9 million of restricted cash that had been held in escrow was released (seeNote 1).

Revised Segment Reporting

TECO Energy expects to implement revised segment reporting for TECO Power Services’ merchant generating assets in the near future. Under the revised format the merchant generating assets (those operating without a significant portion of their output under long-term contract) and the associated allocated interest expense is expected to be reported separately. The TPS assets with long–term power sales agreements will be reported with Other Unregulated businesses. Management believes that this revised method of segment reporting will provide clearer information regarding the value within the regulated businesses and those unregulated businesses with more stable lines of business as compared to the more volatile merchant energy sector.

34

Affiliate Transaction – TECO Transport Contract

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

The contract was signed at the conclusion of a bid process conducted by Tampa Electric and a detailed market rate analysis by an outside expert consultant to determine current transportation market prices. The new contract includes rates that are slightly lower than those currently charged and are expected to result in savings to Tampa Electric’s retail customers.

The costs associated with this fuel transportation contract are expected to be reviewed by the Florida Public Service Commission (FPSC) in the first quarter of 2004. The review is expected to focus on the request for proposal process employed by Tampa Electric, the rates under the contract and the appropriateness of the existing FPSC benchmark methodology to measure actual market transportation rates on a going-forward basis.

Guarantees and Letters of Credit Reductions

As of Nov. 3, 2003, TECO Energy had renegotiated and re-evaluated the significant number of the guarantees and letters of credit outstanding as of Sept. 30, 2003 as discussed inNote 19. As a direct result of these efforts, the maximum theoretical obligation under TECO Energy’s guarantees and letters of credit for fuel purchase/energy management and issued for the benefit of TPS and Prior Energy, has been reduced to $325 million.

Tampa Electric Company Credit Line Renewal

On Nov. 7, 2003 Tampa Electric replaced its maturing $300 million bank facility with a $250 million facility. The new facility includes a new covenant limiting cumulative distributions and outstanding loans to its parent to an amount representing an accumulation of net income after May 31, 2003, and capital contributions from the parent after Oct. 31, 2003, plus $450 million.

TECO Energy $350 million Term Loan Maturity and $350 million Credit Facility Amended

On Nov. 13, 2003, TECO Energy repaid the $350 million bank term loan maturing on that date. On Nov. 12, 2003, TECO Energy and Merrill Lynch amended the existing $350 million Merrill Lynch credit facility that was previously required to be drawn by Nov. 13, 2003 in order to maintain the capacity under the facility. The amendment reduces the commitment to $100 million of undrawn line capacity available through April 8, 2004, at which time the facility can be drawn up to $100 million and remain outstanding to Oct. 8, 2004. The $100 million facility is required to be reduced for certain asset sales and financings. The facility was undrawn at the time of the amendment.

Suspension Agreement and Rating Agency Activities

On Oct. 28, 2003, the company entered into a Suspension Agreement with the lending group, as discussed more fully in Notes 7, 8 and 19. As previously discussed inNote 19, the Suspension Agreement contemplates discussions among TECO Energy, the Union and Gila River project companies and the lending group to reach an understanding regarding the projects’ operating budgets and performance before the expiration of the suspension period on Jan. 31, 2004.

On Nov. 5, 2003, Standard and Poor’s (S&P) removed the Credit Watch and affirmed the existing ratings on TECO Energy and Tampa Electric Company, leaving the outlook Negative. S&P indicated in support of its continued Negative Outlook that it had remaining concerns about the ultimate resolution of TECO Energy’s merchant exposure, management’s commitment to a redefined business strategy, and elevated debt balances. S&P further indicated that a return to ratings stability is directly correlated to a swift exit from merchant activity and a prudent use of free cash flow to reduce indebtedness.

As discussed in Notes 1 and 10, the estimates used for the asset impairment test under FAS 144 are based on assumptions deemed to be reasonable in the judgment of management. The Suspension Agreement and contemplated discussions, continuing changes in external factors, and the future performance of individual assets, may cause management to reconsider or adjust the assumptions and expectations in the future.

Agreement to Sell TECO Propane Ventures’ Indirect Interest in Heritage Propane Partners, LP

On Nov. 7, 2003, the company announced an agreement by TECO Propane Ventures, LLC, a wholly owned subsidiary of TECO Energy, along with affiliates of Atmos Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources, Inc., to: (1) sell the general partnership interest in Heritage Propane Partners, LP (“Heritage”) that is currently owned by US Propane LP; and to (2) sell US Propane’s ownership of Heritage Holdings, Inc. which owns limited partnership interests in Heritage. TECO Energy’s portion of the sale is anticipated to generate approximately $50 million of cash proceeds and a pretax book gain of approximately $18 million. The closing of this transaction is conditioned upon financing and regulatory approvals, which are expected before the end of the year.

35

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 Sept. 30, 2003 and Dec. 31, 2002, and the results of operations and cash flows for the three-month and nine-month periods ended Sept. 30, 2003 and 2002. The results of operations for the three-month and nine-month periods ended Sept. 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 43 to 51 of this report.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page No.
Consolidated Balance Sheets, Sept. 30, 2003 and Dec. 31, 2002	37-38
Consolidated Statements of Income for the three-month and nine-month periods ended Sept. 30, 2003 and 2002	39-40
Consolidated Statements of Comprehensive Income for the three-month and nine-month periods ended Sept. 30, 2003 and 2002	41
Consolidated Statements of Cash Flows for the nine-month periods ended Sept. 30, 2003 and 2002	42
Notes to the Consolidated Financial Statements	43-51

36

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets

Assets (millions)	Sept. 30, 2003 Unaudited			Dec. 31, 2002
Property, plant and equipment
Utility plant in service
Electric	$	4,644.4		$	4,310.8
Gas		768.5			746.7
Construction work in progress		442.9			768.5
Property, plant and equipment, at original cost		5,855.8			5,826.0
Accumulated depreciation		(2,228.6	)		(2,161.0	)
		3,627.2			3,665.0
Other property		8.0			7.9
Total property, plant and equipment		3,635.2			3,672.9
Current assets
Cash and cash equivalents		57.3			6.9
Receivables, less allowance for uncollectibles of $1.0 million at Sept. 30, 2003 and $1.1 million at Dec. 31, 2002		215.9			186.5
Inventories
Fuel, at average cost		66.3			79.1
Materials and supplies		47.3			48.1
Prepayments and other		16.7			18.4
Total current assets		403.5			339.0
Deferred debits
Deferred income taxes		134.2			133.3
Unamortized debt expense		23.8			23.7
Regulatory assets		184.4			163.2
Other		(2.9	)		5.6
Total deferred debits		339.5			325.8
Total assets	$	4,378.2		$	4,337.7

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

37

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets—continued

Liabilities and Capital (millions)	Sept. 30, 2003 Unaudited		Dec. 31, 2002
Capital
Common stock	$	1,376.8	$	1,535.1
Retained earnings		310.4		302.9
Total capital		1,687.2		1,838.0
Long-term debt, less amount due within one year		1,590.8		1,345.6
Total capitalization		3,278.0		3,183.6
Current liabilities
Long-term debt due within one year		6.1		81.0
Notes payable		10.0		10.5
Accounts payable		129.4		178.8
Current derivative liabilities		5.0		—
Customer deposits		99.0		94.6
Interest accrued		27.6		18.3
Taxes accrued		70.4		46.9
Total current liabilities		347.5		430.1
Deferred credits
Deferred income taxes		505.1		483.1
Investment tax credits		23.7		27.1
Regulatory liabilities		96.4		98.1
Other		127.5		115.7
Total deferred credits		752.7		724.0
Total liabilities and capital	$	4,378.2	$	4,337.7

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

38

TAMPA ELECTRIC COMPANY

Consolidated Statements of Income

Unaudited

(millions)	Three months ended Sept. 30,
	2003			2002
Revenues
Electric (includes franchise fees and gross receipts taxes of $18.4 million in 2003, $17.5 million in 2002)	$	456.0		$	438.9
Gas (includes franchise fees and gross receipts taxes of $2.6 million in 2003, $2.0 million in 2002)		103.2			74.4
Total revenues		559.2			513.3
Expenses
Operations
Fuel		131.1			122.8
Purchased power		64.9			66.6
Cost of natural gas sold		63.1			37.6
Other		66.8			64.8
Maintenance		21.3			22.9
Depreciation		63.0			57.0
Restructuring charges		3.9			—
Taxes, federal and state income		30.7			35.3
Taxes, other than income		35.7			32.0
Total expenses		480.5			439.0
Income from operations		78.7			74.3
Other income
Allowance for other funds used during construction		3.9			6.9
Other income, net		1.1			0.8
Total other income		5.0			7.7
Interest charges
Interest on long-term debt		26.5			17.5
Other interest		2.5			1.0
Allowance for borrowed funds used during construction		(1.5	)		(2.7	)
Total interest charges		27.5			15.8
Net income	$	56.2		$	66.2

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

39

TAMPA ELECTRIC COMPANY

Consolidated Statements of Income

Unaudited

(millions)	Nine months ended Sept. 30,
	2003			2002
Revenues
Electric (includes franchise fees and gross receipts taxes of $48.7 million in 2003, $47.8 million in 2002)	$	1,205.5		$	1,197.5
Gas (includes franchise fees and gross receipts taxes of $10.4 million in 2003, $7.6 million in 2002)		324.9			237.1
Total revenues		1,530.4			1,434.6
Expenses
Operations
Fuel		335.4			337.1
Purchased power		169.4			169.3
Cost of natural gas sold		186.2			111.1
Other		189.1			192.8
Maintenance		65.5			77.5
Depreciation		182.8			164.3
Restructuring charges		3.9			3.2
Taxes, federal and state income		80.8			85.8
Taxes, other than income		103.9			99.2
Total expenses		1,317.0			1,240.3
Income from operations		213.4			194.3
Other income
Allowance for other funds used during construction		15.6			16.9
Other income, net		1.2			1.6
Asset impairment (net of income tax benefit of $30.7)		(48.9	)		—
Total other (expense) income		(32.1	)		18.5
Interest charges
Interest on long-term debt		76.4			51.8
Other interest		7.6			5.7
Allowance for borrowed funds used during construction		(6.1	)		(6.5	)
Total interest charges		77.9			51.0
Net income	$	103.4		$	161.8

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

40

TAMPA ELECTRIC COMPANY

Consolidated Statements of Comprehensive Income

Unaudited

(millions)	Three months ended Sept. 30,				Nine months ended Sept. 30,
	2003		2002		2003		2002
Net income	$	56.2	$	66.2	$	103.4	$	161.8
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	$	56.2	$	66.2	$	103.4	$	161.9

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

41

TAMPA ELECTRIC COMPANY

Consolidated Statements of Cash Flows

Unaudited

(millions)	Nine months ended Sept. 30,
	2003			2002
Cash flows from operating activities
Net income	$	103.4		$	161.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		182.8			164.3
Deferred income taxes		12.7			(10.0	)
Asset impairment, pretax		79.6			—
Investment tax credits, net		(3.5	)		(3.3	)
Allowance for funds used during construction		(21.7	)		(23.4	)
Deferred recovery clause		(24.5	)		75.2
Refund to customers		—			(6.1	)
Receivables, less allowance for uncollectibles		(29.4	)		(55.4	)
Inventories		13.6			(9.9	)
Prepayments		(1.8	)		(1.7	)
Taxes accrued		23.5			25.0
Interest accrued		9.3			11.7
Accounts payable		(49.3	)		(2.8	)
Other		44.9			(9.7	)
Cash flows from operating activities		339.6			315.7
Cash flows from investing activities
Capital expenditures		(226.9	)		(510.8	)
Allowance for funds used during construction		21.7			23.4
Proceeds from sale of assets		1.0			—
Cash flows from investing activities		(204.2	)		(487.4	)
Cash flows from financing activities
Proceeds from contributed capital from parent		—			217.0
Return of capital		(158.3	)		—
Proceeds from long-term debt		250.0			690.4
Repayment of long-term debt		(80.3	)		(302.4	)
Net increase (decrease) in short-term debt		(0.5	)		(244.0	)
Payment of dividends		(95.9	)		(197.4	)
Cash flows from financing activities		(85.0	)		163.6
Net (decrease) in cash and cash equivalents		50.4			(8.1	)
Cash and cash equivalents at beginning of period		6.9			15.4
Cash and cash equivalents at end of period	$	57.3		$	7.3

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

42

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. 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. SeeNote 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. As a result of TPS’ sale of Hardee Power Partners, Ltd. (HPP) in September 2003 (seeNotes 19 and20to theTECO Energy Consolidated Financial Statements), all periods presented reflect the reclassification of power purchases from HPP as non-affiliate purchases. Tampa Electric’s long-term power purchase agreement from HPP was not affected by TPS’ sale of HPP. Under the existing agreement, which has been approved by the FPSC, Tampa Electric has the right to purchase, on average, approximately 52% of the total output of the Hardee power station. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.9 million and $169.4 million, respectively, for the three months and nine months ended Sept. 30, 2003, compared to $66.6 million and $169.3 million, respectively, for the three months and nine months ended Sept. 30, 2002. 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 4.5% and 4.2% for the nine months ended Sept. 30, 2003 and 2002, respectively. For the nine months ended Sept. 30, 2003, Tampa Electric recognized depreciation expense of approximately $19 million related to accelerated depreciation of certain Gannon power station coal-fired assets, in accordance with a regulatory order issued by the FPSC.

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 million. At Sept. 30, 2003, the cost of removal and dismantlement component of accumulated depreciation was approximately $459 million.

The implementation of FAS 143,Accounting for Asset Retirement Obligationsin 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 (seeNote 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 Statements of Income. For the three months ended Sept. 30, 2003 and 2002 these amounts totaled $21.0 million, and $19.5 million, respectively, and for the nine months ended Sept. 30, 2003 and 2002 these amounts totaled $59.1 million and $55.4 million, respectively. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. For the three months ended Sept. 30, 2003

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and 2002, these totaled $20.9 million and $19.5 million, respectively, and for the nine months ended Sept. 30, 2003 and 2002, they totaled $58.9 million and $55.4 million, respectively.

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. As discussed inNote 7, indicators of impairment existed for certain long-term turbine purchase contracts, triggering a requirement to test for a impairment of these assets. No other significant events or changes in circumstances occurred during the nine months ended Sept. 30, 2003 to indicate an impairment.

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 (seeNote 13). Tampa Electric’s first mortgage bond indenture does not limit loans and advances. SeeNote 15 for an update on Tampa Electric Company’s credit line renewal and additional covenants included.

2. Derivatives and Hedging

At Sept. 30, 2003, the company had a net derivative liability of $5.0 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 Sept. 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 Sept. 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 nine months ended Sept. 30, 2003, the company reclassified net pretax losses of $1.5 million and gains of $5.8 million, respectively, to earnings for cash flow hedges, compared to pretax losses of $0.1 million for the nine months ended Sept. 30, 2002. No amounts were reclassified to earnings for the three months ended Sept. 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 (seeNote 3).

Based on the fair values of derivatives at Sept. 30, 2003, pretax losses of $5.0 million are expected to be reversed from OCI to the Consolidated Statements 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 Sept. 30, 2003 and Dec. 31, 2002 are presented in the following table:

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Regulatory Assets and Liabilities

(millions)	Sept. 30, 2003		Dec. 31, 2002
Regulatory assets:
Regulatory tax asset (1)	$	58.5	$	54.9
Other:
Cost recovery clauses		58.2		34.7
Coal contract buy-out (2)		3.4		5.4
Unamortized refinancing costs (3)		33.1		35.9
Environmental remediation		20.7		20.3
Competitive rate adjustment		4.9		7.4
Other		5.6		4.6
		125.9		108.3
Total regulatory assets	$	184.4	$	163.2
Regulatory liabilities:
Regulatory tax liability (1)	$	32.0	$	36.6
Other:
Deferred allowance auction credits		2.0		2.1
Cost recovery clauses		1.3		2.2
Environmental remediation		20.7		20.3
Transmission and distribution storm reserve		39.0		36.0
Deferred gain on property sales (4)		1.3		0.9
Deferred gain on property sales (4)		0.1		—
		64.4		61.5
Total regulatory liabilities	$	96.4	$	98.1

(1) Related primarily to plant life. Includes excess deferred taxes of $18.0 million and $20.9 million as of Sept. 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 an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

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

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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 assets retirement obligations of $0.3 million. The after-tax charge recorded as a change in accounting principle was not material.

For the three and nine months ended Sept. 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 nine months ended Sept. 30, 2002.

5. Short-term Debt

Notes payable at Dec. 31, 2002 consisted of $10.5 million of commercial paper with a weighted average interest rate of 1.86%. Tampa Electric Company’s $300 million credit facility has a maturity date of November 2003. (SeeNote 15 regarding the renewal of this facility.) At Sept. 30, 2003, $10.0 million of the credit facility was drawn, while none was drawn at Dec. 31, 2002. The credit facility requires commitment fees of 20 basis points, and drawn amounts are charged interest at LIBOR plus 105-117.5 basis points, depending on the amount of the draw, 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.

7. Asset Impairments

For the nine months ended Sept. 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 inNote 11 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. Restructuring Costs

In early September 2003, TECO Energy announced a corporate reorganization to restructure the company along functional lines, consistent with its objectives to grow the core utility operation, maintain liquidity, generate cash and maximize the value in the existing assets. As part of this restructuring phase, and the additional actions taken in October 2003 (seeNote 15), the company is now aligned to provide for centralized oversight according to functional lines for power plant operations, energy delivery, energy management, and human resources and technology/support services. This phase at Tampa Electric Company included the involuntary termination or retirement of 38 employees at the electric division and 30 employees at the gas division, including officers and other personnel from plant operations, support services, certain regional offices and two call centers. The company recognized an expense of $3.9 million for accrued benefits including severance and salary continuation through the end of 2003 and other termination and retirement benefits.

Tampa Electric Company expects to complete this phase of restructuring activities by the end of 2003. As of Sept. 30, 2003, no adjustments have been made to the benefits initially accrued for and $1.2 million of the accrued benefits have been paid or otherwise settled.

9. 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 inNote 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 nine months ended Sept. 30, 2003 was 38.58%.

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Effective Income Tax Rate

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions)	2003			2002			2003			2002
Net income from continuing operations, excluding unusual and infrequently occurring item, net of tax	$	56.3		$	66.2		$	152.4		$	161.8
Total income tax provision, excluding tax associated with unusual and infrequently occurring item (1)		31.4			36.0			81.6			86.4
Income from continuing operations before income taxes, excluding unusual and infrequently occurring item (1)	$	87.7		$	102.3		$	234.0		$	248.3
Income taxes on above at federal statutory rate of 35%	$	30.6		$	35.7		$	81.8		$	86.8
Increase (decrease) due to               State income tax, net of federal income tax		3.2			3.7			8.4			8.9
Amortization of investment tax credits		(1.2	)		(1.1	)		(3.4	)		(3.3	)
AFUDC Equity		(1.4	)		(2.4	)		(5.5	)		(5.9	)
Other		0.2			0.1			0.3			(0.1	)
Total income tax provision from continuing operations	$	31.4		$	36.0		$	81.6		$	86.4
Provision for income taxes as a percent of income from continuing operations, before income taxes		35.8	%		35.2	%		34.9	%		34.8	%

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

10. Comprehensive Income

As discussed inNote 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)	Gross			Tax			Net
Three months ended Sept. 30,
2003
Unrealized (loss) gain on cash flow hedges	$	(1.5	)	$	(0.6	)	$	(0.9	)
Less: Loss (gain) reclassified to net income		1.5			0.6			0.9
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)	$	—		$	—		$	—
Nine months ended Sept. 30,
2003
Unrealized gain (loss) on cash flow hedges	$	5.8		$	2.2		$	3.6
Less: (Gain) loss reclassified to net income		(5.8	)		(2.2	)		(3.6	)
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

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11. Related Parties

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 under which 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 and third quarters of 2003, Tampa Electric returned $158 million of capital to TECO Energy. TECO Energy had previously contributed capital to Tampa Electric in support of Tampa Electric’s construction program in the wholesale business, which has been scaled back.

12. Segment Information

(millions) Three months ended Sept. 30,	Tampa Electric			Peoples Gas		Other & Eliminations			Tampa Electric Company
2003
Revenues-outsiders	$	455.4		$	103.2	$	—		$	558.6
Sales to affiliates		0.8			—		(0.2	)		0.6
Total revenues	$	456.2		$	103.2	$	(0.2	)	$	559.2
Depreciation		54.8			8.2		—			63.0
Restructuring costs (1)		2.2			1.7		—			3.9
Interest charge		23.6			3.9		—			27.5
Provision (benefit) for taxes		29.2			1.5		—			30.7
Net income	$	53.3		$	2.9	$	—		$	56.2
2002
Revenues-outsiders	$	438.3		$	74.4	$	—		$	512.7
Sales to affiliates		0.8			—		(0.2	)		0.6
Total revenues	$	439.1		$	74.4	$	(0.2	)	$	513.3
Depreciation		49.3			7.7		—			57.0
Restructuring costs		—			—		—			—
Interest charge		12.1			3.7		—			15.8
Provision (benefit) for taxes		33.4			1.9		—			35.3
Net income	$	63.1		$	3.1	$	—		$	66.2
Nine months ended Sept. 30,
2003
Revenues-outsiders	$	1,203.5		$	324.9	$	—		$	1,528.4
Sales to affiliates		2.5			—		(0.5	)		2.0
Total revenues	$	1,206.0		$	324.9	$	(0.5	)	$	1,530.4
Depreciation		158.1			24.7		—			182.8
Restructuring costs (1)		2.2			1.7		—			3.9
Interest charge		66.2			11.7		—			77.9
Provision (benefit) for taxes		38.1	(2)		12.0		—			50.1
Net income	$	83.8	(2)	$	19.6	$	—		$	103.4
2002
Revenues-outsiders	$	1,195.6		$	237.1	$	—		$	1,432.7
Sales to affiliates		2.5			—		(0.6	)		1.9
Total revenues	$	1,198.1		$	237.1	$	(0.6	)	$	1,434.6
Depreciation		141.5			22.8		—			164.3
Restructuring costs		3.2			—		—			3.2
Interest charge		40.2			10.8		—			51.0
Provision (benefit) for taxes		74.9			10.9		—			85.8
Net income	$	144.5		$	17.3	$	—		$	161.8

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(1) In early September, Tampa Electric Company announced a corporate reorganization to restructure the company along functional lines, consistent with its objectives to grow the core utility operation, maintain liquidity, generate cash and maximize the value of existing assets (seeNote 8).

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

13. 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 Sept. 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 Sept. 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 Sept. 30, 2003 is as follows:

Tampa Electric Company’s Significant Financial Covenants

(millions)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Sept. 30, 2003
Tampa Electric
Mortgage bond indenture	Dividend restriction	Cumulative distributions cannot exceed cumulative net income plus $4	$42 unrestricted (2)
PGS senior notes	EBIT/interest	Minimum of 2.0 times	3.8 times
	Restricted payments	Shareholder equity at least $500	$1,687
	Funded debt/capital	Cannot exceed 65%	50.2%
	Sale of assets	Less than 20% of total assets	0%
Credit facility (3)	Debt/capital	Cannot exceed 60%	48.8%
	EBITDA/interest	Minimum of 2.5 times	6.2 times
6.25% senior notes	Debt/capital	Cannot exceed 60%	48.8%
	Limit on liens	Cannot exceed $787	$362

(1) As defined in each applicable instrument.

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(2) Reflects determination as of Sept. 30, 2003, after giving effect to $158 million distributed to TECO Energy as a return of capital during 2003. There are $75 million principal amount of bonds outstanding under the indenture as of Sept. 30, 2003.

(3) SeeNote 15 for information regarding the recent renewal of this facility.

14. 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. SeeNote 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. SeeNote 8 for a discussion of activities subject to this guidance.

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 (seeNote 13). 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.

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

This standard is effective for all financial instruments entered into or modified after May 31, 2003, and for all other financial instruments, at the beginning of the first interim period beginning after June 15, 2003. Tampa Electric Company adopted the standard with no material impact.

15. Subsequent Events

Restructuring Costs

On Oct. 7, 2003, TECO Energy announced phase two of the corporate reorganization discussed inNote 8. As a result of this phase of the restructuring, the company took additional steps towards re-alignment to provide for centralized oversight according to functional lines for power plant operations, energy delivery, energy management, and human resources and technology/support services. This process at Tampa Electric Company included the involuntary termination or retirement of 131 employees, including personnel from power plant operations, office staff and support services. The company will recognize an expense in the fourth quarter of approximately $8.1 million for accrued benefits including severance and other termination and retirement benefits. The table below details the expense to be recognized by the operating divisions in the fourth quarter.

(millions)	Tampa Electric		Peoples Gas		Tampa Electric Company
Termination and retirement benefit expense	$	6.1	$	2.0	$	8.1

The company expects to complete the second phase of restructuring activities by the end of 2003.

Affiliate Transaction –TECO Transport Contract

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

The contract was signed at the conclusion of a bid process conducted by Tampa Electric and a detailed market rate analysis by an outside expert consultant to determine current transportation market prices. The new contract includes rates that are slightly lower than those currently charged and are expected to result in savings to Tampa Electric’s retail customers.

The costs associated with this fuel transportation contract are expected to be reviewed by the Florida Public Service Commission (FPSC) in the first quarter of 2004. The review is expected to focus on the request for proposal process employed by Tampa Electric, the rates under the contract and the appropriateness of the existing FPSC benchmark methodology to measure actual market transportation rates on a going-forward basis.

Tampa Electric Company credit line renewal

On Nov. 7, 2003 Tampa Electric replaced its maturing $300 million bank facility with a $250 million facility. The new facility includes a new covenant limiting cumulative distributions and outstanding loans to its parent to an amount representing an accumulation of net income after May 31, 2003, and capital contributions from the parent after Oct. 31, 2003, plus $450 million.

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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; TECO Energy’s ability to rationalize its merchant generation portfolio or otherwise insulate itself from the impact of these plants; 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. 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 under “Risk Factors” in TECO Energy’s prospectus supplement filed with the Securities and Exchange Commission on Sept. 11, 2003, and reference is made thereto.

Earnings Summary—Unaudited

	Three months ended Sept. 30,					Nine months ended Sept. 30,
(millions, except per share amounts)	2003			2002		2003			2002
Consolidated revenues	$	940.7		$	725.6	$	2,322.1		$	1,994.4
Net (loss) income from continuing operations (1)	$	(19.2	)	$	110.6	$	(146.6	)	$	256.9
Discontinued operations (2)		37.4			8.3		66.7			23.1
Cumulative effect of change in accounting		(3.2	)		—		(4.3	)		—
Net (loss) income	$	15.0		$	118.9	$	(84.2	)	$	280.0
Average common shares outstanding
Basic		179.5			156.1		177.5			146.4
Diluted		179.8			156.1		177.8			146.7
Earnings per share—basic
Continuing operations (1)	$	(0.11	)	$	0.71	$	(0.83	)	$	1.75
Discontinued operations (2)		0.21			0.05		0.38			0.16
Cumulative effect of change in accounting		(0.02	)		—		(0.02	)		—
Earnings per share—basic	$	0.08		$	0.76	$	(0.47	)	$	1.91
Earnings per share—diluted
Continuing operations (1)	$	(0.11	)	$	0.71	$	(0.83	)	$	1.75
Discontinued operations (2)		0.21			0.05		0.38			0.16
Cumulative effect of change in accounting		(0.02	)		—		(0.02	)		—
Earnings per share—diluted	$	0.08		$	0.76	$	(0.47	)	$	1.91

(1) Results for the three months ended Sept. 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 nine months ended Sept. 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 and Hardee Power Partners).

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Operating Results

Three Months Ended Sept. 30, 2003:

TECO Energy, Inc. (the company) reported third quarter net income of $15.0 million compared with $118.9 million in the third quarter of 2002. Earnings per share were $0.08, compared with $0.76 for the same periods in 2002. The loss from continuing operations was $19.2 million in the third quarter, compared with net income of $110.6 million for the same period in 2002. On an earnings-per-share basis, the loss from continuing operations was $0.11 for the third quarter, compared with earnings per share of $0.71 in the 2002 period. Discontinued operations in the quarter reflect the results from Hardee Power Partners (the owner of the Hardee Power Station), which was sold Sept. 30, 2003. The number of common shares outstanding was 15 percent higher for the quarter than for the same period in 2002.

Total results were driven primarily by the negative results at the wholesale merchant plants, which have been coming online throughout 2003, the cost associated with actions to limit merchant exposure at TPS, synfuel issues, and reorganization of the company to best accomplish the goal of focusing on the core Florida operations. During the third quarter, the company completed several events in line with that focus.

• Completed the major construction activities at both the Union and Gila River power stations with the final phases of Gila River ahead of schedule;

• Completed the sale of Hardee Power Partners, for net proceeds of over $100 million;

• Completed a common equity sale, raising $129 million;

• Completed the acquisition of Panda’s interest in the Odessa and Guadalupe power stations (Texas Independent Energy or TIE) and started marketing the equity interest in these plants; and

• Announced a corporate restructuring in September to better align the organization with the strategic focus, and completed these activities in October.

Nine months Ended Sept. 30, 2003:

The year-to-date loss was $84.2 million, compared with net income of $280.0 million for the same period in 2002. The loss on an earnings-per-share basis was $0.47, compared with earnings-per-share of $1.91 for the same period in 2002. The year-to-date loss from continuing operations was $146.6 million, compared with net income of $256.9 million for the same period in 2002. The loss from continuing operations on an earnings-per-share basis was $0.83, compared with earnings-per-share of $1.75 for the same period in 2002. Year-to-date discontinued operations reflected the results from Hardee Power Partners. Shares outstanding for the first nine months were 21 percent higher than for the same period in 2002.

See TECO Energy’s Current Report on Form 8-K dated October 23, 2003, for a reconciliation of net income in accordance with generally accepted accounting principles (GAAP) to a non-GAAP net income from continuing operations that adjusts for certain items, including certain items discussed below underOther Changes Affecting Net Income.

Tampa Electric Company—Electric division (Tampa Electric)

Tampa Electric’s net income for the third quarter was $53.3 million, compared with $63.1 million for the same period in 2002, principally due to lower earnings from the equity component of allowance for funds used during construction (AFUDC, which represents allowed equity cost capitalized to construction costs), higher depreciation expense, and higher interest expense. The lower AFUDC was principally driven by the Gannon / Bayside repowering project, for which AFUDC decreased to $3.9 million for the quarter, from $6.9 million for the same period in 2002, reflecting the commercial operation of Bayside Unit 1 in April 2003. Depreciation expense increased, reflecting $6 million pretax of accelerated depreciation on the Gannon coal assets scheduled for retirement at the end of 2003, the April in-service of Bayside Unit 1, and normal electric plant additions to support customer growth, partially offset by the retirement of the Hookers Point and Dinner Lake power stations. Interest expense increased due to higher long-term debt balances. Lower operations and maintenance expenses for the quarter reflected lower expenditures on generating units. Tampa Electric recorded a $1.3-million after-tax charge ($2.2 million pretax) in the third quarter for costs associated with the corporate restructuring announced Sept. 2, 2003.

Retail energy sales increased 3.9 percent in the quarter, reflecting an improved local economy, average customer growth of 2.5 percent, and increased per-customer usage, which more than offset milder weather and decreased sales to industrial phosphate customers. Cooling degree-days in the quarter were 5.5 percent lower than 2002 and 1.5 percent lower than normal.

Tampa Electric’s year-to-date net income, excluding the $48.9-million charge recorded in the first quarter related to turbine purchase cancellations, was $132.7 million, compared to $144.5 million in 2002. The equity component of AFUDC decreased to $15.7 million, from $16.9 million for the same period in 2002, reflecting the commercial operation of Bayside Unit 1 in April 2003. These results also reflect customer growth of 2.4 percent and 2.3 percent higher retail energy sales. Total heating and cooling degree-days were 4.9 percent above normal due to colder than normal winter weather, but 2.4 percent lower than 2002 due to mild summer weather in 2003. Depreciation expense increased and operations and maintenance expense decreased as a result of the factors discussed for the quarter. Results in 2002 also included a $3.2-million after-tax charge related to an early employee retirement program in the second quarter. Tampa Electric’s year-to-date net income, including the turbine purchase cancellation charge, was $83.8 million.

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A summary of Tampa Electric’s operating statistics for the three months and nine months ended Sept. 30, 2003 and 2002 follows:

	Operating Revenues								Kilowatt-hour sales
(in millions, except average customers)	2003			2002			% Change		2003	2002	% Change
Three months ended Sept. 30,
Residential	$	227.5		$	215.9		5.4		2,452.2	2,329.4	5.3
Commercial		128.5			123.7		3.9		1,639.7	1,582.7	3.6
Industrial – Phosphate		16.1			17.7		(9.0	)	293.6	335.2	(12.4	)
Industrial – Other		24.1			21.6		11.6		344.7	319.4	7.9
Other sales of electricity		33.3			30.8		8.1		412.5	382.0	8.0
Deferred and other revenues		(2.9	)		1.8		(261.1	)	—	—	—
		426.6			411.5		(3.7	)	5,142.7	4,948.7	3.9
Sales for resale		10.3			17.8		(42.1	)	168.4	290.4	(42.0	)
Other operating revenue		19.3			9.8		96.9		—	—	—
	$	456.2		$	439.1		3.9		5,311.1	5,239.1	1.4
Average customers (thousands)		605.4			590.5		2.5		—	—	—
Retail output to line (kilowatt hours)									5,422.5	5,353.7	1.3
Nine months ended Sept. 30,
Residential	$	587.3		$	572.1		2.7		6,359.6	6,113.0	4.0
Commercial		344.2			346.0		(0.5	)	4,402.4	4,393.5	0.2
Industrial—Phosphate		49.1			55.4		(11.4	)	958.0	1,028.8	(6.9	)
Industrial – Other		66.3			62.4		6.3		975.1	921.8	5.8
Other sales of electricity		91.9			86.6		6.1		1,134.3	1,058.1	7.2
Deferred and other revenues		(1.7	)		(8.0	)	(78.7	)	—	—	—
		1,137.1			1,114.5		2.0		13,829.4	13,515.2	2.3
Sales for resale		32.8			49.8		(34.2	)	554.7	777.2	(28.6	)
Other operating revenue		36.1			33.8		6.8		—	—	—
	$	1,206.0		$	1,198.1		0.7		14,384.1	14,292.4	0.6
Average customers (thousands)		603.1			588.7		2.4		—	—	—
Retail output to line (kilowatt hours)									14,713.2	14,420.5	2.0

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

Peoples Gas System reported net income of $2.9 million for the quarter, compared with $3.1 million recorded in the same period in 2002. Quarterly results reflected customer growth of more than 5 percent, offset by a $1.1-million after-tax restructuring charge ($1.7 million pretax) 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.

Year-to-date net income was $19.6 million, compared with $17.3 million for the same period in 2002. Customer growth of approximately 5 percent, favorable winter weather in the first quarter and a base rate increase effective in January 2003 contributed to these results. Volumes were lower for the lower-margin transportation service for interruptible customers and electric power generators primarily due to higher gas prices.

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A summary of PGS’ operating statistics for the three months and nine months ended Sept. 30, 2003 and 2002 follows:

	Operating revenues						Therms
(in millions, except average customers)	2003		2002		% Change		2003	2002	% Change
Three months ended Sept. 30,
By Customer Segment:
Residential	$	18.5	$	14.1	31.2		9.1	8.8	3.4
Commercial		29.9		26.2	14.1		77.8	72.0	8.0
Industrial		2.3		2.8	(17.9	)	49.3	55.2	(10.7	)
Off system sales		42.3		22.4	88.8		76.4	59.2	29.1
Power generation		2.5		2.9	(13.8	)	108.1	138.8	(22.1	)
Other revenues		7.7		6.0	28.3		—	—	—
	$	103.2	$	74.4	38.7		320.7	334.0	(4.0	)
By Sales Type:
System supply	$	78.1	$	50.6	54.4		103.1	86.2	19.6
Transportation		17.4		17.8	(2.3	)	217.6	247.8	(12.2	)
Other revenue		7.7		6.0	28.3		—	—	—
	$	103.2	$	74.4	38.7		320.7	334.0	(4.0	)
Average customers (thousands)		291.2		276.4	5.4		—	—	—
Nine months ended Sept. 30,
By Customer Segment:
Residential	$	80.2	$	54.8	46.4		49.4	44.2	11.8
Commercial		109.3		90.5	20.8		264.2	244.4	8.1
Industrial		7.8		9.3	(16.1	)	163.4	187.1	(12.7	)
Off system sales		93.6		53.4	75.3		158.2	145.1	9.0
Power generation		7.6		8.8	(13.6	)	285.8	391.8	(27.1	)
Other revenues		26.4		20.3	30.0		—	—	—
	$	324.9	$	237.1	37.0		921.0	1,012.6	(9.0	)
By Sales Type:
System supply	$	242.0	$	160.3	51.0		273.6	262.0	4.4
Transportation		56.5		56.5	—		647.4	750.6	(13.7	)
Other revenue		26.4		20.3	30.0		—	—	—
	$	324.9	$	237.1	37.0		921.0	1,012.6	(9.0	)
Average customers (thousands)		290.7		276.3	5.2		—	—	—

Unregulated Companies – Operating Results

TECO Power Services (TPS)

TECO Power Services’ (TPS) loss for the third quarter was $62.2 million, compared with net income of $23.4 million for the same period in 2002. Included in these results were continued strong earnings at the Guatemalan operations, offset by a $25.9-million after-tax charge associated with the recognition of a reserve for an arbitration award against TMDP, the indirect owner of the Commonwealth Chesapeake Power Station, significant losses from the Union and Gila River stations, both of which were in full commercial operation at the end of the quarter and therefore incurred significant incremental depreciation and interest expense, and the end of interest payments on the loan to Panda related to the TIE projects and the notes receivable from TECO—Panda Generating Company (TPGC). Third quarter results in 2002 included a $6.0-million after-tax benefit related to a settlement agreement with ERCOT and higher earnings from a reliability-must-run contract on the Frontera Station in Texas. Interest expense allocated to TPS was $18.5 million for the quarter, compared to $6.0 million in the third quarter of 2002. Interest expense also increased due to lower capitalized interest, including the recognition of interest expense on the suspended Dell and McAdams power stations.

The third quarter loss for the Union and Gila River power stations was $26.1 million. Actual spark spreads from commercial operations realized for Union and Gila River were $8.75 / MWh and $16.58 / MWh, respectively. These actual spark spreads reflect the fact that the non-contract sales are being made in the lower-margin non-firm spot market rather than the firm market. The plants operated at capacity factors of 39 percent for Union and 45 percent for Gila River in the quarter. (The spark spread, a non-GAAP measure, reflects the relative profitability of converting natural gas into electricity, but does not include the cost of transmission service, gas transportation service and other services. The capacity factor is a relative indication of actual generation compared to a theoretical maximum sustainable generation.) There was significant performance and warranty testing required at the Union Station through July and at the Gila River Station through August, which reduced the amount of energy available for commercial sale.

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TPS’ year-to-date loss was $266.3 million compared with net income of $32.7 million for the same period in 2002. The year-to-date results included the third quarter $25.9-million after-tax charge associated with the recognition of a reserve for an arbitration award against TMDP, the $155.9 million of charges recorded in the second quarter related to the Panda partnership termination and resulting consolidation of Panda Energy’s interest in the Union and Gila River power stations and the goodwill impairments required under FAS 142,Goodwill and Other Intangible Assets, for the Frontera and Commonwealth Chesapeake power stations, and the $15.3-million charge recorded in the first quarter related to turbine purchase cancellations.

TECO Transport

TECO Transport recorded net income of $2.6 million in the third quarter compared with $4.7 million for the same period last year. These results reflect lower Tampa Electric volumes as a result of the Bayside repowering, as well as higher fuel and repair costs.

Year-to-date net income was $11.6 million, compared to $15.8 million for the same period in 2002. The 2003 results included a $0.8-million after-tax charge due to the adoption of FAS 143. Year-to-date results were driven by the same factors as in the third quarter, weak pricing and lower northbound river shipments, and a $1.5-million after-tax gain on the disposition of oceangoing equipment no longer used by the TECO Ocean Shipping subsidiary.

TECO Coal

TECO Coal achieved third quarter net income of $18.4 million, compared to $21.7 million reported in the same period in 2002. Results for the quarter were driven primarily by lower volumes and lower prices for conventional metallurgical and steam coals, which were partially offset by higher volumes of synthetic fuel. These results also reflect the effect of the sale of the 49 percent interest in the synfuel facilities to a third party.

Year-to-date net income was $64.6 million, compared with $58.8 million reported in 2002. The 2003 results included a $0.3-million after-tax charge due to the adoption of FAS 143. Results were driven primarily by lower volumes and prices for conventional metallurgical and steam coals and slightly higher mining costs due to the use of marginal coals for the production of synfuel, more than offset by higher volumes of synthetic fuel and the sale of a 49 percent interest in the synfuel production facilities.

For segment reporting, the deferral of tax credits discussed below underOther Charges Affecting Net Income is reported in the “Parent/other” line item for the quarter and year-to-date results.

Other Unregulated Companies

TECO Energy’s other unregulated companies essentially broke even for the third quarter, compared to a loss of $1.0 million for the same period in 2002. The year-to-date loss was $1.0 million, compared with net income of $3.6 million for the same period in 2002.

Discontinued Operations

On Sept. 30, 2003, TPS sold Hardee Power Partners for net proceeds of $107.7 million, and recorded a $34.5 million after-tax gain ($56.2 million pretax) on the sale. All periods presented reflect the reclassification of results for Hardee Power Partners (previously owned by TPS) to discontinued operations.

In addition to the Hardee Power Partners results, year-to-date income from discontinued operations of $66.7 million included $23.1 million recorded in the first quarter, primarily reflecting 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

Results for the quarter included $6.8 million in after-tax costs ($11.0 million pre-tax) from the corporate restructuring announced Sept. 2, 2003; a $25.9 million after-tax charge ($40.7 million pre-tax) associated with the recognition of a reserve for an arbitration award against a TECO Power Services subsidiary, TMDP, related to its indirect ownership interest of the Commonwealth Chesapeake Power Stations, a $3.2 million after-tax charge for the cumulative effect of an accounting change to reflect the implementation of FAS 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity; and a $34.5 million after-tax gain ($56.2 million pre-tax) on the sale of Hardee Power Partners discussed above.

In addition to the third quarter charges discussed above, year-to-date results also included $94.7 million of after-tax accounting charges ($153.9 million pretax) related to the Panda partnership termination and resulting consolidation of Panda Energy’s interest in the Union and Gila River power stations in the second quarter; $61.2 million of after-tax goodwill impairments ($95.2 million pretax) required under FAS 142,Goodwill and Other Intangible Assets, for the Frontera and Commonwealth Chesapeake power stations in the second quarter; a $64.2 million after-tax write-off ($104.5 million pretax) in the first quarter related to turbine purchase cancellations; a $1.1 million after-tax charge for the cumulative effect of an accounting

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change to reflect the adoption of FAS 143,Accounting for Asset Retirement Obligations; and a $23.1 million after-tax gain ($34.7 million pretax) from discontinued operations, primarily from the completion of the sale of TECO Coalbed Methane in the first quarter as discussed above.

SeeNotes 4 and12 to theTECO Energy Consolidated Financial Statements for additional details related to these charges.

Results for the quarter and year-to-date also included the deferral of recognition of $18.0 million and $28.5 million, respectively, of tax credits related to the production of synthetic fuel at TECO Coal, and are discussed in more detail below in theIncome Taxes section.

Other Income (Expense)

Other income (expense) for the three months and nine months ended Sept. 30, 2003 was expense of $20.8 million and expense of $119.3 million, respectively, compared to income of $21.1 million and $59.6 million, respectively, for the same periods in 2002. In addition to the $32.0 million pretax charge ($20.0 million after-tax) recorded in the third quarter of 2003 for the TMDP arbitration reserve, the nine months ended Sept. 30, 2003 also included the second quarter $153.9 million pretax expense ($94.7 million after-tax) recorded for the loss on the joint venture termination as discussed above.

Equity AFUDC at Tampa Electric, which is included in Other income, was $3.9 million and $15.6 million, respectively, for the three months and nine months ended Sept. 30, 2003, and $6.9 million and $16.9 million, respectively, for the same periods in 2002. AFUDC has decreased, reflecting the commercial operation of Bayside Unit 1 in April 2003.

Interest Charges

Total interest charges for the three months and nine months ended Sept. 30, 2003 were $109.5 million and $256.3 million, respectively, compared with $40.2 million and $124.2 million for the same periods last year. Interest expense increased due to no longer capitalizing interest on the non-recourse debt for the Union and Gila River power stations, no longer capitalizing interest on the Dell and McAdams power stations where construction was suspended 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.

Results for the quarter and year-to-date periods include interim tax credit deferrals of $18.0 million and $28.5 million, respectively. The tax credit deferrals are primarily due to uncertainties related to Section 29 tax credits from the production of synfuel at TECO Coal. The amount of tax credits generated for the company’s use was significantly more in the first and third quarters than in the second quarter. One uncertainty was related to the issuance of a PLR reflecting the new ownership structure, which had been delayed due to the IRS’ suspension of the issuance of PLRs while it resolved taxpayer positions related to chemical change. The deferral of these tax credits is included in the “Parent/other” line for segment reporting purposes. TECO Coal received a PLR from the IRS on Oct. 31, 2003. Accordingly, the deferred tax credits are expected to be reversed and recorded in net income during the fourth quarter of 2003.

The provision for income taxes as a percent of income from unusual and infrequently occurring items for the three months and nine months ended Sept. 30, 2003 were 106.5% and (4.6)%, respectively. For the three and nine months ended Sept. 30, 2003, net income from discontinued operations was $37.4 million and $66.7 million, respectively, and the provision for income taxes as a percent of income from discontinued operations was 38.6% and 38.9%, respectively.

The income tax effect of gains and losses from the discontinued operations of TECO Coalbed Methane and Hardee Power Partners (previously owned by TPS) are shown as a component of results from discontinued operations.

Subsequent Events

Affiliate Transaction – TECO Transport Contract

In October, 2003, Tampa Electric Company signed a five-year contract renewal with an affiliate company, TECO Transport Corporation, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008. The contract was signed at the conclusion of a bid process conducted by Tampa Electric and a detailed market rate analysis by an outside expert consultant to determine current transportation market prices. The new contract includes rates that are slightly lower than those currently charged and are expected to result in savings to Tampa Electric’s retail customers.

The costs associated with this fuel transportation contract are expected to be reviewed by the Florida Public Service Commission (FPSC) in the first quarter of 2004. The review is expected to focus on the request for proposal process employed by Tampa Electric, the rates under the contract and the appropriateness of the existing FPSC benchmark methodology to measure actual market transportation rates on a going-forward basis.

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Restructuring Costs

On Oct. 7, 2003, TECO Energy announced phase two of the corporate reorganization discussed inNote 11. As a result of this phase of the restructuring, the company took additional steps towards re-alignment to provide for centralized oversight according to functional lines for power plant operations, energy delivery, energy management, human resources and technology/support services. This phase included the involuntary termination or retirement of 207 employees, including personnel from power plant operations, bulk terminal operations, office staff and support services. The company will recognize an expense in the fourth quarter of approximately $11.2 million for accrued benefits including severance and other termination and retirement benefits. The table below details the expense to be recognized by the operating segments in the fourth quarter.

(millions)	Tampa Electric		Peoples Gas		TPS		TECO Transport		TECO Coal		Other Unregulated		Eliminations & Other		TECO Energy
Termination and retirement benefit expense	$	6.1	$	2.0	$	0.7	$	1.6	$	—	$	0.5	$	0.3	$	11.2

The company expects to complete the restructuring activities of the second phase by the end of 2003.

Agreement to Sell TECO Propane Ventures’ Indirect Interest in Heritage Propane Partners, LP

On Nov. 7, 2003, the company announced an agreement by TECO Propane Ventures, LLC, a wholly owned subsidiary of TECO Energy, along with affiliates of Atmos Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources, Inc., to: (1) sell the general partnership interest in Heritage Propane Partners, LP (“Heritage’) that is currently owned by US Propane LP; and to (2) sell US Propane’s ownership of Heritage Holdings, Inc. which owns limited partnership interests in Heritage. TECO Energy’s portion of the sale is anticipated to generate approximately $50 million of cash proceeds and a pretax book gain of approximately $18 million. The closing of this transaction is conditioned upon financing and regulatory approvals, which are expected before the end of the year.

Liquidity, Capital Resources

Available Cash and Liquidity

At Sept. 30, 2003, TECO Energy had cash and cash equivalents of $409.2 million, excluding all restricted cash, reflecting a net increase of $141.2 million in the third quarter, and a $1.9 million decrease for the year-to-date period. The cash balance does not reflect the proceeds from the sale of Hardee Power Partners which were received in early October. The third quarter increase was driven primarily by the issuance of common stock and changes in working capital accounts at TPGC, which more than offset dividend payments of $33.6 million and capital expenditures of $149.8 million. The year-to-date results reflect the repayment of the $375 million equity bridge loan at TPS in the second quarter; repayment of $75 million of first mortgage bonds at Tampa Electric and a $25 million capital lease at TECO Transport; and dividend payments of $130 million; partially offset by the $129 million equity issuance, the $300 million of notes issued at TECO Energy and $250 million of notes issued at Tampa Electric.

In addition, at Sept. 30, 2003, availability under bank credit facilities totaled $674 million, net of letters of credit of $116 million outstanding under these facilities. The availability under the bank credit facilities included $290 million of the Tampa Electric Company’s $300 million facility; TECO Energy’s $150 million undrawn Merrill Lynch facility; and the $350 million TECO Energy multi-year facility, undrawn except for $116 million of letters of credit. Total liquidity, cash plus credit facilities, totaled $1.1 billion, including $347 million at Tampa Electric, at the end of the third quarter.

As discussed under theCovenants in Financing Agreements section below, andNotes 7,8 and19 to theTECO Energy Consolidated Financial Statements, TECO Energy reclassified the non-recourse debt of $1.4 billion at the Union and Gila River projects from long-term to current. Due to the non-recourse nature of this debt, this reclassification does not have any measurable or significant impact on the liquidity of the company.

Estimated cash needs for the remainder of 2003 include the November maturity of TECO Energy’s $350 million one-year term loan, and net capital spending of $40 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 theBank Credit Facilitiesand Covenants in Financing Agreements sections). Based on its cash flow forecasts, TECO Energy expects to have at least $700 million of cash and capacity under the bank credit facilities at the end of 2003.

Restricted Cash

Restricted cash at Sept. 30, 2003 is comprised of $68 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 $46 million at TPS, primarily related to cash to be used for construction-related purposes at the Union and Gila River power stations.

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On Nov. 5, 2003, $59 million of the amount escrowed at Sept. 30, 2003 was released upon delivery of the required PLR. 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 was contingent upon receipt of a positive response to a PLR request, and the proceeds from this transaction were held in escrow pending resolution of this contingency. Through Sept. 30, 2003, $68 million of the proceeds were escrowed pending receipt of the PLR. On Oct. 31, 2003 TECO Coal received a PLR confirming the revised ownership structure, location of facilities and other terms of the two previous PLRs.

Cash Flows

Year-to-date cash flow from operations reflects 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, and the under recovery of fuel costs at Tampa Electric. In addition, cash from operations is reduced by income taxes associated with gains on assets sold, although the proceeds from those asset sales are classified as cash from investing activities.

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 approximately $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. 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 were included in restricted cash at Sept. 30, 2003 as a PLR reflecting the revised ownership structure had not been received as of that date.

The $250 million early repayment of the equity bridge loan related to the Union and Gila power projects that was required in April due to the downgrade of TECO Energy’s credit ratings to non-investment grade by Moody’s and the scheduled $125 million payment in April are reflected in repayment of long-term debt under financing activities. 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 River power projects, reflect amounts drawn to fund project construction since the April 1, 2003 consolidation for accounting purposes.

On Sept. 10, 2003 TECO Energy sold 11 million shares of common stock to funds managed by Franklin Advisers, Inc. of San Mateo, California at a price of $11.76 per share. Net proceeds of about $129 million will be used to repay short-term indebtedness and general corporate purposes.

TECO Energy has identified in thisManagement’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. Although TPS’ net loss this year to date 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.

Other

TECO Energy sold its Enron bankruptcy claims for approximately 15.5 cents on the dollar which amounted to a recovery of about $42 million. There was 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 was received in July 2003. 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.

As a result of TPS having received Panda’s interest in TPGC and the resulting consolidation, Panda owed 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 held a 50-percent interest in the Texas Independent Energy (TIE) projects, Odessa and Guadalupe. In September 2003, the company consummated foreclosure on Panda Energy’s interest in PLC for a default under a $23 million note receivable resulting in TPS’ 100-percent ownership in PLC which owns 50-percent of TIE (seeNotes 1,12 and16 to theTECO Energy Consolidated Financial Statements). As of Sept. 30, 2003, TPS consolidated PLC resulting in a net increase in investment in unconsolidated affiliates of approximately $18 million and recognition of an unrealized after-tax loss of approximately $5 million in OCI related to interest rate swaps designated as cash flow hedges and held at TIE.

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In the second and third quarters of 2003, Tampa Electric returned to TECO Energy a total of $158 million of capital which was previously contributed by TECO Energy to support Tampa Electric’s construction program.

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.

As a result of downgrades to TECO Energy’s credit ratings in the second quarter of 2003, 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. SeeNote 19to 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 Sept. 30, 2003, the maximum collateral obligation, if all counterparties exercised their full rights, would be approximately $24 million. The collateral obligation, if the most probable rights were exercised, would be approximately $19 million (including actual collateral posted of $17 million).

Bank Credit Facilities

At Sept. 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 Sept. 30, 2003, $10 million was drawn on the Tampa Electric credit facility and the TECO Energy credit facility was undrawn excluding letter of credit usage. In November 2002, TECO Energy converted another $350 million bank credit line then in effect into a one-year term loan due November 2003. On Nov. 13, TECO Energy repaid the $350 million bank term loan maturing on that date. On Nov. 7, Tampa Electric Company replaced its maturing $300 million bank facility with a $250 million facility. (See theCovenants in Financing Agreementssection for a description of the financial covenants contained in these facilities.)

The TECO Energy bank credit facility maturing November 2004 includes a $250 million sub-limit for letters of credit. At Sept. 30, 2003, $115.6 million of letters of credit were outstanding against that facility, including $66 million related to the construction of the Union and Gila River power stations. These letters of credit of $20 million and $46 million for Union and Gila River, respectively, will decline to $4 million for each station when final acceptance is achieved, which is projected to occur in December.

The Tampa Electric Company bank credit facility requires commitment fees of 20 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.

On April 9, 2003, TECO Energy entered into a $350 million unsecured credit facility with Merrill Lynch that would have been available if required to refinance the one-year term loan maturing in November 2003. In addition, $150 million of the facility was available for general corporate purposes until November 2003. The credit facility was previously required to be drawn by Nov. 13, 2003 in order to maintain the capacity under the facility, and if drawn in November 2003 would have expired in October 2004. The size of this $350 million facility was reduced by certain asset sales and financings, and as of Oct. 24, 2003, was reduced to $210 million. On Nov. 12, 2003, TECO Energy and Merrill Lynch amended this credit facility, reducing the commitment to $100 million of undrawn line capacity through Apr. 8, 2004, at which time the facility can be drawn up to $100 million and remain outstanding to Oct. 8, 2004. This facility, if drawn, could limit the payment of dividends as discussed below inCovenants in Financing Agreementsand was undrawn at the time of the amendment .

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.

Credit Ratings/Senior Unsecured Debt

On Nov. 5, 2003, Standard and Poor’s (S&P) removed the Credit Watch and affirmed the existing ratings on TECO Energy and Tampa Electric Company, leaving the outlook Negative. S&P indicated in support of its continued Negative Outlook that it had remaining concerns about the ultimate resolution of TECO Energy’s merchant exposure, management’s commitment to a redefined business strategy, and elevated debt balances. S&P further indicated that a return to ratings stability is directly correlated to a swift exit from merchant activity and a prudent use of free cash flow to reduce indebtedness.

Because S&P bases its ratings on the consolidated corporate entity, any future action would 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 an event.

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

Senior Unsecured Credit Ratings as of Nov. 5, 2003

	Fitch		Moody’s		Standard & Poor’s
Tampa Electric Company	BBB+	(1)	Baa1	(1)	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 earnings before interest, taxes, depreciation and amortization (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 Sept. 30, 2003, Tampa Electric Company’s debt-to-capital ratio was 48.8%, and interest coverage was 6.2 times. On Nov. 7, Tampa Electric replaced its maturing $300 million bank facility with a $250 million facility. The new facility includes a new covenant limiting cumulative distributions and outstanding loans to its parent to an amount representing an accumulation of net income after May 31, 2003, and capital contributions from the parent after Oct. 31, 2003, plus $450 million.

Various agreements with the Union and Gila River project debt lenders relating to the completion of construction (“Construction Undertakings”) 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. Should either ratio 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. At Sept. 30, 2003, TECO Energy’s debt-to-total capital ratio was 56.3%.

TECO Energy and the Union and Gila River project companies have entered into a Suspension Agreement with the lending group for the Union and Gila River projects to suspend until Feb. 1, 2004 the quarterly calculation of the 3.0 times EBITDA to interest coverage ratio covenant in these agreements. The Suspension Agreement contemplates discussions among TECO Energy, the Union and Gila River project companies and the lending group to reach an understanding regarding the projects’ operating budgets and performance before expiration of the suspension period on Jan. 31, 2004 promptly after which the Sept. 30 and Dec. 31, 2003 quarterly calculations would be made. In the absence of an understanding, the lenders could seek to accelerate the non-recourse project debt starting as early as Feb. 1, 2004 for non-compliance with the EBITDA to interest covenant requirements for the quarters ended Sept. 30 or Dec. 31, 2003, and thus the consolidated $1.395 billion non-recourse debt is now reflected as current. The non-recourse project debt is not an obligation of TECO Energy, but actions by the lenders could adversely affect its equity investment in the projects, which is currently carried on its books at $1.1 billion. The Suspension Agreement and contemplated discussions, continuing changes in external factors, and the future performance of individual assets, may cause management to reconsider or adjust the assumptions and expectations in the future for the purposes of an asset impairment test.

The Construction Undertakings permit TECO Energy to terminate its obligations thereunder, including the requirement to comply with the covenants, by providing a Substitute Guarantor reasonably satisfactory to the lending group. On September 22, 2003, TECO Energy tendered a Substitute Guarantor, which it believes satisfied the requirements of the Construction Undertakings. TECO Energy’s tender also included continued maintenance of the letters of credit described below. The lending group declined to accept this tender as being satisfactory. TECO Energy disagrees with the basis of their declining to accept the Substitute Guarantor. If the suspension period ends without TECO Energy and the lending group agreeing to an alternative arrangement, TECO Energy would plan to assert that the Construction Undertakings were terminated in the event that the lending group sought to exercise its rights thereunder based on a violation of the EBITDA to interest coverage ratio covenant. As part of the Suspension Agreement, both TECO Energy and the lending group have agreed not to assert their respective positions during the suspension period.

The ratings downgrade by Moody’s in April 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.

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Subsequent to that posting, the outstanding letters of credit under these agreements were reduced with the commercial operation of the units. As of Sept. 30, 2003, the outstanding letters of credit under these agreements totaled $66 million. The amounts outstanding are expected to be reduced to $8 million following the final acceptance of the units which is expected in December 2003.

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 Sept. 30, 2003, $310 million was accumulated and available for future restricted payments, representing three 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 Sept. 30, 2003 this limitation would apply to certain liens exceeding $182 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 Sept. 30, 2003, the company’s EBITDA to interest coverage for the immediate preceding four quarters was 2.8 times.

The Merrill Lynch facility contains covenants that, if the facility is drawn upon, (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.

TECO Energy’s $37.5 million credit facility, maturing in 2004, has covenants similar to those of the other TECO Energy credit facilities but also includes an 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. At Sept. 30, 2003, EBITDA to interest coverage was 2.8 times.

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.

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 changed the classification and measurement of certain financial instruments. Accordingly, the company preferred securities are now included in the liabilities section of the balance sheet. This change did not impact the calculation of previously discussed significant financial covenants, as these are calculated in accordance with the terms defined in the relevant agreements. SeeNote 21 to theTECO Energy Consolidated Financial Statements for a discussion of the accounting guidance included in FAS 150.

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 Sept. 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 are at risk if those projects default on their non-recourse loans.

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. (SeeNote 21 to theTECO Energy Consolidated Financial Statements.)

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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.

SeeNote 1to 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 theLong-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 theGoodwill 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. (SeeNotes 1, 4, 10, 12and 20 to theTECO EnergyConsolidated Financial Statements.)

Long-Lived Assets

Effective Jan. 1, 2002, TECO Energy and its subsidiaries adopted FAS 144,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 indicators of other than temporary impairment exist. As discussed inNote 10, indicators of impairment existed for certain long-term turbine purchase contracts and merchant power plants, triggering a requirement to test for an impairment of these 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. In the second quarter of 2003, a $61.2 million after-tax (95.2 million pretax) impairment charge was recorded to write off all goodwill associated with the Frontera and Commonwealth Chesapeake power stations. (SeeNote 4 to theTECO 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

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under an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are 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. In connection with the adoption of the guidance on 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. (SeeNote 6 to theTECO EnergyConsolidated 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.

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 theDisclosures 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. (SeeNote 2 to theTECO EnergyConsolidated 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 Sept. 30, 2003, TECO Energy had deferred income tax assets of $507 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. (SeeNote 13to theTECO EnergyConsolidated Financial Statements.)

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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 ocean equipment improvements 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. (SeeNote 1to theTECO 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 4.0% and 4.2% for the nine months ended Sept. 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. (SeeNote 1 to theTECO EnergyConsolidated Financial Statements.)

Regulatory Accounting

Tampa Electric’s and PGS’ retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the 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. (SeeNotes 1and 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.

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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. (SeeNote 1 to theTECO 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. (SeeNote 21 to theTECO 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 Sept. 30, 2003, there was no significant change in the company’s exposure to interest rate risk since Dec. 31, 2002.

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 Sept. 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	$	30.9	$	—	$	30.9	2	$	14.0
Split rating		15.0		—		15.0	1		15.0
Non-investment grade		2.1		0.6		1.5	—		—
No external ratings (internally rated)
Investment grade		0.3		—		0.3	—		—
Non-investment grade		—		—		—	—		—
Total	$	48.3	$	0.6	$	47.7	3	$	29.0

(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.

(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 Sept. 30, 2003, the commodity risk exposure at the Regulated Utilities was not significantly different from that as of Dec. 31, 2002.

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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 Sept. 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 Sept. 30, 2003 and Dec. 31, 2002.

Sensitivity of the Fair Value of Merchant Energy Derivative Contracts

(millions)	Sept. 30, 2003			Dec. 31, 2002
Change in Fair Value due to a 10%: (1)
Decrease in natural gas prices	$	(5.0	)	$	(16.9	)
Increase in electricity prices		(6.8	)		(24.4	)
Increase in electricity and natural gas prices		(1.8	)		(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 quarter ended Sept. 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		(2.8	)
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		(14.4	)
Net fair value of energy derivatives as of Sept. 30, 2003	$	(8.8	)

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		4.3
Recorded in earnings		(24.9	)
Net option premium payments		10.2
Net purchase (sale) of existing contracts		(6.8	)
Net fair value of energy derivatives as of Sept. 30, 2003	$	(8.8	)

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.

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

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

Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value (millions)
Actively quoted prices	$	9.3		$	4.1		$	13.4
Other external sources (1)		(17.6	)		(2.4	)		(20.0	)
Model prices (2)		—			(2.2	)		(2.2	)
Total	$	(8.3	)	$	(0.5	)	$	(8.8	)

(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.

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Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See the discussion entitled “Disclosures about Market Risk” inItem 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.

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PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

In connection with the arbitration proceeding brought against a TECO Power Services 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 Dec. 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.

In September 2003, the panel reached a final award in which TMDP is obligated to acquire NCP’s voting and other rights, pay NCP interest on the deemed acquisition price from a pre-determined date, and pay NCP’s legal fees as prescribed under the final award. The forced acquisition creates an intangible asset of $4.9 million relating to specific contractual rights previously held by NCP and a loss of $32.0 million, representing the excess of the purchase price over the fair value of the interests acquired. TMDP is seeking to vacate the arbitration award in the U.S. District Court for the District of Columbia and has not yet paid the amount of the award. As of Sept. 30, 2003, the company recorded a contingent liability of $45.5 million reflecting the maximum payment obligation under the final award. Of the $45.5 million recorded, $8.6 million was expensed, $4.9 million was recognized as an intangible asset to be amortized over 20 years, and $32.0 million was expensed to establish a reserve, reflecting the maximum payment obligation under the final award.

In March 2001, TECO Power Services was served with a lawsuit filed in the Circuit Court for Hillsborough County by a Tampa-based firm called Grupo Interamerica, LLC. (“Grupo”) in connection with a potential investment in a power project in Colombia in 1996. Grupo alleges, among other things, that TPS breached an oral contract with Grupo that would have allowed Grupo to acquire up to a 20-percent interest of the Colombian wholesale generation project when TPS declined to invest in such project. Grupo is seeking damages equal to the net present value of the value of 20-percent of the project over its life. TPS disputes the allegations and denies liability since any understanding made investment in the project subject to TECO Energy Board approval which was not obtained.

Two lawsuits have been filed in the Circuit Court in Hillsborough County against Tampa Electric, in connection with the location of transmission structures in certain residential areas, by residents in the areas surrounding the structures. The high-voltage power lines are needed by Tampa Electric to move electricity to the northwest part of its service territory where population growth has been experienced. The residents are seeking to remove the poles or to receive monetary damages. Tampa Electric is working with the community to determine the feasibility of alternate routes or structures or some combination.

See the discussion of environmental matters inNotes5 and19 to theTECO Energy Consolidated Financial Statements andNotes 3 and13 to theTampa Electric Company Consolidated Financial Statements.

Item 6.EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits—See index on page 74.

(b) Reports on Form 8-K

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

1. 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. 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.

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3. Current Report on Form 8-K dated Aug.26, 2003, under “Item 5.Other Events”, announcing that TECO Power Services, Inc. had signed an agreement to sell its interest in the Hardee Power Station.

4. Current Report on Form 8-K/A dated Aug. 27, 2003, under “Item 5.Other Events”, and “Item 7.Financial Statements, Pro forma Financial Statements and Exhibits”, amending the previously filed Current Report on Form 8-K, dated June 26, 2003, by providing additional details regarding interest acquired and indicating that additional information was not required pursuant to Items 7(a) and (b).

5. Current Report on Form 8-K dated Sept. 2, 2003, under “Item 5.Other Events”, and “Item 7.Financial Statements, Pro Forma Financial Statements and Exhibits”, announcing a corporate reorganization for TECO Energy, Inc.

6. Current Report on Form 8-K dated Sept. 10, 2003, under “Item 5.Other Events”, and “Item 7.Financial Statements, Pro Forma Financial Statements and Exhibits”, reporting that TECO Energy, Inc. had entered into a Stock Purchase Agreement to sell 11,000,000 shares of its common stock, and 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).

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

1. Current Report on Form 8-K dated Oct. 23, 2003, under “Item 5.Other Event”, and “Item 12.Results of Operations and Financial Condition”, furnishing TECO Energy, Inc.’s financial results for the quarter ended Sept. 30, 2003.

2. Current Report on Form 8-K dated Oct. 23, 2003, under “Item 12.Results of Operations and Financial Condition”, furnishing additional unaudited information about TECO Energy, Inc.’s financial results for the quarter ended Sept. 30, 2003.

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

1. Current Report on Form 8-K dated Sept. 2, 2003, under “Item 5.Other Events”, and “Item 7.Financial Statements, Pro Forma Financial Statements and Exhibits”, announcing a corporate reorganization for TECO Energy, Inc.

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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 November, 2003.

TECO ENERGY, INC.

(Registrant)

Date: November 13, 2003	By: /s/ G. L. GILLETTE
	G. L. GILLETTE Senior Vice President—Finance and Chief Financial Officer (Principal Financial Officer)

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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 November, 2003.

TAMPA ELECTRIC COMPANY

(Registrant)

Date: November 13, 2003	By:	/s/ G. L. GILLETTE
		G. L. GILLETTE Senior Vice President—Finance and Chief Financial Officer (Principal Financial Officer)

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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).	*
10.1	Suspension of Rights and Amendment Agreement dated Oct. 22, 2003, by and among Union Power Partners, L.P., and Panda Gila River, L.P., as Borrowers, TECO Energy, Inc., Societe Generale, as LC Bank, and Citibank, NA, as Administrative Agent.	[	]
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.

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