TECO Energy 10-Q 2008 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 ended September 30, 2008

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.	59-2052286
	(a Florida corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-1111
1-5007	TAMPA ELECTRIC COMPANY	59-0475140
	(a Florida corporation)
	TECO Plaza
	702 N. Franklin Street
	Tampa, Florida 33602
	(813) 228-1111

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

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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

YES  x    NO  ¨

Indicate by check mark whether TECO Energy, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

Indicate by check mark whether Tampa Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x    Smaller reporting company  ¨

Indicate by check mark whether TECO Energy, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES  ¨    NO  x

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES  ¨    NO  x

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Oct. 27, 2008 was 212,783,006. As of Oct. 27, 2008, 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 60

Index to Exhibits appears on page 60.

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sep. 30, 2008 and Dec. 31, 2007, and the results of their operations and cash flows for the periods ended Sep. 30, 2008 and 2007. The results of operations for the three month and nine month periods ended Sep. 30, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008. References should be made to the explanatory notes affecting the consolidated financial statements contained in Amendment No. 1 to TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2007 and to the notes on pages 9 through 27 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2008 and Dec. 31, 2007	3-4
Consolidated Condensed Statements of Income for the three month and nine month periods ended Sep. 30, 2008 and 2007	5-6
Consolidated Condensed Statements of Comprehensive Income for the three month and nine month periods ended Sep. 30, 2008 and 2007	7
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2008 and 2007	8
Notes to Consolidated Condensed Financial Statements	9-27

2

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions, except for share amounts)	Sep. 30, 2008			Dec. 31, 2007
Current assets
Cash and cash equivalents	$	92.5		$	162.6
Restricted cash		7.5			7.4
Short-term investments		2.4			—
Receivables, less allowance for uncollectibles of $4.7 and $3.3 at Sep. 30, 2008 and Dec. 31, 2007, respectively		340.5			295.9
Crude oil options receivable, net		—			78.5
Inventories, at average cost
Fuel		92.5			85.8
Materials and supplies		70.7			68.2
Current regulatory assets		223.3			67.4
Current derivative assets		0.1			0.3
Prepayments and other current assets		26.2			23.0
Income tax receivables		0.3			0.7
Total current assets		856.0			789.8
Property, plant and equipment
Utility plant in service
Electric		5,489.1			5,275.2
Gas		940.9			917.4
Construction work in progress		366.3			364.8
Other property		351.3			336.4
Property, plant and equipment		7,147.6			6,893.8
Accumulated depreciation		(2,064.4	)		(2,005.6	)
Total property, plant and equipment, net		5,083.2			4,888.2
Other assets
Deferred income taxes		355.2			424.9
Other investments		21.1			22.9
Long-term regulatory assets		190.8			186.8
Long-term derivative assets		0.1			1.9
Investment in unconsolidated affiliates		287.9			275.5
Goodwill		59.4			59.4
Deferred charges and other assets		121.4			115.8
Total other assets		1,035.9			1,087.2
Total assets	$	6,975.1		$	6,765.2

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

3

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions, except for share amounts)	Sep. 30, 2008			Dec. 31, 2007
Current liabilities
Long-term debt due within one year
Recourse	$	5.5		$	5.7
Non-recourse		1.4			1.4
Notes payable		13.0			25.0
Accounts payable		293.2			302.1
Customer deposits		144.2			138.1
Current regulatory liabilities		26.2			35.4
Current derivative liabilities		72.4			26.0
Interest accrued		80.1			32.7
Taxes accrued		56.4			33.2
Other current liabilities		15.3			18.0
Total current liabilities		707.7			617.6
Other liabilities
Investment tax credits		11.2			12.2
Long-term regulatory liabilities		592.8			582.7
Long-term derivative liabilities		10.8			0.1
Deferred credits and other liabilities		404.3			377.2
Long-term debt, less amount due within one year
Recourse		3,199.0			3,149.4
Non-recourse		7.6			9.0
Total other liabilities		4,225.7			4,130.6
Commitments and contingencies (seeNote 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 212.8 million shares and 210.9 million shares outstanding at Sep. 30, 2008 and Dec. 31, 2007, respectively)		212.8			210.9
Additional paid in capital		1,515.6			1,489.2
Retained earnings		348.5			334.1
Accumulated other comprehensive loss		(35.2	)		(17.2	)
Total capital		2,041.7			2,017.0
Total liabilities and capital	$	6,975.1		$	6,765.2

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

4

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Three months ended Sep. 30,
(millions, except per share amounts)	2008			2007
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $29.2 in 2008 and $30.8 in 2007)	$	782.1		$	791.9
Unregulated		144.0			198.1
Total revenues		926.1			990.0
Expenses
Regulated operations
Fuel		263.7			251.1
Purchased power		65.0			84.5
Cost of natural gas sold		134.9			99.2
Other		72.9			75.2
Operation other expense
Mining related costs		108.9			120.3
Waterborne transportation costs		—			55.0
Other		4.0			3.6
Maintenance		41.4			41.1
Depreciation and amortization		66.7			59.8
Taxes, other than income		52.1			53.6
Gain on sale, net of transaction related costs		—			4.9
Total expenses		809.6			848.3
Income from operations		116.5			141.7
Other income
Allowance for other funds used during construction		1.3			0.7
Other income		7.9			25.5
Income from equity investments		18.5			15.6
Total other income		27.7			41.8
Interest charges
Interest expense		57.9			64.2
Allowance for borrowed funds used during construction		(0.5	)		(0.3	)
Total interest charges		57.4			63.9
Income before provision for income taxes		86.8			119.6
Provision for income taxes		28.6			47.6
Income before minority interest		58.2			72.0
Minority interest		—			20.8
Net income	$	58.2		$	92.8
Average common shares outstanding– Basic		211.2			209.2
– Diluted		212.6			210.0
Earnings per share– Basic	$	0.28		$	0.44
– Diluted	$	0.27		$	0.44
Dividends paid per common share outstanding	$	0.20		$	0.195

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

5

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Nine months ended Sep. 30,
(millions, except per share amounts)	2008			2007
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $83.2 in 2008 and $84.8 in 2007)	$	2,152.3		$	2,120.0
Unregulated		452.7			557.8
Total revenues		2,605.0			2,677.8
Expenses
Regulated operations
Fuel		603.5			647.5
Purchased power		262.8			207.6
Cost of natural gas sold		387.7			299.4
Other		216.1			201.2
Operation other expense
Mining related costs		332.9			314.8
Waterborne transportation costs		—			164.0
Other		13.9			11.2
Maintenance		133.0			137.5
Depreciation		196.6			198.2
Taxes, other than income		161.1			167.4
Transaction related costs		0.9			21.2
Total expenses		2,308.5			2,370.0
Income from operations		296.5			307.8
Other income
Allowance for other funds used during construction		4.3			3.5
Other income		17.2			100.0
Income from equity investments		57.5			50.5
Total other income		79.0			154.0
Interest charges
Interest expense		172.7			198.1
Allowance for borrowed funds used during construction		(1.7	)		(1.4	)
Total interest charges		171.0			196.7
Income before provision for income taxes		204.5			265.1
Provision for income taxes		64.1			104.7
Income before minority interest		140.4			160.4
Minority interest		—			64.6
Income from continuing operations		140.4			225.0
Discontinued operations
Income tax benefit		—			(14.3	)
Total discontinued operations		—			14.3
Net income	$	140.4		$	239.3
Average common shares outstanding– Basic		210.4			208.9
– Diluted		211.7			209.8
Earnings per share from continuing operations – Basic	$	0.67		$	1.08
– Diluted	$	0.66		$	1.07
Earnings per share from discontinued operations – Basic	$	—		$	0.07
– Diluted	$	—		$	0.07
Earnings per share– Basic	$	0.67		$	1.15
– Diluted	$	0.66		$	1.14
Dividends paid per common share outstanding	$	0.595		$	0.580

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Sep. 30,						Nine months ended Sep. 30,
(millions)	2008			2007			2008			2007
Net income	$	58.2		$	92.8		$	140.4		$	239.3
Other comprehensive income (loss), net of tax
Net unrealized losses on cash flow hedges		(3.8	)		(3.3	)		(5.9	)		(0.8	)
Amortization of unrecognized benefit costs		0.3			0.7			0.6			1.8
Recognized benefit costs due to curtailment		—			—			—			4.1
Change in benefit obligations due to remeasurement		—			—			(10.8	)		(1.3	)
Unrealized loss on available-for-sale securities		(0.9	)		—			(1.9	)		—
Other comprehensive (loss) income, net of tax		(4.4	)		(2.6	)		(18.0	)		3.8
Comprehensive income	$	53.8		$	90.2		$	122.4		$	243.1

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sep. 30,
(millions)	2008			2007
Cash flows from operating activities
Net income	$	140.4		$	239.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		196.6			198.2
Deferred income taxes		69.5			90.6
Investment tax credits, net		(1.0	)		(1.9	)
Allowance for funds used during construction		(4.3	)		(3.5	)
Non-cash stock compensation		7.9			9.9
Gain on sale of business/assets, pretax		(1.4	)		(27.2	)
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		(25.3	)		(7.3	)
Minority interest		—			(64.6	)
Derivatives marked-to-market		—			(48.7	)
Deferred recovery clauses		(117.1	)		78.1
Receivables, less allowance for uncollectibles		(44.6	)		(81.5	)
Inventories		(9.2	)		(33.9	)
Prepayments and other current assets		(3.2	)		0.4
Taxes accrued		23.6			53.6
Interest accrued		47.4			32.3
Accounts payable		12.3			(42.1	)
Other		34.1			22.5
Cash flows from operating activities		325.7			414.2
Cash flows from investing activities
Capital expenditures		(402.5	)		(359.6	)
Allowance for funds used during construction		4.3			3.5
Net (settlement) proceeds from sale of business/assets		(3.7	)		60.8
Restricted cash		(0.1	)		(0.1	)
Distributions from unconsolidated affiliates		13.2			26.8
Other investments		76.2			(27.7	)
Cash flows used in investing activities		(312.6	)		(296.3	)
Cash flows from financing activities
Dividends		(126.1	)		(121.9	)
Proceeds from the sale of common stock		20.9			9.8
Proceeds from long-term debt		327.8			444.1
Repayment of long-term debt/Purchase in lieu of redemption		(293.8	)		(840.3	)
Minority interest		—			59.9
Net (decrease) increase in short-term debt		(12.0	)		25.0
Cash flows used in financing activities		(83.2	)		(423.4	)
Net decrease in cash and cash equivalents		(70.1	)		(305.5	)
Cash and cash equivalents at beginning of period		162.6			441.6
Cash and cash equivalents at end of period	$	92.5		$	136.1

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

8

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries, and the accounts of variable interest entities for which it is the primary beneficiary (TECO Energy or the company). All significant intercompany balances and intercompany transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy is not the primary beneficiary but we are able to exert significant influence. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sep. 30, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Sep. 30, 2008 and 2007. The results of operations for the three month and nine month periods ended Sep. 30, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates. The year-end condensed balance sheet data was derived from audited financial statements, however this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by GAAP in the United States of America.

Revenues

As of Sep. 30, 2008 and Dec. 31, 2007, unbilled revenues of $49.0 million and $46.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Cash Flows Related to Derivatives and Hedging Activities

The company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of heating oil swaps that are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operations section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are also typically included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows. For the year ended Dec. 31, 2007, crude oil options that protected the cash flows related to the sales of investor interests in the synthetic fuel production facilities were included in the investing section.

Other Income and Minority Interest

In 2007, TECO Energy earned a portion of its income indirectly through the synthetic fuel operations at TECO Coal. At Sep. 30, 2007, TECO Coal had sold ownership interests in the synthetic fuel facilities to unrelated third-party investors equal to 98%. These investors paid for the purchase of the ownership interests as synthetic fuel was produced. The payments were based on the amount of production and sales of synthetic fuel and the related underlying value of the tax credit, which was subject to potential limitation based on the price of domestic crude oil. These payments were recorded in “Other income” in the Consolidated Condensed Statements of Income. Additionally, the outside investors made payments towards the cost of producing synthetic fuel. These payments were reflected as a benefit under “Minority interest” in the Consolidated Condensed Statements of Income and comprised the majority of that line item. The synthetic fuel operations were terminated on Dec. 31, 2007 concurrent with the termination of the tax credit program.

For the nine month period ended Sep. 30, 2008, “Other income” included the final adjustment of $0.9 million to the 2007 inflation factor applied to the tax credit available on the production of synthetic fuel in 2007. For the three month and nine month periods ended Sep. 30, 2007, “Other income” reflected an estimated phase-out of approximately 48%, or $57.4 million and $76.1 million, respectively, reducing the benefit of the underlying value of the tax credit based on an internal estimate of the average annual price of domestic crude oil during 2007.

To protect the cash proceeds derived from the sale of ownership interests, TECO Energy had in place crude oil options to hedge against the risk of high oil prices reducing the value of the tax credits related to the production of synthetic fuel. These instruments were marked-to-market with fair value gains and losses recognized in “Other income” on the Consolidated Condensed Statements of Income. For the year ended Dec. 31, 2007, the company recognized gains of $82.7 million on these instruments, which were cash settled in January 2008.

9

Purchased Power

Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $65.0 million and $262.8 million for the three months and nine months ended Sep. 30, 2008, respectively, compared to $84.5 million and $207.6 million for the three months and nine months ended Sep. 30, 2007, respectively. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities (Tampa Electric and Peoples Gas System (PGS)) are allowed to recover from customers certain costs incurred through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. These amounts totaled $29.2 million and $83.2 million, respectively, for the three months and nine months ended Sep. 30, 2008, compared to $30.8 million and $84.8 million, respectively, for the three months and nine months ended Sep. 30, 2007. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These totaled $29.2 million and $83.0 million, respectively, for the three months and nine months ended Sep. 30, 2008, compared to $30.7 million and $84.6 million, respectively, for the three months and nine months ended Sep. 30, 2007.

2. New Accounting Pronouncements

Fair Value of a Financial Asset When the Market for That Asset Is Not Active

In October 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Financial Accounting Standard (FAS) 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (FSP FAS 157-3). This FSP clarifies the definition of fair value by stating that a transaction price is not necessarily indicative of fair value in a market that is not active or in a forced liquidation or distressed sale. Rather, if the company has the ability and intent to hold the asset, the company may use its assumptions about future cash flows and appropriately adjusted discount rates in measuring fair value of the asset. The guidance in FSP FAS 157-3 was effective immediately upon issuance on Oct. 10, 2008, including prior periods for which financial statements have not been issued. The adoption of FSP FAS 157-3 was not material to the company’s results of operations, statement of position or cash flows.

Disclosures about Credit Derivatives and Certain Guarantees

In September 2008, the FASB issued FSP No. FAS 133-1 and FASB Interpretation (FIN) 45-4,Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161 (FSP FAS 133-1 and FIN 45-4). This FSP requires more detailed disclosures about credit derivatives and more detailed disclosures by sellers of credit derivatives. The guidance in FSP FAS 133-1 and FIN 45-4 is effective for reporting periods ending after Nov. 15, 2008. The company does not believe FSP FAS 133-1 and FIN 45-4 will be material to its results of operations, statement of position or cash flows.

Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities

In June 2008, the FASB issued FASB Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1). FSP EITF 03-6-1 requires that the two-class method earnings per share calculation include unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether the dividend or dividend equivalents are paid or not paid. The guidance in FSP EITF 03-6-1 is effective for fiscal years beginning after Dec. 15, 2008. The company does not believe FSP EITF 03-6-1 will be material to its results of operations, statement of position or cash flows.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 161,Disclosures about Derivative Instruments and Hedging Activities(FAS 161). FAS 161 was issued to enhance the disclosure framework in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities(FAS 133). FAS 161 requires enhanced disclosures about the purpose of an entity’s derivative instruments, how derivative instruments and hedged items are accounted for, and how the entity’s financial position, cash flows, and performance are enhanced by the derivative instruments and hedged items. The guidance in FAS 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. The company believes that FAS 161 will be significant to its financial statement disclosures and will continue to evaluate the impact through its adoption.

Additionally, in April 2008, the FASB revised Statement 133 Implementation Issues Nos. I1 and K4 to reflect the enhanced disclosures required by FAS 161. The company does not believe these revisions will be material to its results of operations, statement of position or cash flows, but will be significant to its financial statement disclosures and will continue to evaluate the impact through its adoption.

10

Statement 133 Implementation Issue E23

In January 2008, the FASB cleared Implementation IssueHedging – General: Issues Involving the Application of the Shortcut Method under Paragraph 68 (Issue E23). Issue E23 amends FAS 133, paragraph 68 to include hedged items with trade dates differing from their settlement dates due to generally established conventions in the marketplace. This allows companies to assume these commitments have no ineffectiveness in a hedging relationship, thus allowing use of the shortcut method for accounting purposes assuming all other conditions within the paragraph are met.

Issue E23 also allows use of the shortcut method if the fair value of an interest rate swap is not zero at inception of the hedge as long as the swap was entered into at the relationship’s inception, there was no transaction price of the swap in the company’s principal or most advantageous market, and the difference between the swap’s fair value and transaction price is due to differing prices within the bid-ask spread between the entry transaction and a hypothetical exit transaction.

The effective date for Issue E23 is for hedging relationships entered into on or after Jan. 1, 2008. The company does not believe Issue E23 will be material to its results of operations, statement of position or cash flows.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements(FAS 160). FAS 160 was issued to improve the relevance, comparability and transparency of the financial information provided by requiring: ownership interests be presented in the consolidated statement of financial position separate from parent equity; the amount of net income attributable to the parent and the noncontrolling interest be identified and presented on the face of the consolidated statement of income; changes in the parent’s ownership interest be accounted for consistently; when deconsolidating, that any retained equity interest be measured at fair value; and that sufficient disclosures identify and distinguish between the interests of the parent and noncontrolling owners. The guidance in FAS 160 is effective for fiscal years beginning on or after Dec. 15, 2008. The company is currently assessing the impact of FAS 160, but does not believe it will be material to its results of operations, statement of position or cash flows.

Business Combinations (Revised)

In December 2007, the FASB issued SFAS No. 141R,Business Combinations(FAS 141R). FAS 141R was issued to improve the relevance, representational faithfulness, and comparability of information disclosed in financial statements about business combinations. FAS 141R establishes principles and requirements for how the acquirer: 1) recognizes and measures the assets acquired, liabilities assumed and any noncontrolling interest in the acquiree; 2) recognizes and measures the goodwill acquired; and 3) determines what information to disclose for users of financial statements to evaluate the effects of the business combination. The guidance in FAS 141R is effective prospectively for any business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after Dec. 15, 2008. The company will assess the impact of FAS 141R in the event it enters into a business combination for which the expected acquisition date is subsequent to the required effective date.

Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards

In June 2007, the EITF issued EITF Issue No. 06-11,Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11). EITF 06-11 states that realized tax benefits resulting from share-based payment awards that entitle employees to dividends or dividend equivalents on non-vested equity shares or to payments equal to the dividends paid on the underlying shares while the equity option is outstanding and the dividends or dividend equivalents should be recorded as additional paid-in capital. Further, the amount recorded as additional paid-in capital should be included in the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards in accordance with FAS 123(R),Accounting for Stock-Based Compensation. The company is currently assessing the impact of EITF 06-11, but does not believe it will be material to its results of operations, statement of position or cash flows.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FSP FIN 39-1. This FSP amends FASB Interpretation No. 39,Offsetting of Amounts Related to Certain Contracts by allowing an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The guidance in this FSP is effective for fiscal years beginning after Nov. 15, 2007. The company adopted this FSP effective Jan. 1, 2008 and set a policy to offset fair value amounts recognized with cash collateral received or cash collateral paid under master netting agreements. At Sep. 30, 2008, the company had received cash collateral in the amount of $0.5 million.

Fair Value Option For Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of FAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. FAS 159 is effective for fiscal years beginning

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after Nov. 15, 2007. The company adopted FAS 159 effective Jan. 1, 2008, but did not elect to measure any financial instruments at fair value. Accordingly, its adoption did not have any effect on its results of operations, statement of position or cash flows.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value, and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. FAS 157 defines the following fair value hierarchy, based on these two types of inputs:

• Level 1 – Quoted prices for identical instruments in active markets.

• Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations in which all significant inputs and significant value drivers are observable in active markets.

• Level 3 – Model derived valuations in which one or more significant inputs or significant value drivers are unobservable.

The effective date was for fiscal years beginning after Nov. 15, 2007. In November of 2007, the FASB informally granted a one year deferral for non-financial assets and liabilities. In February 2008, the FASB issued FSP 157-2 which formally delayed the effective date of FAS 157 to fiscal years beginning after Nov. 15, 2008. This FSP is applicable to non-financial assets and liabilities except for items that are required to be recognized or disclosed at fair value at least annually in the company’s financial statements. As a result, the company adopted FAS 157 effective Jan. 1, 2008 for financial assets and liabilities. SeeNote 13, Fair Value Measurements.

Additionally, the FASB issued FSP 157-1 in February 2008 to exclude SFAS 13,Accounting for Leases, and related pronouncements addressing lease fair value measurements from the scope of FAS 157. Assets and liabilities assumed in a business combination are not covered under this scope exception. The effective date of this FSP coincides with the adoption of FAS 157.

The company will continue to evaluate FAS 157 for the remaining non-financial assets and liabilities to be included effective Jan. 1, 2009. The company does not believe applying FAS 157 to the remaining non-financial assets and liabilities will be material to its results of operations, statement of position or cash flows.

3. Regulatory

Cost Recovery – Tampa Electric Company and PGS

Tampa Electric Company and PGS recover the cost of fuel, purchased power, eligible environmental expenditures and conservation through cost recovery clauses that are adjusted on an annual basis. As part of the regulatory process, it is reasonably likely that third parties may intervene in various matters related to fuel, purchased power, environmental and conservation cost recovery.

Base Rates

On Aug. 11, 2008, each of Tampa Electric Company and PGS filed for an increase in its base rates. For Tampa Electric Company, this was the first such filing since 1992. In its filing, using a 2009 projected test year, Tampa Electric requested a $228.2 million increase in base rates calculated on 55.3% equity in the capital structure with a 12% return on equity, an 8.82% weighted cost of capital and a 13-month average rate base of $3.7 billion. Discovery by the FPSC staff and intervenors is underway as are audits by the FPSC staff. Hearings are scheduled for January 2009 with a final FPSC decision expected in April with new rate effective in May 2009.

In its filing, also using a 2009 projected test year, PGS requested a $26.5 million increase in base rates calculated on 54.7% equity in the capital structure with an 11.5% return on equity, an 8.88% weighted cost of capital and a 13-month average rate base of $563.6 million. Discovery by the FPSC staff and intervenors is underway as are audits by the FPSC staff. Hearings are scheduled for March 2009 with a final FPSC decision expected in May with new rate effective in June 2009.

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SO₂ Emission Allowances

The Clean Air Act Amendments of 1990 (Clean Air Act) established SO₂ allowances to manage the achievement of SO₂ emissions requirements. The legislation also established a market-based SO₂ allowance trading component.

An allowance authorizes a utility to emit one ton of SO₂during a given year. The Environmental Protection Agency (EPA) allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use in current or future years. In addition, the EPA withholds a small percentage of the annual SO₂ allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause. These gains are reflected in “Revenues-Regulated electric and gas” on the Consolidated Condensed Statements of Income.

Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO₂ allowances unneeded and sold resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.

During the three months and nine months ended Sep. 30, 2008, approximately 12,500 and 17,500 allowances were sold, respectively, resulting in proceeds of $4.6 million and $6.6 million, respectively. During the three months and nine months ended Sep. 30, 2007, approximately 70,000 and 105,000 allowances were sold resulting in proceeds of $39.0 million and $56.6 million, respectively.

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 Federal Energy Regulatory Commission (FERC).

Tampa Electric and PGS apply the accounting treatment permitted by SFAS No. 71,Accounting for the Effects of Certain Types of Regulation(FAS 71). 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 the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year. Details of the regulatory assets and liabilities as of Sep. 30, 2008 and Dec. 31, 2007 are presented in the following table:

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Regulatory Assets and Liabilities

(millions)	Sep. 30, 2008		Dec. 31, 2007
Regulatory assets:
Regulatory tax asset(1)	$	64.8	$	62.5
Other:
Cost recovery clauses		212.5		47.2
Postretirement benefit asset		93.3		97.5
Deferred bond refinancing costs(2)		22.7		25.5
Environmental remediation		10.9		11.4
Competitive rate adjustment		4.6		5.4
Other		5.3		4.7
Total other regulatory assets		349.3		191.7
Total regulatory assets		414.1		254.2
Less: Current portion		223.3		67.4
Long-term regulatory assets	$	190.8	$	186.8
Regulatory liabilities:
Regulatory tax liability(1)	$	18.6	$	18.8
Other:
Deferred allowance auction credits		0.1		0.1
Cost recovery clauses		6.6		18.9
Environmental remediation		10.8		11.4
Transmission and delivery storm reserve		23.3		20.3
Deferred gain on property sales(3)		4.5		4.7
Accumulated reserve-cost of removal		553.5		543.5
Other		1.6		0.4
Total other regulatory liabilities		600.4		599.3
Total regulatory liabilities		619.0		618.1
Less: Current portion		26.2		35.4
Long-term regulatory liabilities	$	592.8	$	582.7

(1) Related to plant life and derivative positions.

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

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

All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods:

Regulatory assets

(millions)	Sep. 30, 2008		Dec. 31, 2007
Clause recoverable(1)	$	217.1	$	52.6
Earning a rate of return(2)		97.7		101.7
Regulatory tax assets(3)		64.8		62.5
Capital structure and other(3)		34.5		37.4
Total	$	414.1	$	254.2

(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar for dollar basis in the next year.

(2) Primarily reflects allowed working capital, which is included in rate base and earns an 8.2% rate of return as permitted by the FPSC.

(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

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4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax returns for the years 2005 and 2006 during 2007. The U.S. federal statute of limitations remains open for the year 2007 and onward. Years 2007 and 2008 are currently under examination by the IRS under the Compliance Assurance Program, a program in which the company is a participant. The company does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2008. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2002 and onward.

The company recognizes interest and penalties associated with uncertain tax positions in the Consolidated Condensed Statements of Income in accordance with FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. During the three and nine month periods ended Sep. 30, 2008, the company recorded approximately $0.4 million and $1.0 million, respectively, of pre-tax charges for interest only. No amounts have been recorded for penalties for the nine month periods ended Sep. 30, 2008 and Sep. 30, 2007.

During the nine month periods ended Sep. 30, 2008 and Sep. 30, 2007, the company experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included permanent reinvestment of foreign income under APB No. 23,Accounting for Taxes – Special Areas, depletion, repatriation of foreign source income to the United States, and reduction of income tax expense under the “tonnage tax” regime for transportation.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. The obligations of the Supplemental Executive Retirement Plan (SERP) were remeasured as of Jan. 1, 2008 to reflect the impact on this benefit plan of the settlement of the SERP obligations related to the retirement of certain participants. Settlement costs of $0.9 million that reflect the accelerated recognition of previously deferred actuarial gains were reclassed from accumulated other comprehensive income. These costs were recognized in the quarter ended Mar. 31, 2008 and are included in “Operation other expense—Other” in the Consolidated Condensed Statements of Income for the nine months ended Sep. 30, 2008. Other than the remeasurement of plan obligations for these participant retirements and, as discussed in Amendment No. 1 to the company’s Annual Report on Form 10-K for the year ended Dec. 31, 2007, the impacts of the termination of TECO Transport employees’ participation in these plans as a result of the sale of TECO Transport in December 2007, no significant changes have been made to these benefit plans since Dec. 31, 2003.

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Pension Expense

(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sep. 30,	2008			2007			2008		2007
Components of net periodic benefit expense
Service cost	$	3.9		$	4.0		$	1.0	$	1.3
Interest cost on projected benefit obligations		8.0			8.2			3.0		3.0
Expected return on assets		(9.8	)		(9.1	)		—		—
Amortization of:
Transition obligation		—			—			0.5		0.7
Prior service (benefit) cost		(0.1	)		(0.1	)		0.5		0.7
Actuarial loss		1.0			2.3			—		—
Pension expense		3.0			5.3			5.0		5.7
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	3.0		$	5.3		$	5.0	$	5.7
Nine months ended Sep. 30,
Components of net periodic benefit expense
Service cost	$	11.6		$	12.0		$	3.1	$	3.9
Interest cost on projected benefit obligations		23.9			24.6			9.0		9.0
Expected return on assets		(29.3	)		(27.3	)		—		—
Amortization of:
Transition obligation		—			—			1.7		2.1
Prior service (benefit) cost		(0.3	)		(0.3	)		1.3		2.1
Actuarial loss		3.0			6.9			—		—
Pension expense		8.9			15.9			15.1		17.1
Settlement cost		0.9			—			—		—
Curtailment cost		—			0.3			—		6.5
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	9.8		$	16.2		$	15.1	$	23.6

For the fiscal 2008 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.90% for pension benefits under its qualified pension plan as of its Dec. 4, 2007 remeasurement date; a discount rate of 5.90% for its SERP benefits as of its Jan. 1, 2008 remeasurement date; and a discount rate of 6.20% for other postretirement benefits at its Sep. 30, 2007 measurement date. As a result of the Dec. 4, 2007 and Jan. 1, 2008 remeasurements, benefit obligations for the pension plans increased $18.5 million.

Effective Dec. 31, 2006, in accordance with FAS 158,Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, TECO Energy adjusted its postretirement benefit obligations and recorded other comprehensive income (loss) to reflect the unamortized transition obligation, prior service cost, and actuarial gains and losses of its postretirement benefit plans. The adjustment to other comprehensive income was net of amounts that, for regulatory purposes prescribed by FAS 71, were recorded as regulatory assets for Tampa Electric Company. For the three months and nine months ended Sep. 30, 2008, TECO Energy and its subsidiaries reclassed $0.5 million and $1.6 million, respectively, of unamortized transition obligation, prior service cost and actuarial gains and losses from accumulated other comprehensive income to net income as part of periodic benefit expense compared to $1.1 million and $3.3 million, respectively, for the same periods ended Sep. 30, 2007. In addition, during the three months and nine months ended Sep. 30, 2008, Tampa Electric Company reclassed $1.4 million and $4.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial gains and losses from regulatory assets to net income as part of periodic benefit expense compared to $2.5 million and $7.5 million for the same periods ended Sep. 30, 2007.

TECO Energy’s defined benefit plan assets were negatively impacted by unfavorable market conditions through Sep. 30, and market conditions further deteriorated in October. We currently expect to contribute $11.7 million to the plan in the fourth quarter of 2008. However, the market impact on TECO Energy’s asset values could increase its future plan funding requirements above those normally expected.

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6. Short-Term Debt

At Sep. 30, 2008 and Dec. 31, 2007, the following credit facilities and related borrowings existed:

Credit Facilities

	Sep. 30, 2008						Dec. 31, 2007
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility	$	325.0	$	—	$	1.4	$	325.0	$	—	$	—
1-year accounts receivable facility		150.0		13.0		—		150.0		25.0		—
TECO Energy/TECO Finance:
5-year facility(2)		200.0		—		7.1		200.0		—		9.5
Total	$	675.0	$	13.0	$	8.5	$	675.0	$	25.0	$	9.5

(1) Borrowings outstanding are reported as notes payable.

(2) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

These credit facilities require commitment fees ranging from 9.0 to 17.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sep. 30, 2008 and Dec. 31, 2007 was 2.69% and 4.76%, respectively.

7. Long-Term Debt

Issuance of Tampa Electric Company 6.10% Notes due 2018

On May 16, 2008, Tampa Electric Company issued $150 million aggregate principal amount of 6.10% Notes due May 15, 2018. The 6.10% Notes were sold at par. The offering resulted in net proceeds to the Company (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $148.7 million. Net proceeds were used for general corporate purposes. Tampa Electric Company may redeem all or any part of the 6.10% Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 6.10% Notes to be redeemed or (ii) the present value of the remaining payments of principal and interest on the 6.10% Notes to be redeemed, discounted at an applicable treasury rate (as defined in the applicable indenture) plus 35 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

On May 15, 2008, in connection with this debt offering, Tampa Electric Company settled interest rate swaps entered into in 2007 for $11.8 million, coincident with the related May 2008 debt issuance. The cash outflows related to this settlement are netted with the proceeds from the debt offering in the financing section of the Consolidated Condensed Statement of Cash Flows and are recorded in “Accumulated other comprehensive loss” on the Consolidated Condensed Balance Sheet. These amounts will be reclassified to interest expense over the 10-year term of the related debt, resulting in an effective interest rate of 6.89%.

Remarketing and Repurchase in Lieu of Redemption of Tampa Electric Company’s Tax-Exempt Auction Rate Bonds

On Mar. 19, 2008, the Hillsborough County Industrial Development Authority (HCIDA) remarketed $86.0 million Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006, in a fixed-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The bonds, which previously had been in auction rate mode, bear interest at 5.00% per annum and are subject to mandatory tender for purchase on Mar. 15, 2012 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation, as more fully described in Amendment No. 1 to the company’s Annual Report on Form 10-K for the year ended Dec. 31, 2007.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $75.0 million Polk County Industrial Development Authority (PCIDA) Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 and $125.8 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C (collectively, the “2007 Bonds”). Also on that date, the Insurance Agreement dated as of Jul. 27, 2007 with Financial Guaranty Insurance Company, pursuant to which Financial Guaranty Insurance Company issued a financial guaranty insurance policy for the HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C (the “2007 HCIDA Bonds”), was terminated. The company also entered into a corresponding First Supplemental Loan and Trust Agreement regarding the removal of the bond insurance on the 2007 HCIDA Bonds. After these changes to the 2007 HCIDA Bonds, the company remarketed the $54.2 million Series A and the $51.6 million Series B 2007 Bonds in long term interest rate modes. The $54.2 million Series A bonds, which previously had been in auction rate mode, bear interest at 5.65% per annum until maturity on

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Mar. 15, 2018. The $51.6 million Series B bonds, which previously had been in auction rate mode, bear interest at 5.15% per annum and will be subject to mandatory tender on Sep. 1, 2013 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the 2007 Bonds.

As a result of these transactions, $95.0 million of the bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Sep. 30, 2008 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income for the three months and nine months ended Sep. 30, 2008 and 2007, related to changes in the fair value of cash flow hedges, amortization of unrecognized benefit costs associated with the company’s pension plans and unrecognized gains and losses on available-for-sale securities:

Other Comprehensive Income	Three months ended Sep. 30,									Nine months ended Sep. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2008
Unrealized loss on cash flow hedges	$	(6.7	)	$	2.5		$	(4.2	)	$	(10.7	)	$	4.1		$	(6.6	)
Add: Loss reclassified to net income		0.6			(0.2	)		0.4			1.2			(0.5	)		0.7
Loss on cash flow hedges		(6.1	)		2.3			(3.8	)		(9.5	)		3.6			(5.9	)
Amortization of unrecognized benefit costs		0.5			(0.2	)		0.3			1.6			(1.0	)		0.6
Change in benefit obligation due to remeasurement		—			—			—			(17.6	)		6.8			(10.8	)
Unrealized loss on available-for-sale securities (1)		(0.9	)		—			(0.9	)		(1.9	)		—			(1.9	)
Total other comprehensive loss	$	(6.5	)	$	2.1		$	(4.4	)	$	(27.4	)	$	9.4		$	(18.0	)
2007
Unrealized (loss) gain on cash flow hedges	$	(3.3	)	$	(1.2	)	$	(2.1	)	$	1.3		$	0.5		$	0.8
Less: Gain reclassified to net income		(2.0	)		(0.8	)		(1.2	)		(2.5	)		(0.9	)		(1.6	)
Loss on cash flow hedges		(5.3	)		(2.0	)		(3.3	)		(1.2	)		(0.4	)		(0.8	)
Amortization of unrecognized benefit costs		1.1			0.4			0.7			3.3			1.5			1.8
Recognized benefit costs due to curtailment		—			—			—			6.7			2.6			4.1
Change in benefit obligation due to remeasurement		—			—			—			(2.1	)		(0.8	)		(1.3	)
Total other comprehensive (loss) income	$	(4.2	)	$	(1.6	)	$	(2.6	)	$	6.7		$	2.9		$	3.8

Accumulated Other Comprehensive Loss
(millions)	Sep. 30, 2008			Dec. 31, 2007
Unrecognized pension losses and prior service costs (2)	$	(24.1	)	$	(13.3	)
Unrecognized other benefit losses, prior service costs and transition obligations (3)		2.9			2.3
Net unrealized losses from cash flow hedges(4)		(12.1	)		(6.2	)
Net unrecognized loss on available-for-sale securities		(1.9	)		—
Total accumulated other comprehensive loss	$	(35.2	)	$	(17.2	)

(1) Amount relates to an off-shore investment not subject to U.S. Federal income tax.

(2) Net of tax benefit of $14.4 million and $8.3 million as of Sep. 30, 2008 and Dec. 31, 2007, respectively.

(3) Net of tax expense of $1.8 million and $1.5 million as of Sep. 30, 2008 and Dec. 31, 2007, respectively.

(4) Net of tax benefit of $7.3 million and $3.8 million as of Sep. 30, 2008 and Dec. 31, 2007, respectively.

9. Earnings Per Share

For the three months and nine months ended Sep. 30, 2008, stock options of 4.1 million and 4.4 million shares, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect. Stock options of 6.6 million and 5.8 million shares for the three months and nine months ended Sep. 30, 2007, respectively, were similarly excluded from the computation.

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(millions, except per share amounts)	Three months ended Sep. 30,						Nine months ended Sep. 30,
	2008			2007			2008			2007
Numerator
Net income from continuing operations, basic and diluted	$	58.2		$	92.8		$	140.4		$	225.0
Discontinued operations, net of tax		—			—			—			14.3
Net income, diluted	$	58.2		$	92.8		$	140.4		$	239.3
Denominator
Average number of shares outstanding – basic		211.2			209.2			210.4			208.9
Plus: Incremental shares for assumed conversions:
Stock options and contingent performance shares		4.6			3.3			5.0			3.9
Less: Treasury shares which could be purchased		(3.2	)		(2.5	)		(3.7	)		(3.0	)
Average number of shares outstanding – diluted		212.6			210.0			211.7			209.8
Earnings per share from continuing operations
Basic	$	0.28		$	0.44		$	0.67		$	1.08
Diluted	$	0.27		$	0.44		$	0.66		$	1.07
Earnings per share from discontinued operations, net
Basic	$	—		$	—		$	—		$	0.07
Diluted	$	—		$	—		$	—		$	0.07
Earnings per share
Basic	$	0.28		$	0.44		$	0.67		$	1.15
Diluted	$	0.27		$	0.44		$	0.66		$	1.14

10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with SFAS No. 5,Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Investment in Empresa Eléctrica de Guatemala

TECO Guatemala has a 24% ownership interest in Empresa Eléctrica de Guatemala (EEGSA) through a joint venture (DECA II) with Iberdrola, S.A. and Electricidade de Portugal, S.A. The Value Added Distribution (VAD) charges applicable in the tariffs charged by EEGSA are reset every five years. The VAD was expected to be reset for a new five-year term in the third quarter in a manner similar to the process utilized in 2003, in accordance with applicable Guatemalan law.

On Jul. 25, 2008, the National Commission of Electrical Energy (CNEE), the Guatemalan regulatory body responsible for establishing tariff rates, issued a communication unilaterally disbanding the panel of experts appointed under existing regulations to review and approve the new tariff rates. On Jul. 31, 2008, CNEE issued resolutions setting new tariff rates for EEGSA, which deviated from the rates calculated consistent with the panel of experts’ guidance. The new lower VAD set by CNEE is significantly below the prior period level. The results herein from Aug. 1, 2008 forward reflect the lower tariff rates.

TECO Energy and EEGSA’s other investors are actively pursuing legal and other efforts to facilitate reconsideration of the VAD through procedures consistent with EEGSA’s interpretation of Guatemala’s Electricity Law. TECO Guatemala evaluated its $142.3 million investment in DECA II, including associated goodwill, at Sep. 30, 2008 and determined that the value was not impaired. However, the outcome of the current efforts is uncertain, and could impact this determination in the future.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2008,

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Tampa Electric Company has estimated its ultimate financial liability to be approximately $10.9 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors, or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

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

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves and 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

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and Tampa Electric Company’s letters of credit and guarantees as of Sep. 30, 2008 is as follows:

Letters of Credit and Guarantees-TECO Energy

(millions) Letters of Credit and Guarantees for the Benefit of:	2008		2009-2012		After (1) 2012		Total		Liabilities Recognized at Sep. 30, 2008
Tampa Electric
Letters of credit	$	—	$	—	$	0.3	$	0.3	$	—
Guarantees:
Fuel purchase/energy management(2)		—		—		20.0		20.0		6.9
		—		—		20.3		20.3		6.9
TECO Coal
Letters of credit		—		—		6.8		6.8		—
Guarantees: Fuel purchase related(2)		—		—		1.4		1.4		3.0
		—		—		8.2		8.2		3.0
Other subsidiaries
Guarantees:
Fuel purchase/energy management(2)		60.3		—		2.9		63.2		6.6
Total	$	60.3	$	—	$	31.4	$	91.7	$	16.5

Letters of Credit-Tampa Electric Company

(millions) Letters of Credit for the Benefit of:	2008		2009-2012		After (1) 2012		Total		Liabilities Recognized at Sep. 30, 2008
Tampa Electric
Letters of credit	$	—	$	—	$	1.4	$	1.4	$	—
Total	$	—	$	—	$	1.4	$	1.4	$	—

(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2012.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sep. 30, 2008. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

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Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance and Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2008, management believes that TECO Energy, TECO Finance and Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets, as required by SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information. All significant intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.

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Segment Information(1)
(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO(2) Guatemala			TECO (3) Transport			Other & Eliminations			TECO Energy
Three months ended Sep. 30,
2008
Revenues - external	$	601.5	$	180.6	$	142.0	$	1.8		$	—		$	0.2		$	926.1
Sales to affiliates		0.3		—		—		—			—			(0.3	)		—
Total revenues		601.8		180.6		142.0		1.8			—			(0.1	)		926.1
Equity earnings of unconsolidated affiliates		—		—		—		18.5			—			—			18.5
Depreciation		46.6		10.6		9.3		0.2			—			—			66.7
Total interest charges (1)		28.7		4.8		1.7		3.9			—			18.3			57.4
Internally allocated interest(1)		—		—		1.4		3.8			—			(5.2	)		—
Provision (benefit) for taxes		33.1		1.6		0.4		2.1			—			(8.6	)		28.6
Net income (loss) from continuing operations	$	50.6	$	2.6	$	3.7	$	11.7		$	—		$	(10.4	)	$	58.2
2007
Revenues - external	$	646.4	$	145.5	$	142.1	$	1.9		$	54.1		$	—		$	990.0
Sales to affiliates		0.5		—		—		—			23.8			(24.3	)		—
Total revenues		646.9		145.5		142.1		1.9			77.9			(24.3	)		990.0
Equity earnings of unconsolidated affiliates		—		—		—		15.7			(0.1	)		—			15.6
Depreciation		39.5		10.1		10.2		(0.1	)		—			0.1			59.8
Total interest charges (1)		28.8		4.4		3.2		3.8			1.3			22.4			63.9
Internally allocated interest(1)		—		—		3.0		3.7			0.3			(7.0	)		—
Provision (benefit) for taxes		38.6		2.5		9.5		1.7			5.0			(9.7	)		47.6
Net income (loss) from continuing operations	$	64.8	$	3.8	$	20.5	$	10.2		$	11.0		$	(17.5	)	$	92.8
(millions)	Tampa		Peoples		TECO		TECO(2)			TECO (3)			Other &			TECO
Nine months ended Sep. 30,	Electric		Gas		Coal		Guatemala			Transport			Eliminations			Energy
2008
Revenues - external	$	1,608.4	$	543.9	$	446.3	$	6.1		$	—		$	0.3		$	2,605.0
Sales to affiliates		1.0		—		—		—			—			(1.0	)		—
Total revenues		1,609.4		543.9		446.3		6.1			—			(0.7	)		2,605.0
Equity earnings of unconsolidated affiliates		—		—		—		57.5			—			—			57.5
Depreciation		136.8		31.2		27.8		0.6			—			0.2			196.6
Total interest charges (1)		86.0		13.5		6.2		11.4			—			53.9			171.0
Internally allocated interest(1)		—		—		5.2		11.2			—			(16.4	)		—
Provision (benefit) for taxes		65.2		11.4		2.5		6.1			—			(21.1	)		64.1
Net income (loss) from continuing operations	$	106.7	$	17.9	$	15.4	$	37.1		$	—		$	(36.7	)	$	140.4
2007
Revenues - external	$	1,662.1	$	457.9	$	396.7	$	5.9		$	155.0		$	0.2		$	2,677.8
Sales to affiliates		1.4		—		—		—			76.1			(77.5	)		—
Total revenues		1,663.5		457.9		396.7		5.9			231.1			(77.3	)		2,677.8
Equity earnings of unconsolidated affiliates		—		—		—		50.5			—			—			50.5
Depreciation		133.2		29.9		28.8		0.3			5.6			0.4			198.2
Total interest charges (1)		84.1		12.8		9.3		11.3			3.9			75.3			196.7
Internally allocated interest(1)		—		—		8.7		11.0			(0.1	)		(19.6	)		—
Provision (benefit) for taxes		69.0		12.8		37.2		5.1			11.2			(30.6	)		104.7
Net income (loss) from continuing operations	$	121.3	$	20.2	$	83.7	$	33.3		$	27.0		$	(60.5	)	$	225.0

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Segment Information(1)
(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO (2) Guatemala		Other & Eliminations		TECO Energy
At Sep. 30, 2008
Goodwill	$	—	$	—	$	—	$	59.4	$	—	$	59.4
Investment in unconsolidated affiliates		—		—		—		287.9		—		287.9
Other non-current investments		—		—		—		13.1		8.0		21.1
Total assets	$	5,267.8	$	837.0	$	301.0	$	458.1	$	111.2	$	6,975.1
At Dec. 31, 2007
Goodwill	$	—	$	—	$	—	$	59.4	$	—	$	59.4
Investment in unconsolidated affiliates		—		—		—		275.5		—		275.5
Other non-current investments		—		—		—		15.0		7.9		22.9
Total assets	$	4,838.3	$	761.4	$	501.2	$	435.3	$	229.0	$	6,765.2

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2008 and 2007 were at a pretax rate of 7.25% and 7.5%, respectively, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a ⁵⁰/50 debt/equity capital structure.

(2) Revenues are exclusive of entities deconsolidated as a result of FIN 46R. Total revenues for unconsolidated affiliates, attributable to TECO Guatemala based on ownership percentages, were $29.3 million and $27.1 million for the three months ended Sep. 30, 2008 and 2007, respectively, and $88.7 million and $86.7 million for the nine months ended Sep. 30, 2008 and 2007, respectively.

(3) TECO Transport was sold effective Dec. 4, 2007.

12. Derivatives and Hedging

At Sep. 30, 2008, TECO Energy and its affiliates had total derivative assets and liabilities (current and non-current) of $0.2 million and $83.2 million, respectively, compared to total derivative assets and liabilities (current and non-current) of $2.2 million and $26.1 million, respectively, at Dec. 31, 2007. At Sep. 30, 2008 and Dec. 31, 2007, accumulated other comprehensive income (AOCI) included after-tax losses of $12.1 million and $6.2 million, respectively, representing the fair value of cash flow hedges for transactions that will occur in the future. Amounts recorded in AOCI at Sep. 30, 2008 and Dec. 31, 2007 relate to interest rate and heating oil swaps. These interest rate swaps settled coincident with debt issued in May of 2008 (seeNote 7, Long-Term Debt). The amounts related to interest rate swaps will be amortized into earnings over the life of the associated debt.

For the three months ended Sep. 30, 2008 and 2007, TECO Energy and its affiliates reclassified amounts from AOCI and recognized net pretax losses of $0.6 million and net pretax gains of $2.0 million, respectively. For the nine months ended Sep. 30, 2008 and 2007, the amounts reclassified and recognized from AOCI were net pretax losses of $1.2 million and net pretax gains of $2.5 million, respectively (seeNote 8,Other Comprehensive Income). Amounts reclassified from AOCI in 2007 were primarily related to cash flow hedges of physical purchases of fuel oil. For these types of hedge relationships, the loss on the derivative reclassified from AOCI to earnings is offset by the decreased expense arising from lower prices paid for spot purchases of fuel oil. Conversely, reclassification of a gain from AOCI to earnings is offset by the increased cost of spot purchases of fuel oil.

The company expects to reclass pretax losses of $7.0 million from AOCI to the Consolidated Condensed Statements of Income within the next twelve months. These amounts relate to settled interest rate and heating oil swaps. As a result of applying the provisions of FAS 71, the changes in value of natural gas derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the risks of hedging activities (seeNote 3, Regulatory). Based on the fair value of cash flow hedges at Sep. 30, 2008, net pretax losses of $67.2 million are expected to be reclassified from regulatory liabilities to the Consolidated Condensed Statements of Income within the next twelve months. The amounts related to natural gas derivatives 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 2010.

For the three months and nine months ended Sep. 30, 2007, the company recognized a pretax gain of $36.4 million and $47.9 million, respectively, relating to crude oil options that were not designated as either a cash flow or fair value hedge.

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13. Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. It also requires recognition of trade-date gains related to certain derivative transactions whose fair value has been determined using unobservable market inputs. This guidance supersedes the guidance in EITF Issue No. 02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which prohibited the recognition of trade-date gains for such derivative transactions when determining the fair value of instruments not traded in an active market.

On Nov. 14, 2007, the FASB reaffirmed its position that companies will be required to implement the standard for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. The FASB did, however, provide a one year deferral for the implementation of FAS 157 for other non-financial assets and liabilities. Effective Jan. 1, 2008, the company adopted FAS 157 for financial assets and liabilities that are carried at fair value on a recurring basis.

FAS 157 is applied prospectively as of the first interim period for the fiscal year in which it is initially adopted, except for limited retrospective adoption for the following three items:

• The valuation of financial instruments using blockage factors;

• Financial instruments that were measured at fair value using the transaction price (as indicated in EITF 02-3); and,

• The valuation of hybrid financial instruments that were measured at fair value using the transaction price (as indicated in FAS 155).

The impact of adoption in these areas would be applied as a cumulative-effect adjustment to opening retained earnings, measured as the difference between the carrying amounts and the fair values of relevant assets and liabilities at the date of adoption. TECO Energy does not have any of the three aforementioned items, and therefore no transition adjustment was recorded.

Fair Value Hierarchy

FAS 157 specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. In accordance with FAS 157, these two types of inputs have created the following fair value hierarchy:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as OTC forwards, options and repurchase agreements.

• Level 3 – Pricing inputs include significant inputs that are generally not observable in the marketplace. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the company performs an analysis of all instruments subject to FAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

This hierarchy requires the use of observable market data when available.

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Determination of Fair Value

The company measures fair value using the procedures set forth below for all assets and liabilities measured at fair value that were previously carried at fair value pursuant to other accounting guidelines.

When available, the company uses quoted market prices on assets and liabilities traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the assets and liabilities are traded in a secondary market, the company makes use of acceptable practical expedients to calculate fair value, and classifies such items as Level 2.

If observable transactions and other market data are not available, fair value is based upon internally developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using internally generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

Valuation Techniques

FAS 157 describes three main approaches to measuring the fair value of assets and liabilities:

1)Market Approach - The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business). The market approach includes the use of matrix pricing.

2)Income Approach - The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

3)Cost Approach - The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Items Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2008. As required by FAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and heating oil swaps, the market approach was used in determining fair value. For other investments, the income approach was used.

Recurring Derivative Fair Value Measures

	At fair value as of Sep. 30, 2008
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	—	$	0.2	$	—	$	0.2
Other investments		—		—		13.1		13.1
Total	$	—	$	0.2	$	13.1	$	13.3
Liabilities
Natural gas swaps	$	—	$	76.6	$	—	$	76.6
Heating oil swaps		—		6.6		—		6.6
Total	$	—	$	83.2	$	—	$	83.2

Natural gas and heating oil swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of these swaps are the New York Mercantile Exchange (NYMEX) quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value.

The primary pricing inputs in determining the fair value of interest rate swaps are LIBOR swap rates as reported by Bloomberg. For each instrument, the projected forward swap rate is used to determine the stream of cash flows over the life of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. A $1.4 million liability, primarily in interest rate swaps, is held on the books of unconsolidated affiliates of TECO Guatemala, but is reflected in “Investment in unconsolidated affiliates” on the TECO Energy, Inc. Consolidated Condensed Balance Sheets.

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Other investments reflect two auction rate securities owned by TECO Guatemala with a combined par value of $15.0 million. As a result of market conditions, TECO Guatemala changed the valuation technique for these securities to an income approach using a discounted cash flow model. The model assumes a continuation of failed auctions and interest payments at the default rate. Cash flows are discounted at a rate reflecting current market conditions for the security. Accordingly, these securities changed to Level 3 within FAS 157’s three tier fair value hierarchy since initial valuation at Jan. 1, 2008.

Based on the fair value determined from the discounted cash flow analysis, a temporary impairment was recorded in other comprehensive income. These are investment grade securities backed by pools of student loans. Therefore, it is expected that the investments will not be settled at a price less than par value. Because the company has the ability and intent to hold this investment until a recovery of its original investment value, it considers the investment to be temporarily impaired at Sep. 30, 2008.

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2008 the fair value of derivatives was not materially affected by nonperformance risk. Our net positions with substantially all counterparties were liability positions.

Assets Measured at Fair Value on a Recurring Basis Using Unobservable Inputs (Level 3)

(in millions)	Auction Rate Securities			Interest Rate Swaps			Total
Balance at Jan. 1, 2008	$	—		$	(9.0	)	$	(9.0	)
Transfers to Level 3		14.0			—			14.0
Change in fair market value		—			(7.3	)		(7.3	)
Included in earnings		—			—			—
Balance at Mar. 31, 2008		14.0			(16.3	)		(2.3	)
Transfers to Level 3		—			—			—
Change in fair market value		—			4.5			4.5
Settled		—			11.8			11.8
Included in earnings		—			—			—
Balance at Jun. 30, 2008		14.0			—			14.0
Transfers to Level 3		—			—			—
Change in fair market value		(0.9	)		—			(0.9	)
Settled		—			—			—
Included in earnings		—			—			—
Balance at Sep. 30, 2008	$	13.1		$	—		$	13.1

$11.8 million of forward starting interest rate swaps were settled in the second quarter of 2008 and are related to our May 2008 issuance of debt.

14. Mergers, Acquisitions and Dispositions

Sale of TECO Transport

During the first quarter of 2007, management of the company engaged a financial advisor, contacted interested bidders and initiated other activities in connection with a plan to sell TECO Transport Corporation. In accordance with the provisions of SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets(FAS 144), it was determined that as of Mar. 31, 2007 TECO Transport met the requirements to be presented as an asset held for sale.

On Dec. 4, 2007, TECO Diversified, Inc., a wholly-owned subsidiary of the company, sold its entire interest in TECO Transport Corporation for $405 million to an unaffiliated investment group which resulted in a pretax gain of $220.4 million, net of transaction-related costs including the final working capital adjustment reflected in the first quarter of 2008. As a result of its significant continuing involvement with Tampa Electric Company for the waterborne transportation of solid fuel, the results of TECO Transport Corporation were reflected in continuing operations for the three months and nine months ended Sep. 30, 2007 in accordance with the provisions of FAS 144.

Also in accordance with the provisions of FAS 144, once designated as assets held for sale, the assets of TECO Transport Corporation were measured at the lower of its carrying amount or fair value and depreciation for these assets ceased beginning Apr. 1, 2007. For the three months ended Sep. 30, 2007 and the 6 months subsequent to Apr. 1, 2007, depreciation of $5.7 million and $11.4 million, respectively, would have been recorded had the assets of TECO Transport not been held for sale. For the three months and nine months ended Sep. 30, 2007, TECO Energy recognized $4.9 million and $21.2 million, respectively, in transaction-related costs related to the then potential sale.

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For the three months and nine months ended Sep. 30, 2008, Tampa Electric paid United Maritime Group, formerly TECO Transport Corporation, $37.4 million and $81.1 million, respectively, for the waterborne transportation services described above. For the three months and nine months ended Sep. 30, 2007, Tampa Electric paid TECO Transport $24.5 million and $74.3 million, respectively.

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TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company as of Sep. 30, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Sep. 30, 2008 and 2007. The results of operations for the three months and nine months ended Sep. 30, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008. References should be made to the explanatory notes affecting the consolidated financial statements contained in Amendment No. 1 to Tampa Electric Company’s Annual Report on Form 10-K for the year ended Dec. 31, 2007 and to the notes on pages 34-45 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2008 and Dec. 31, 2007	29-30
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and nine month periods ended Sep. 30, 2008 and 2007	31-32
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2008 and 2007	33
Notes to Consolidated Condensed Financial Statements	34-45

28

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Sep. 30,			Dec. 31,
(millions)	2008			2007
Property, plant and equipment
Utility plant in service
Electric	$	5,475.8		$	5,262.0
Gas		940.9			917.4
Construction work in progress		365.4			363.6
Property, plant and equipment, at original costs		6,782.1			6,543.0
Accumulated depreciation		(1,848.6	)		(1,808.6	)
		4,933.5			4,734.4
Other property		4.5			4.5
Total property, plant and equipment, net		4,938.0			4,738.9
Current assets
Cash and cash equivalents		26.6			11.9
Receivables, less allowance for uncollectibles of $2.8 and $1.4 at Sep. 30, 2008 and Dec. 31, 2007, respectively		288.6			238.8
Inventories, at average cost
Fuel		77.2			66.2
Materials and supplies		59.8			58.0
Current regulatory assets		223.3			67.4
Current derivative assets		0.1			0.3
Taxes receivable		—			2.9
Prepayments and other current assets		16.7			11.6
Total current assets		692.3			457.1
Deferred debits
Unamortized debt expense		23.0			22.9
Long-term regulatory assets		190.8			186.8
Long-term derivative assets		0.1			1.9
Other		15.7			11.7
Total deferred debits		229.6			223.3
Total assets	$	5,859.9		$	5,419.3

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

29

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets– continued

Unaudited

Liabilities and Capital	Sep. 30,			Dec. 31,
(millions)	2008			2007
Capital
Common stock	$	1,710.4		$	1,510.4
Accumulated other comprehensive loss		(7.0	)		(5.0	)
Retained earnings		313.8			295.6
Total capital		2,017.2			1,801.0
Long-term debt, less amount due within one year		1,894.7			1,844.8
Total capitalization		3,911.9			3,645.8
Current liabilities
Long-term debt due within one year		5.5			5.7
Notes payable		13.0			25.0
Accounts payable		246.9			237.6
Customer deposits		144.2			138.1
Current regulatory liabilities		26.2			35.4
Current derivative liabilities		67.3			26.0
Current deferred income taxes		30.0			0.3
Interest accrued		41.8			23.5
Taxes accrued		48.5			16.8
Other		11.2			11.3
Total current liabilities		634.6			519.7
Deferred credits
Non-current deferred income taxes		441.1			407.5
Investment tax credits		11.2			12.0
Long-term derivative liabilities		9.3			0.1
Long-term regulatory liabilities		592.8			582.7
Other		259.0			251.5
Total deferred credits		1,313.4			1,253.8
Total liabilities and capital	$	5,859.9		$	5,419.3

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

30

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Sep. 30,
(millions)	2008			2007
Revenues
Electric (includes franchise fees and gross receipts taxes of $24.4 in 2008 and $26.0 in 2007)	$	601.7		$	646.9
Gas (includes franchise fees and gross receipts taxes of $4.8 in 2008 and 2007)		180.6			145.3
Total revenues		782.3			792.2
Expenses
Operations
Fuel		263.7			275.0
Purchased power		65.0			84.5
Cost of natural gas sold		134.9			99.2
Other		72.7			75.0
Maintenance		27.8			26.1
Depreciation		57.2			49.6
Taxes, federal and state		34.4			40.4
Taxes, other than income		43.0			44.0
Total expenses		698.7			693.8
Income from operations		83.6			98.4
Other income
Allowance for other funds used during construction		1.3			0.7
Taxes, non-utility federal and state		(0.3	)		(0.7	)
Other income, net		2.1			3.4
Total other income		3.1			3.4
Interest charges
Interest on long-term debt		31.4			30.6
Other interest		2.6			2.9
Allowance for borrowed funds used during construction		(0.5	)		(0.3	)
Total interest charges		33.5			33.2
Net income		53.2			68.6
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) on cash flow hedges		0.2			(1.9	)
Total other comprehensive income (loss), net of tax		0.2			(1.9	)
Comprehensive Income	$	53.4		$	66.7

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

31

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Nine months ended Sep. 30,
(millions)	2008			2007
Revenues
Electric (includes franchise fees and gross receipts taxes of $64.8 in 2008 and $66.4 in 2007)	$	1,609.1		$	1,663.5
Gas (includes franchise fees and gross receipts taxes of $18.4 in 2008 and 2007)		543.9			457.4
Total revenues		2,153.0			2,120.9
Expenses
Operations
Fuel		603.5			723.7
Purchased power		262.8			207.6
Cost of natural gas sold		387.7			299.4
Other		215.8			200.7
Maintenance		94.2			86.2
Depreciation		168.0			163.1
Taxes, federal and state		75.4			80.1
Taxes, other than income		130.9			133.4
Total expenses		1,938.3			1,894.2
Income from operations		214.7			226.7
Other income
Allowance for other funds used during construction		4.3			3.5
Taxes, non-utility federal and state		(1.2	)		(1.7	)
Other income, net		6.1			9.9
Total other income		9.2			11.7
Interest charges
Interest on long-term debt		93.0			88.6
Other interest		8.0			9.7
Allowance for borrowed funds used during construction		(1.7	)		(1.4	)
Total interest charges		99.3			96.9
Net income		124.6			141.5
Other comprehensive loss, net of tax
Net unrealized loss on cash flow hedges		(2.0	)		(1.9	)
Total other comprehensive loss, net of tax		(2.0	)		(1.9	)
Comprehensive Income	$	122.6		$	139.6

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

32

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sep. 30,
(millions)	2008			2007
Cash flows from operating activities
Net income	$	124.6		$	141.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		168.0			163.1
Deferred income taxes		67.9			(31.5	)
Investment tax credits, net		(0.8	)		(1.9	)
Allowance for funds used during construction		(4.3	)		(3.5	)
Deferred recovery clause		(117.1	)		78.1
Receivables, less allowance for uncollectibles		(49.8	)		(86.4	)
Inventories		(12.8	)		(13.8	)
Prepayments		(5.1	)		(3.9	)
Taxes accrued		34.6			77.2
Interest accrued		18.3			10.8
Accounts payable		23.0			(41.1	)
Gain on sale of business/assets		(0.2	)		(0.3	)
Other		21.8			16.0
Cash flows from operating activities		268.1			304.3
Cash flows from investing activities
Capital expenditures		(376.8	)		(307.8	)
Allowance for funds used during construction		4.3			3.5
Net proceeds from sale of business		2.2			0.5
Cash flows used in investing activities		(370.3	)		(303.8	)
Cash flows from financing activities
Proceeds from long-term debt		327.8			444.1
Common stock		200.0			—
Repayment of long-term debt/Purchase in lieu of redemption		(292.5	)		(356.9	)
Net (decrease) increase in short-term debt		(12.0	)		25.0
Dividends		(106.4	)		(98.3	)
Cash flows from financing activities		116.9			13.9
Net increase in cash and cash equivalents		14.7			14.4
Cash and cash equivalents at beginning of period		11.9			5.1
Cash and cash equivalents at end of period	$	26.6		$	19.5

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

33

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies are as follows:

Principles of Consolidation and Basis of Presentation

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. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company and subsidiaries as of Sep. 30, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Sep. 30, 2008 and 2007. The results of operations for the three month and nine month periods ended Sep. 30, 2008 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2008.

The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates. The year-end condensed balance sheet data was derived from audited financial statements, however this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by GAAP in the United States of America.

Revenues

As of Sep. 30, 2008 and Dec. 31, 2007, unbilled revenues of $49.0 million and $46.6 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Purchased Power

Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $65.0 million and $262.8 million for the three months and nine months ended Sep. 30, 2008, respectively, compared to $84.5 million and $207.6 million for the three months and nine months ended Sep. 30, 2007, respectively. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities (Tampa Electric and PGS) are allowed to recover from customers certain costs incurred through rates approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. These amounts totaled $29.2 million and $83.2 million, respectively, for the three months and nine months ended Sep. 30, 2008, compared to $30.8 million and $84.8 million, respectively, for the three months and nine months ended Sep. 30, 2007. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These totaled $29.2 million and $83.0 million, respectively, for the three months and nine months ended Sep. 30, 2008, compared to $30.7 million and $84.6 million, respectively, for the three months and nine months ended Sep. 30, 2007.

Cash Flows Related to Derivatives and Hedging Activities

Tampa Electric Company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

2. New Accounting Pronouncements

Fair Value of a Financial Asset When the Market for That Asset Is Not Active

In October 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Financial Accounting Standard (FAS) 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active (FSP FAS 157-3). This FSP clarifies the definition of fair value by stating that a transaction price is not necessarily indicative of fair value in a market that is not active or in a forced liquidation or distressed sale. Rather, if the company has the ability and intent to hold the asset, the company may use its assumptions about future cash flows and appropriately adjusted discount rates in measuring fair value of the asset. The guidance in FSP FAS 157-3 was effective immediately upon issuance on Oct. 10, 2008, including prior periods for which financial statements have not been issued. The adoption of FSP FAS 157-3 was not material to the company’s results of operations, statement of position or cash flows.

34

Disclosures about Credit Derivatives and Certain Guarantees

In September 2008, the FASB issued FSP No. FAS 133-1 and FASB Interpretation (FIN) 45-4,Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161 (FSP FAS 133-1 and FIN 45-4). This FSP requires more detailed disclosures about credit derivatives and more detailed disclosures by sellers of credit derivatives. The guidance in FSP FAS 133-1 and FIN 45-4 is effective for reporting periods ending after Nov. 15, 2008. The company does not believe FSP FAS 133-1 and FIN 45-4 will be material to its results of operations, statement of position or cash flows.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 161,Disclosures about Derivative Instruments and Hedging Activities(FAS 161). FAS 161 was issued to enhance the disclosure framework in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities(FAS 133). FAS 161 requires enhanced disclosures about the purpose of an entity’s derivative instruments, how derivative instruments and hedged items are accounted for, and how the entity’s financial position, cash flows, and performance are enhanced by the derivative instruments and hedged items. The guidance in FAS 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008. The company believes that FAS 161 will be significant to its financial statement disclosures and we continue to evaluate the impact through its adoption.

Additionally, in April 2008, the FASB revised Statement 133 Implementation Issues Nos. I1 and K4 to reflect the enhanced disclosures required by FAS 161. The company does not believe these revisions will be material to its results of operations, statement of position or cash flows, but will be significant to its financial statement disclosures and will continue to evaluate the impact through its adoption.

Statement 133 Implementation Issue E23

In January 2008, the FASB cleared Implementation IssueHedging – General: Issues Involving the Application of the Shortcut Method under Paragraph 68 (Issue E23). Issue E23 amends FAS 133, paragraph 68 to include hedged items with trade dates differing from their settlement dates due to generally established conventions in the marketplace. This allows companies to assume these commitments have no ineffectiveness in a hedging relationship, thus allowing use of the shortcut method for accounting purposes assuming all other conditions within the paragraph are met.

Issue E23 also allows use of the shortcut method if the fair value of an interest rate swap is not zero at inception of the hedge as long as the swap was entered into at the relationship’s inception, there was no transaction price of the swap in the company’s principal or most advantageous market, and the difference between the swap’s fair value and transaction price is due to differing prices within the bid-ask spread between the entry transaction and a hypothetical exit transaction.

The effective date for Issue E23 is for hedging relationships entered into on or after Jan. 1, 2008. The company does not believe Issue E23 will be material to its results of operations, statement of position or cash flows.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements(FAS 160). FAS 160 was issued to improve the relevance, comparability and transparency of the financial information provided by requiring: ownership interests be presented in the consolidated statement of financial position separate from parent equity; the amount of net income attributable to the parent and the noncontrolling interest be identified and presented on the face of the consolidated statement of income; changes in the parent’s ownership interest be accounted for consistently; when deconsolidating, that any retained equity interest be measured at fair value; and that sufficient disclosures identify and distinguish between the interests of the parent and noncontrolling owners. The guidance in FAS 160 is effective for fiscal years beginning on or after Dec. 15, 2008. The company is currently assessing the impact of FAS 160, but does not believe it will be material to its results of operations, statement of position or cash flows.

Business Combinations (Revised)

In December 2007, the FASB issued SFAS No. 141R,Business Combinations(FAS 141R). FAS 141R was issued to improve the relevance, representational faithfulness, and comparability of information disclosed in financial statements about business combinations. FAS 141R establishes principles and requirements for how the acquirer: 1) recognizes and measures the assets acquired, liabilities assumed and any non-controlling interest in the acquiree; 2) recognizes and measures the goodwill acquired; and 3) determines what information to disclose for users of financial statements to evaluate the effects of the business combination. The guidance in FAS 141R is effective prospectively for any business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after Dec. 15, 2008. The company will assess the impact of FAS 141R in the event it enters into a business combination for which the expected acquisition date is subsequent to the required effective date.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FSP FIN 39-1. This FSP amends FASB Interpretation No. 39,Offsetting of Amounts Related to Certain Contracts by allowing an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The guidance in this FSP is

35

effective for fiscal years beginning after Nov. 15, 2007. The company adopted this FSP effective Jan. 1, 2008 and set a policy to offset fair value amounts recognized with cash collateral received or cash collateral paid under master netting agreements. At Sep. 30, 2008, the company had received cash collateral in the amount of $0.5 million.

Fair Value Option For Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115 (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of FAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. FAS 159 is effective for fiscal years beginning after Nov. 15, 2007. The company adopted FAS 159 effective Jan. 1, 2008, but did not elect to measure any financial instruments at fair value. Accordingly, its adoption did not have any effect on its results of operations, statement of position or cash flows.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value, and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. FAS 157 defines the following fair value hierarchy, based on these two types of inputs:

• Level 1 – Quoted prices for identical instruments in active markets.

• Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations in which all significant inputs and significant value drivers are observable in active markets.

• Level 3 – Model derived valuations in which one or more significant inputs or significant value drivers are unobservable.

The effective date was for fiscal years beginning after Nov. 15, 2007. In November of 2007, the FASB informally granted a one year deferral for non-financial assets and liabilities. In February 2008, the FASB issued FSP 157-2 which formally delayed the effective date of FAS 157 to fiscal years beginning after Nov. 15, 2008. This FSP is applicable to non-financial assets and liabilities except for items that are required to be recognized or disclosed at fair value at least annually in the company’s financial statements. As a result, the company adopted FAS 157 effective Jan. 1, 2008 for financial assets and liabilities. SeeNote 12, Fair Value Measurements.

Additionally, the FASB issued FSP 157-1 in February 2008 to exclude SFAS 13,Accounting for Leases, and related pronouncements addressing lease fair value measurements from the scope of FAS 157. Assets and liabilities assumed in a business combination are not covered under this scope exception. The effective date of this FSP coincides with the adoption of FAS 157.

The company will continue to evaluate FAS 157 for the remaining non-financial assets and liabilities to be included effective Jan. 1, 2009. The company does not believe applying FAS 157 to the remaining non-financial assets and liabilities will be material to its results of operations, statement of position or cash flows.

3. Regulatory

Cost Recovery – Tampa Electric Company and PGS

Tampa Electric Company and PGS recover the cost of fuel, purchased power, eligible environmental expenditures and conservation through cost recovery clauses that are adjusted on an annual basis. As part of the regulatory process, it is reasonably likely that third parties may intervene in various matters related to fuel, purchased power, environmental and conservation cost recovery.

Base Rates

On Aug. 11, 2008, each of Tampa Electric Company and PGS filed for an increase in its base rates. For Tampa Electric Company, this was the first such filing since 1992. In its filing, using a 2009 projected test year, Tampa Electric requested a $228.2 million increase in base rates calculated on 55.3% equity in the capital structure with a 12% return on equity, an 8.82% weighted cost of capital and a 13-month average rate base of $3.7 billion. Discovery by the FPSC staff and intervenors is underway as are audits by the FPSC staff. Hearings are scheduled for January 2009 with a final FPSC decision expected in April with new rate effective in May 2009.

36

In its filing, also using a 2009 projected test year, PGS requested a $26.5 million increase in base rates calculated on 54.7% equity in the capital structure with an 11.5% return on equity, an 8.88% weighted cost of capital and a 13-month average rate base of $563.6 million. Discovery by the FPSC staff and intervenors is underway as are audits by the FPSC staff. Hearings are scheduled for March 2009 with a final FPSC decision expected in May with new rate effective in June 2009.

SO₂ Emission Allowances

The Clean Air Act Amendments of 1990 (Clean Air Act) established SO₂ allowances to manage the achievement of SO₂ emissions requirements. The legislation also established a market-based SO₂ allowance trading component.

An allowance authorizes a utility to emit one ton of SO₂during a given year. The Environmental Protection Agency (EPA) allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use in current or future years. In addition, the EPA withholds a small percentage of the annual SO₂ allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause. These gains are reflected in “Revenues-Regulated electric and gas” on the Consolidated Condensed Statements of Income.

Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO₂ allowances unneeded and sold resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.

During the three months and nine months ended Sep. 30, 2008, approximately 12,500 and 17,500 allowances were sold, respectively, resulting in proceeds of $4.6 million and $6.6 million, respectively. During the three months and nine months ended Sep. 30, 2007, approximately 70,000 and 105,000 allowances were sold resulting in proceeds of $39.0 million and $56.6 million, respectively.

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 Federal Energy Regulatory Commission (FERC).

Tampa Electric and PGS apply the accounting treatment permitted by SFAS No. 71,Accounting for the Effects of Certain Types of Regulation(FAS 71). 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 the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year. Details of the regulatory assets and liabilities as of Sep. 30, 2008 and Dec. 31, 2007 are presented in the following table:

37

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2008		Dec. 31, 2007
Regulatory assets:
Regulatory tax asset(1)	$	64.8	$	62.5
Other:
Cost recovery clauses		212.5		47.2
Postretirement benefit asset		93.3		97.5
Deferred bond refinancing costs(2)		22.7		25.5
Environmental remediation		10.9		11.4
Competitive rate adjustment		4.6		5.4
Other		5.3		4.7
Total other regulatory assets		349.3		191.7
Total regulatory assets		414.1		254.2
Less: Current portion		223.3		67.4
Long-term regulatory assets	$	190.8	$	186.8
Regulatory liabilities:
Regulatory tax liability(1)	$	18.6	$	18.8
Other:
Deferred allowance auction credits		0.1		0.1
Cost recovery clauses		6.6		18.9
Environmental remediation		10.8		11.4
Transmission and delivery storm reserve		23.3		20.3
Deferred gain on property sales(3)		4.5		4.7
Accumulated reserve-cost of removal		553.5		543.5
Other		1.6		0.4
Total other regulatory liabilities		600.4		599.3
Total regulatory liabilities		619.0		618.1
Less: Current portion		26.2		35.4
Long-term regulatory liabilities	$	592.8	$	582.7

(1) Related to plant life and derivative positions.

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

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

All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods:

Regulatory assets

	Sep. 30,		Dec. 31,
(millions)	2008		2007
Clause recoverable(1)	$	217.1	$	52.6
Earning a rate of return(2)		97.7		101.7
Regulatory tax assets(3)		64.8		62.5
Capital structure and other(3)		34.5		37.4
Total	$	414.1	$	254.2

(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar for dollar basis in the next year.

(2) Primarily reflects allowed working capital, which is included in rate base and earns an 8.2% rate of return as permitted by the FPSC.

(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

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4. Income Taxes

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Tampa Electric Company’s effective tax rates for the nine months ended Sep. 30, 2008 and 2007 differ from the statutory rate principally due to state income taxes, amortization of investment tax credits and the domestic activity production deduction.

The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax returns for the years 2005 and 2006 during 2007. The U.S. federal statute of limitations remains open for the year 2007 and onward. Years 2007 and 2008 are currently under examination by the IRS under the Compliance Assurance Program, a program in which TECO Energy is a participant. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2008. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2004 and onward.

The company does not currently have any uncertain tax positions and does not anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease by the end of 2008.

5. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Effective Jan. 1, 2004, Tampa Electric Company adopted FAS 132R (revised 2003),Employers’ Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB Statements No. 87, 88 and 106, with no material effect. No significant changes have been made to these benefit plans since Dec. 31, 2003.

Amounts allocable to all participants of the TECO Energy retirement plans are found inNote 5,Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. Tampa Electric Company’s portion of the net pension expense for the three months ended Sep. 30, 2008 and 2007, respectively, was $2.1 million and $3.5 million for pension benefits, and $3.5 million and $3.6 million for other postretirement benefits. For the nine months ended Sep. 30, 2008 and 2007, respectively, net pension expense was $6.3 million and $10.5 million for pension benefits, and $10.5 million and $10.9 million for other postretirement benefits.

Included in the benefit expenses discussed above, for the three months and nine months ended Sep. 30, 2008, Tampa Electric Company reclassed $1.4 million and $4.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income compared to $2.5 million and $7.5 million, respectively, for the same periods ended Sep. 30, 2007.

For the fiscal 2008 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.90% for pension benefits under its qualified pension plan as of its Dec. 4, 2007 remeasurement date; a discount rate of 5.90% for its SERP benefits as of its Jan. 1, 2008 remeasurement date; and a discount rate of 6.20% for other postretirement benefits at its Sep. 30, 2007 measurement date. As a result of the Dec. 4, 2007 and Jan. 1, 2008 remeasurements, total benefit obligations for the pension plans increased $18.5 million.

6. Short-Term Debt

At Sep. 30, 2008 and Dec. 31, 2007, the following credit facilities and related borrowings existed:

Credit Facilities

	Sep. 30, 2008						Dec. 31, 2007
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility	$	325.0	$	—	$	1.4	$	325.0	$	—	$	—
1-year accounts receivable facility		150.0		13.0		—		150.0		25.0		—
Total	$	475.0	$	13.0	$	1.4	$	475.0	$	25.0	$	—

(1) Borrowings outstanding are reported as notes payable.

These credit facilities require commitment fees ranging from 9.0 to 17.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sep. 30, 2008 and Dec. 31, 2007 was 2.69% and 4.76%, respectively.

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7. Long-Term Debt

Issuance of Tampa Electric Company 6.10% Notes due 2018

On May 16, 2008, Tampa Electric Company issued $150 million aggregate principal amount of 6.10% Notes due May 15, 2018. The 6.10% Notes were sold at par. The offering resulted in net proceeds to the Company (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $148.7 million. Net proceeds were used for general corporate purposes. Tampa Electric Company may redeem all or any part of the 6.10% Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 6.10% Notes to be redeemed or (ii) the present value of the remaining payments of principal and interest on the 6.10% Notes to be redeemed, discounted at an applicable treasury rate (as defined in the applicable indenture) plus 35 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

On May 15, 2008, in connection with this debt offering, Tampa Electric Company settled interest rate swaps entered into in 2007 for $11.8 million, coincident with the related May 2008 debt issuance. The cash outflows related to this settlement are netted with the proceeds from the debt offering in the financing section of the Consolidated Condensed Statement of Cash Flows and are recorded in “Accumulated other comprehensive loss” on the Consolidated Condensed Balance Sheet. These amounts will be reclassified to interest expense over the 10-year term of the related debt, resulting in an effective interest rate of 6.89%.

Remarketing and Repurchase in Lieu of Redemption of Tampa Electric Company’s Tax-Exempt Auction Rate Bonds

On Mar. 19, 2008, the Hillsborough County Industrial Development Authority (HCIDA) remarketed $86.0 million Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006, in a fixed-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The bonds, which previously had been in auction rate mode, bear interest at 5.00% per annum and are subject to mandatory tender for purchase on Mar. 15, 2012 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation, as more fully described in Amendment No. 1 to the company’s Annual Report on Form 10-K for the year ended Dec. 31, 2007.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $75.0 million Polk County Industrial Development Authority (PCIDA) Solid Waste Disposal Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 and $125.8 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C (collectively, the “2007 Bonds”). Also on that date, the Insurance Agreement dated as of Jul. 27, 2007 with Financial Guaranty Insurance Company, pursuant to which Financial Guaranty Insurance Company issued a financial guaranty insurance policy for the HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007A, B and C (the “2007 HCIDA Bonds”), was terminated. The company also entered into a corresponding First Supplemental Loan and Trust Agreement regarding the removal of the bond insurance on the 2007 HCIDA Bonds. After these changes to the 2007 HCIDA Bonds, the company remarketed the $54.2 million Series A and the $51.6 million Series B 2007 Bonds in long term interest rate modes. The $54.2 million Series A bonds, which previously had been in auction rate mode, bear interest at 5.65% per annum until maturity on Mar. 15, 2018. The $51.6 million Series B bonds, which previously had been in auction rate mode, bear interest at 5.15% per annum and will be subject to mandatory tender on Sep. 1, 2013 from the proceeds of a remarketing of the bonds. Tampa Electric Company is responsible for payment of the interest and principal associated with the 2007 Bonds.

As a result of these transactions, $95.0 million of the bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Sep. 30, 2008 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

8. Commitments and Contingencies

Legal Contingencies

From time to time Tampa Electric Company and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS No. 5,Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2008, Tampa Electric Company has estimated its ultimate financial liability to be approximately $10.9 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 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 and 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

At Sep. 30, 2008, Tampa Electric Company was not obligated under guarantees, but had $1.4 million of letters of credit outstanding.

Letters of Credit - Tampa Electric Company

(millions) Letters of Credit for the Benefit of:	2008		2009-2012		After (1) 2012		Total		Liabilities Recognized at Sep. 30, 2008
Tampa Electric
Letters of credit	$	—	$	—	$	1.4	$	1.4	$	—
Total	$	—	$	—	$	1.4	$	1.4	$	—

(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2012.

At Sep. 30, 2008, TECO Energy had provided a $20.0 million fuel purchase guarantee and a $0.3 million letter of credit on behalf of Tampa Electric Company.

Financial Covenants

In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2008, management believes that Tampa Electric Company was in compliance with applicable financial covenants.

9. Related Parties

In October 2003, Tampa Electric signed a five-year contract renewal with a then affiliated company, TECO Transport, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008. TECO Transport was sold to an unaffiliated third-party on Dec. 4, 2007. For the three months and nine months ended Sep. 30, 2008, Tampa Electric paid United Maritime Group, formerly TECO Transport and now an unrelated entity, $37.4 million and $81.1 million, respectively. For the three months and nine months ended Sep. 30, 2007, Tampa Electric paid TECO Transport $24.5 million and $74.3 million, respectively.

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10. Segment Information

(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2008
Revenues - external	$	601.5	$	180.6	$	—		$	782.1
Sales to affiliates		0.3		—		(0.1	)		0.2
Total revenues		601.8		180.6		(0.1	)		782.3
Depreciation		46.6		10.6		—			57.2
Total interest charges		28.7		4.8		—			33.5
Provision for taxes		33.1		1.6		—			34.7
Net income	$	50.6	$	2.6	$	—		$	53.2
2007
Revenues - external	$	646.4	$	145.5	$	—		$	791.9
Sales to affiliates		0.5		—		(0.2	)		0.3
Total revenues		646.9		145.5		(0.2	)		792.2
Depreciation		39.5		10.1		—			49.6
Total interest charges		28.8		4.4		—			33.2
Provision for taxes		38.6		2.5		—			41.1
Net income	$	64.8	$	3.8	$	—		$	68.6
Nine months ended Sep. 30,
2008
Revenues - external	$	1,608.4	$	543.9	$	—		$	2,152.3
Sales to affiliates		1.0		—		(0.3	)		0.7
Total revenues		1,609.4		543.9		(0.3	)		2,153.0
Depreciation		136.8		31.2		—			168.0
Total interest charges		86.0		13.5		(0.2	)		99.3
Provision for taxes		65.2		11.4		—			76.6
Net income	$	106.7	$	17.9	$	—		$	124.6
Total assets at Sep. 30, 2008	$	5,084.9	$	790.2	$	(15.2	)	$	5,859.9
2007
Revenues - external	$	1,662.1	$	457.9	$	—		$	2,120.0
Sales to affiliates		1.4		—		(0.5	)		0.9
Total revenues		1,663.5		457.9		(0.5	)		2,120.9
Depreciation		133.2		29.9		—			163.1
Total interest charges		84.1		12.8		—			96.9
Provision for taxes		69.0		12.8		—			81.8
Net income	$	121.3	$	20.2	$	—		$	141.5
Total assets at Dec. 31, 2007	$	4,672.5	$	754.3	$	(7.5	)	$	5,419.3

11. Derivatives and Hedging

At Sep. 30, 2008 and Dec. 31, 2007, Tampa Electric Company had derivative assets (current and non-current) totaling $0.2 million and $2.2 million, respectively, and had derivative liabilities (current and non-current) totaling $76.6 million and $26.1 million, respectively. As a result of applying the provisions of FAS 71, the changes in value of natural gas derivatives are recorded as regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the risks of hedging activities (seeNote 3, Regulatory). During the second quarter of 2008, interest rate swaps related to debt issued were settled. These swaps were designated as cash flow hedges and as such the remaining after-tax balance of $7.0 million will be reclassed out of accumulated other comprehensive income into interest expense over the life of the debt.

Based on the fair values of derivatives at Sep. 30, 2008, net pretax losses of $67.2 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next twelve months. However, these amounts and other future reclassifications from regulatory assets or liabilities 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 2010.

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12. Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements.

FAS 157, among other things, requires the company to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. It also requires recognition of trade-date gains related to certain derivative transactions whose fair value has been determined using unobservable market inputs. This guidance supersedes the guidance in Emerging Issues Task Force Issue No. 02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which prohibited the recognition of trade-date gains for such derivative transactions when determining the fair value of instruments not traded in an active market.

On Nov. 14, 2007, the FASB reaffirmed its position that companies will be required to implement the standard for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. The FASB did, however, provide a one year deferral for the implementation of FAS 157 for other non-financial assets and liabilities. Effective Jan. 1, 2008, the company adopted FAS 157 for financial assets and liabilities that are carried at fair value on a recurring basis.

FAS 157 is applied prospectively as of the first interim period for the fiscal year in which it is initially adopted, except for limited retrospective adoption for the following three items:

• The valuation of financial instruments using blockage factors;

• Financial instruments that were measured at fair value using the transaction price (as indicated in EITF 02-3); and,

• The valuation of hybrid financial instruments that were measured at fair value using the transaction price (as indicated in FAS 155).

The impact of adoption in these areas would be applied as a cumulative-effect adjustment to opening retained earnings, measured as the difference between the carrying amounts and the fair values of relevant assets and liabilities at the date of adoption. Tampa Electric Company does not have any of the three aforementioned items, and therefore no transition adjustment was recorded.

Fair Value Hierarchy

FAS 157 specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. In accordance with FAS 157, these two types of inputs have created the following fair value hierarchy:

• Level 1– Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as OTC forwards, options and repurchase agreements.

• Level 3 – Pricing inputs include significant inputs that are generally not observable in the marketplace. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the company performs an analysis of all instruments subject to FAS 157 and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

This hierarchy requires the use of observable market data when available.

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Determination of Fair Value

The company measures fair value using the procedures set forth below for all assets and liabilities measured at fair value that were previously carried at fair value pursuant to other accounting guidelines.

When available, the company uses quoted market prices on assets and liabilities traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the assets and liabilities are traded in a secondary market, the company makes use of acceptable practical expedients to calculate fair value, and classifies such items as Level 2.

If observable transactions and other market data are not available, fair value is based upon internally developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using internally generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

Valuation Techniques

FAS 157 describes three main approaches to measuring the fair value of assets and liabilities:

1)Market Approach – The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business). The market approach includes the use of matrix pricing.

2)Income Approach – The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

3)Cost Approach – The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Items Measured at Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2008. As required by FAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures

	At fair value as of Sep. 30, 2008
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	—	$	0.2	$	—	$	0.2
Total	$	—	$	0.2	$	—	$	0.2
Liabilities
Natural gas swaps	$	—	$	76.6	$	—	$	76.6
Total	$	—	$	76.6	$	—	$	76.6

Natural gas swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the New York Mercantile Exchange (NYMEX) quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value.

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2008 the fair value of derivatives was not materially affected by nonperformance risk. Our net positions with substantially all counterparties were liability positions.

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Assets Measured at Fair Value on a Recurring Basis Using Unobservable Inputs (Level 3)

(in millions)	Interest Rate Swaps			Total
Balance at Jan. 1, 2008	$	(9.0	)	$	(9.0	)
Transfers to Level 3		—			—
Change in fair market value		(7.3	)		(7.3	)
Included in earnings		—			—
Balance at Mar. 31, 2008	$	(16.3	)	$	(16.3	)
Transfers to Level 3		—			—
Change in fair market value		4.5			4.5
Settled		11.8			11.8
Included in earnings		—			—
Balance at Jun. 30, 2008	$	—		$	—
Transfers to Level 3		—			—
Change in fair market value		—			—
Settled		—			—
Included in earnings		—			—
Balance at Sep. 30, 2008	$	—		$	—

$11.8 million of forward starting interest rate swaps were settled in the second quarter of 2008 and are related to our May 2008 issuance of debt. The primary pricing inputs in determining the fair value of interest rate swaps are LIBOR swap rates as reported by Bloomberg. For each instrument, the projected forward swap rate was used to determine the stream of cash flows over the life of the contract. The cash flows were then discounted using a spot discount rate to determine the fair value.

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Form 10-Q, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; access to capital and credit markets when required in the current unsettled economic conditions; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida economy and demand for TECO Coal’s production; weather variations and changes in customer energy usage patterns affecting sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions or hurricanes, which are common during the summer months; operating conditions, commodity price and operating cost changes affecting the production levels and margins at TECO Coal, fuel cost recoveries and cash at Tampa Electric or natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; and the ultimate outcome of efforts to revise the significantly lower EEGSA VAD tariff rates implemented by regulatory authorities in Guatemala effective Aug. 1, 2008 affecting TECO Guatemala’s results. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2007, as updated by the information contained in Item 1A of Part II of this Quarterly Report on Form 10-Q and the Quarterly Report for the period ended Jun. 30, 2008.

Earnings Summary -Unaudited

	Three months ended Sep. 30,				Nine months ended Sep. 30,
(millions, except per share amounts)	2008		2007		2008		2007
Consolidated revenues	$	926.1	$	990.0	$	2,605.0	$	2,677.8
Net income from continuing operations		58.2		92.8		140.4		225.0
Discontinued operations		—		—		—		14.3
Net income	$	58.2	$	92.8	$	140.4	$	239.3
Average common shares outstanding
Basic		211.2		209.2		210.4		208.9
Diluted		212.6		210.0		211.7		209.8
Earnings per share - basic
Continuing operations	$	0.28	$	0.44	$	0.67	$	1.08
Discontinued operations		—		—		—		0.07
Earnings per share - basic	$	0.28	$	0.44	$	0.67	$	1.15
Earnings per share - diluted
Continuing operations	$	0.27	$	0.44	$	0.66	$	1.07
Discontinued operations		—		—		—		0.07
Earnings per share - diluted	$	0.27	$	0.44	$	0.66	$	1.14

Operating Results

Three Months Ended Sep. 30, 2008:

Third quarter net income and earnings per share were $58.2 million, or $0.28 per share, compared to $92.8 million, or $0.44 per share in the third quarter of 2007. As a result of the sale of TECO Transport in December 2007 and the conclusion of the program for tax credits from the production of synthetic fuel at the end of 2007, third quarter net income in 2008 included no benefits from the operations of TECO Transport or from the production of synthetic fuel, which contributed $11.0 million and $13.1 million, respectively, or $0.11 per share collectively, in the 2007 period.

Nine Months Ended Sep. 30, 2008:

Year-to-date net income and earnings per share were $140.4 million, or $0.67 per share in 2008, compared to $239.3 million, or $1.15 per share in 2007. Net income and earnings per share from continuing operations were $225.0 million, or $1.08 per share for the same period in 2007. TECO Transport and the production of synthetic fuel contributed $27.0 million and $54.8 million, respectively, or $0.39 per share collectively, to year-to-date 2007 net income. In 2007, year-to-date results included a $14.3 million, or $0.07 per share, tax benefit recorded in discontinued operations as a result of reaching a favorable conclusion with taxing authorities related to the 2005 disposition of the Union and Gila River merchant power plants.

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Operating Company Results

All amounts included in the operating company and Other and Eliminations discussions are after-tax, unless otherwise noted.

Tampa Electric Company – Electric division (Tampa Electric)

Net income for the third quarter was $50.6 million, compared with $64.8 million for the same period in 2007. Results for the quarter reflect lower retail energy sales, a total number of customers that was essentially unchanged and decreased sales to industrial customers. Net income included $1.3 million of Allowance for Funds Used During Construction (AFUDC) - Equity, which represents allowed equity cost capitalized to construction costs, related to the installation of nitrogen oxide (NOx) pollution control equipment, compared to $0.7 million included in the 2007 period. Base revenues decreased $14.2 million in the quarter, primarily due to mild weather and lower per customer usage.

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost recovery clauses, increased $0.6 million in the third quarter of 2008, primarily due to $1.1 million higher spending on maintenance at the power generating facilities, slightly higher bad debt expense, $0.5 million of higher employee related and vehicle fuel costs, partially offset by $1.8 million of lower overhead and self-insurance reserve expenses compared to the 2007 period.

Compared to the third quarter of 2007, net income included $4.4 million higher depreciation expense. Results in 2007 included the benefits of nine months of lower depreciation rates recorded as a result of a depreciation study approved by the FPSC in the third quarter. Property tax expense was essentially unchanged from 2007 due to a $1.8 million benefit recorded in the third quarter of 2008 reflecting adjustments to property valuations agreed to with various taxing authorities. In 2007, property tax expenses included the one-time benefit of nine months of lower property tax rates effective in the third quarter from legislation passed in Florida in 2007, and adjustments to property valuations.

Tampa Electric’s retail energy sales decreased 6.7% in the third quarter due to mild weather, lower sales to industrial customers due to phosphate production facility outages and continued weak economic conditions. Cooling degree-days for the Tampa area in the third quarter were 7% below normal and 11% below actual 2007 levels.

The absence of net customer growth in the third quarter and 0.3% growth in the year-to-date 2008 period reflect the current weak economic conditions in the Tampa area and continued weakness in the local housing market. New customer additions were essentially offset by meter disconnects associated with housing foreclosures and vacant homes.

Year-to-date net income was $106.7 million, compared to $121.3 million in the 2007 period, driven primarily by 2.4% lower retail energy sales, higher maintenance costs related to generating system unit outages, $2.2 million higher depreciation expense, increased interest expense and lower interest income partially offset by $3.2 million higher earnings on investments in emissions control equipment recovered through the Environmental Cost Recovery Clause. Net income also included $4.3 million of AFUDC—Equity related to the installation of NO_x pollution control equipment, compared to $3.5 million included in the 2007 period. Total heating and cooling degree days were 4% below normal due to mild winter weather and 5% below actual 2007 degree days. Year-to-date pretax revenue declined $9.8 million primarily due to mild weather, customer usage patterns and lower sales to phosphate customers due to maintenance outages at their facilities.

Excluding all FPSC-approved cost recovery clause-related expenses, year-to-date net income reflects $7.0 million higher operations and maintenance expense compared to 2007, including $5.1 million higher spending on power generating equipment and $1.1 million higher bad debt expense.

Interest expense at Tampa Electric increased $1.2 million due to higher levels of long-term debt outstanding and higher interest on auction-rate bonds remarketed in the first quarter of the year. In addition, interest income decreased $2.7 million due to lower cash balances and lower interest earned on lower average under-recovered fuel balances.

On Aug. 11, 2008, Tampa Electric filed for an increase in its base rates for the first time since 1992. In its filing, using a 2009 projected test year, Tampa Electric requested a $228.2 million increase in base rates calculated on 55.3% equity in the capital structure with a 12% return on equity, an 8.82% weighted cost of capital on a 13-month average rate base of $3.7 billion. Discovery by the FPSC staff and interveners is underway as are audits by the FPSC staff. Hearings are scheduled for January 2009 with a final FPSC decision expected in April with new rate effective in May 2009.

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A summary of Tampa Electric’s operating statistics for the three months and nine months ended Sep. 30, 2008 and 2007 follows:

	Operating Revenues								Kilowatt-hour sales
(millions, except average customers)	2008			2007			% Change		2008	2007	% Change
Three months ended Sep. 30,
By Customer Type
Residential	$	299.3		$	327.0		(8.5	)	2,638.8	2,892.3	(8.8	)
Commercial		176.3			184.7		(4.5	)	1,784.1	1,869.5	(4.6	)
Industrial – Phosphate		14.3			18.3		(21.9	)	208.3	262.0	(20.5	)
Industrial – Other		28.1			30.7		(8.5	)	327.0	343.1	(4.7	)
Other sales of electricity		49.4			47.9		3.1		494.5	478.5	3.3
Deferred and other revenues(1)		(0.3	)		(30.1	)	(99.0	)	—	—	—
		567.1			578.5		(2.0	)	5,452.7	5,845.4	(6.7	)
Sales for resale		18.4			18.7		(1.6	)	241.4	249.4	(3.2	)
Other operating revenue		11.8			10.6		11.3		—	—	—
SO2 Allowance sales		4.6			39.0		(88.2	)	—	—	—
	$	601.9		$	646.8		(6.9	)	5,694.1	6,094.8	(6.6	)
Average customers (thousands)		666.2			666.6		(0.1	)
Retail output to line (kilowatt hours)									5,729.1	6,113.8	(6.3	)
Nine months ended Sep. 30,
By Customer Type
Residential	$	753.6		$	781.7		(3.6	)	6,570.3	6,823.2	(3.7	)
Commercial		485.6			491.6		(1.2	)	4,873.6	4,926.5	(1.1	)
Industrial – Phosphate		47.4			54.4		(12.9	)	693.1	782.5	(11.4	)
Industrial – Other		85.8			89.4		(4.0	)	957.1	997.7	(4.1	)
Other sales of electricity		138.8			131.8		5.3		1,377.1	1,295.7	6.3
Deferred and other revenues(1)		5.5			(22.7	)	(124.2	)	—	—	—
		1,516.7			1,526.2		(0.6	)	14,471.2	14,825.6	(2.4	)
Sales for resale		53.5			51.9		3.1		661.2	670.6	(1.4	)
Other operating revenue		32.7			28.7		13.9		—	—	—
SO2 Allowance sales		6.6			56.7		(88.4	)	—	—	—
	$	1,609.5		$	1,663.5		(3.2	)	15,132.4	15,496.2	(2.3	)
Average customers (thousands)		667.6			665.8		0.3
Retail output to line (kilowatt hours)									15,362.7	15,694.7	(2.1	)

(1) Primarily reflects the timing of environmental and fuel clause recoveries.

Tampa Electric Company – Natural gas division (PGS)

Peoples Gas reported net income of $2.6 million for the third quarter, compared to $3.8 million in the same period in 2007. Quarterly results reflect lower margins on off-system sales reflecting market conditions and higher volumes transported for industrial customers. Average customer growth of 0.2% in the quarter is a result of the continued weak Florida housing market. Therm sales to industrial customers increased due to two new customers with significant usage. The effects of these higher volumes were more than offset by higher non-fuel operations and maintenance expense, higher depreciation expense due to routine additions to facilities to serve customers, and increased interest expense due to higher levels of long-term debt outstanding.

Year-to-date net income was $17.9 million, compared to $20.2 million in the 2007 period, driven largely by lower margins on off-system sales, lower residential volumes and higher depreciation expense. Results also reflect average customer growth of 0.3% and lower sales to weather-sensitive residential customers due to very mild weather.

On Aug. 11, 2008, Peoples Gas filed for an increase in its base rates. In its filing, using a 2009 projected test year, Peoples Gas requested a $26.5 million increase in base rates calculated on 54.7% equity in the capital structure with an 11.5% return on equity, an 8.88% weighted cost of capital and a 13-month average rate base of $563.6 million. Discovery by the FPSC staff and intervenors is underway as are audits by the FPSC staff. Hearings are scheduled for March 2009 with a final FPSC decision expected in May with new rate effective in June 2009.

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A summary of PGS’ regulated operating statistics for the three months and nine months ended Sep. 30, 2008 and 2007 follows:

	Operating Revenues						Therms
(millions, except average customers)	2008		2007		% Change		2008	2007	% Change
Three months ended Sep. 30,
By Customer Type
Residential	$	26.6	$	23.2	14.7		10.7	10.0	7.0
Commercial		34.1		31.4	8.6		82.1	79.8	2.9
Industrial		1.9		2.4	(20.8	)	44.4	42.2	5.2
Off system sales		105.4		73.8	42.8		99.0	97.7	1.3
Power generation		2.9		4.9	(40.8	)	134.3	172.4	(22.1	)
Other revenues		7.8		8.4	(7.1	)	—	—	—
Total	$	178.7	$	144.1	24.0		370.5	402.1	(7.9	)
By Sales Type
System supply	$	151.3	$	114.3	32.4		122.5	121.0	1.2
Transportation		19.6		21.4	(8.4	)	248.0	281.1	(11.8	)
Other revenues		7.8		8.4	(7.1	)	—	—	—
Total	$	178.7	$	144.1	24.0		370.5	402.1	(7.9	)
Average customers (thousands)		334.1		333.5	0.2
Nine months ended Sep 30,
By Customer Type
Residential	$	107.5	$	108.6	(1.0	)	53.3	53.6	(0.6	)
Commercial		116.5		123.1	(5.4	)	279.8	279.4	0.1
Industrial		6.4		7.3	(12.3	)	144.5	142.0	1.8
Off system sales		271.8		174.2	56.0		259.7	226.4	14.7
Power generation		10.0		11.2	(10.7	)	374.0	354.9	5.4
Other revenues		26.3		28.6	(8.0	)	—	—	—
Total	$	538.5	$	453.0	18.9		1,111.3	1,056.3	5.2
By Sales Type
System supply	$	445.6	$	356.6	25.0		357.4	329.5	8.5
Transportation		66.6		67.7	(1.6	)	753.9	726.8	3.7
Other revenues		26.3		28.7	(8.4	)	—	—	—
Total	$	538.5	$	453.0	18.9		1,111.3	1,056.3	5.2
Average customers (thousands)		335.5		334.6	0.3

TECO Coal

TECO Coal achieved third quarter net income of $3.7 million, compared to $20.5 million in the same period in 2007. In 2007, TECO Coal’s results included $13.1 million of net income related to synthetic fuel production. The 2008 quarter includes a $2.6 million benefit from a contract settlement related to future coal sales.

Third quarter total sales were 2.2 million tons, compared to 2.4 million tons in the third quarter of 2007, which included 1.7 million tons of synthetic fuel. TECO Coal continues to experience lower than expected production due to difficult mining conditions in an underground mine, which temporarily reduced production from that mine late in the third quarter. Production was also negatively impacted by a shortage of qualified underground mining personnel and increased safety inspections. Compared to the third quarter in 2007, results reflect an average per-ton selling price almost 10% higher across all products, excluding transportation allowances. In the third quarter of 2008, the cash cost of production per ton increased 16% over 2007’s level, driven by diesel oil prices that, while down slightly from the second quarter peak, were still more than double 2007 prices; higher per-ton costs for steel products used in underground mining, such as roof bolts; higher costs for explosives used in surface mining operations, that like diesel fuel are down from second quarter peak levels; and higher costs associated with contract miners.

TECO Coal recorded year-to-date net income of $15.4 million in 2008, compared to $83.7 million in the 2007 period. TECO Coal’s 2007 year-to-date results included $54.8 million of net income associated with the production of synthetic fuel.

Year-to-date 2008 total sales were 7.1 million tons, compared to 6.8 million tons in the 2007 period, which included 4.5 million tons of synthetic fuel. Results in 2008 reflect an average net per-ton selling price across all products, excluding transportation allowances, that was more than 6% higher than in 2007. In 2008, the cash cost of production for the year-to-date period was approximately 14% higher than in 2007, driven by the same factors as in the third quarter. Results also reflect a $0.6 million benefit in the first quarter of 2008 from the true-up of the 2007 synthetic fuel tax credit rate, compared to a $1.6 million benefit included in the first quarter of 2007.

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TECO Guatemala

TECO Guatemala reported third quarter net income of $11.7 million in 2008, compared to $10.2 million in the 2007 period. Year-to-date 2008 net income was $37.1 million, compared to $33.3 million in the 2007 period. Earnings from the San José Power Station increased significantly from higher spot market prices for spot energy sales, and from energy sales made under the power sales contract due to increased sales and a scheduled price escalation. Interest expense for both the Alborada and San José power stations decreased in both periods due to lower interest rates and lower project-debt balances. At EEGSA, the distribution utility, 2008 third quarter and year-to-date results reflect customer growth and higher energy sales, partially offset by the reduction in the VAD tariff effective Aug. 1, 2008, which reduced net income approximately $0.6 million in the quarter. SeeNote 10to theTECO Energy, Inc. Consolidated Condensed Financial Statements for further discussion. The earnings from the unregulated EEGSA-affiliated companies (DECA II), which provide, among other things, electricity transmission services, telecommunication carrier services, wholesale power sales to unregulated electric customers and engineering services, increased in both periods from fundamental growth in the businesses. The year-to-date results for EEGSA and affiliated companies also included a $3.1 million benefit related to an adjustment to previously estimated 2007 income and year-end equity balances, compared to a similar $1.9 million benefit in 2007.

Other and Eliminations

The cost for “Parent/other” in the third quarter of 2008 was $10.4 million, compared to a cost of $17.5 million in the same period in 2007. In the 2007 third quarter “Parent/other” included $3.0 million of charges related to the sale of TECO Transport. The improvement in 2008 was driven by lower interest expense partially offset by lower investment income due to lower cash balances. Total parent/TECO Finance interest expense declined by $4.0 million in the third quarter of 2008, reflecting parent debt retirements.

The year-to-date “Parent/other” cost was $36.7 million in 2008, compared to $60.5 million in the 2007 period. Cost in 2008 includes $0.6 million related to previously estimated transaction costs associated with the sale of TECO Transport, compared to 2007, which included $13.0 million of charges related to the sale of TECO Transport. Year-to-date 2008 total parent/TECO Finance interest expense declined by $15.0 million, due to parent debt retirements, and was offset in part by lower interest income.

Income Taxes

The provisions for income taxes from continuing operations for the 2008 third quarter and year-to-date periods were $28.6 million and $64.1 million, respectively, compared to $47.6 million and $104.7 million for the same periods in 2007. The provision for income taxes from continuing operations in the nine months ended Sep. 30, 2008 was impacted by the termination of the synthetic fuel operations tax credit program and its related investor income, as well as by the sale of TECO Transport on Dec. 3, 2007. In addition to the income taxes on recurring operations, the 2007 provision for income taxes includes an income tax benefit related to the application of the “tonnage tax” to qualified vessels.

During the nine month periods ended Sep. 30, 2008 and Sep. 30, 2007, the company experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included permanent reinvestment of foreign income under APB No. 23, depletion, repatriation of foreign source income to the United States and reduction of income tax expense under the new “tonnage tax” regime.

Interest Charges

Total interest charges for the three and nine months ended Sep. 30, 2008 were $57.4 million and $171.0 million, respectively, compared to $63.9 million and $196.7 million for the three and nine months ended Sep. 30, 2007. The lower interest expense reflects parent debt redemption and refinancing activities including the retirement of $300 million of 6.125% notes at maturity in May 2007 and $297.2 million of 7.5% notes due in 2010 in December 2007, offset slightly by the impact of higher long-term debt balances at the regulated utilities.

Liquidity and Capital Resources

The table below sets forth the Sep. 30, 2008 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and Tampa Electric Company credit facilities.

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	Balances as of Sep. 30, 2008
(millions)	Consolidated		Tampa Electric Company		Other		Parent
Credit facilities	$	675.0	$	475.0	$	—	$	200.0
Drawn amounts / LCs	$	21.5		14.4		—		7.1
Available credit facilities		653.5		460.6		—		192.9
Cash and short-term investments		94.9		26.6		60.0		8.3
Total liquidity	$	748.4	$	487.2	$	60.0	$	201.2
Consolidated restricted cash (not included above)	$	7.5	$	—	$	0.2	$	7.3

Consolidated other cash and short-term investments includes $10.0 million of cash at the unregulated operating companies for normal operations and $50.0 million of consolidated cash and short-term investments at TECO Guatemala held offshore due to the tax deferral strategy associated with EEGSA. In addition to consolidated cash, as of Sep. 30, 2008, unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash and short-term investment balances of $26.7 million, which is not included in the table above. The table above also excludes consolidated restricted cash of $7.5 million, primarily at TECO Energy parent.

Tampa Electric’s liquidity position reflects its Sep. 30, 2008 $111 million under-recovery in its fuel and purchased power clause, which is projected to increase to approximately $133 million by year-end. Tampa Electric is seeking to recover the under-recovered 2008 fuel costs through the 2009 fuel adjustment process.

Potential Impacts of Financial Market Conditions

The current disruption in the capital and credit markets could adversely impact the availability and associated cost of externally sourced capital. Although TECO Energy (parent) does not expect to access the capital markets to meet its near-term needs and has no debt maturities until 2010, Tampa Electric expects to issue long-term debt before mid-year 2009 to support its capital spending program and to utilize its credit facilities for normal working capital needs.

The $200 million TECO Finance credit facility, which is guaranteed by TECO Energy, has a May 2012 maturity, and Tampa Electric’s $325 million credit facility also has a May 2012 maturity. All of the banks participating in the credit facilities are performing their obligations under these facilities and meeting our funding requests. Tampa Electric’s $150 million accounts receivable collateralized credit facility is scheduled for renewal in late 2008. In the current market, we expect that the facility will be renewed but at a higher cost.

Our exposure to the Lehman bankruptcy was minimal as Tampa Electric had open positions with Lehman at Sep. 30, 2008 related to a small amount of natural gas hedges that are currently out of the money. TECO Energy’s overall financial commodity trading activities are confined to natural gas hedges at the utilities and diesel fuel oil hedges at TECO Coal.

TECO Energy has minimal floating interest rate exposure. The TECO Energy floating rate notes ($100 million) are based on three-month LIBOR, and the bank credit facilities have a one-month LIBOR mode, with other modes also available. Tampa Electric can also borrow under its accounts receivable backed facility at conduit commercial paper rates. If current market conditions persist, Tampa Electric’s expected 2009 debt issue could be adversely impacted.

TECO Energy’s defined benefit plan assets were negatively impacted by unfavorable market conditions through Sep. 30, and market conditions further deteriorated in October. We currently expect to contribute $11.7 million to the plan in the fourth quarter of 2008. However, the market impact on TECO Energy’s asset values could increase its future plan funding requirements above those normally expected.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. TECO Energy, TECO Finance and Tampa Electric Company and the other operating companies are in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Sep. 30, 2008. Reference is made to the specific agreements and instruments for more details.

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Significant Financial Covenants

(millions, unless otherwise indicated) Instrument			Calculation at Sep. 30, 2008
	Financial Covenant(1)	Requirement/Restriction
Tampa Electric Company
PGS senior notes	EBIT/interest(2)	Minimum of 2.0 times		2.9 times
	Restricted payments	Shareholder equity at least $500	$	2,017
	Funded debt/capital	Cannot exceed 65%		49.6	%
	Sale of assets	Less than 20% of total assets		0	%
Credit facility(3)	Debt/capital	Cannot exceed 65%		48.7	%
Accounts receivable credit facility(3)	Debt/capital	Cannot exceed 65%		48.7	%
6.25% senior notes	Debt/capital	Cannot exceed 60%		48.7	%
	Limit on liens(5)	Cannot exceed $700	$	0 liens outstanding
Insurance agreements relating to certain pollution bonds	Limit on liens(5)	Cannot exceed $393 (7.5% of net assets)	$	0 liens outstanding
TECO Energy/TECO Finance
Credit facility(3)	Debt/EBITDA(2)	Cannot exceed 5.0 times		3.2 times
	EBITDA/interest(2)	Minimum of 2.6 times		4.6 times
	Limit on additional indebtedness	Cannot exceed $1,078	$	0
	Dividend restriction(4)	Cannot exceed $51 per quarter	$	43
TECO Energy 7.5% notes	Limit on liens(5)	Cannot exceed $281 (5% of tangible assets)	$	0 liens outstanding
TECO Energy floating rate and 6.75% notes and TECO Finance 6.75% notes	Restrictions on secured debt	(6)		(6)
TECO Diversified
Coal supply agreement guarantee	Dividend restriction	Net worth not less than $292 (40% of tangible net assets)	$	546

(1) As defined in each applicable instrument.

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

(3) See description of credit facilities inNote 6 to Amendment No. 1 to the 2007 TECO Energy, Inc. Annual Report on Form 10-K.

(4) TECO Energy cannot declare quarterly dividends in excess of the restricted amount unless liquidity projections demonstrating sufficient cash or cash equivalents to make each of the next three quarterly dividend payments are delivered to the Administrative Agent.

(5) If the limitation on liens is exceeded, the company is required to provide ratable security to the holders of these notes.

(6) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by Principal Property or Capital Stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes.

Credit Ratings of Senior Unsecured Debt at Sep. 30, 2008

	Standard & Poor’s	Moody’s	Fitch
Tampa Electric Company	BBB-	Baa2	BBB+
TECO Energy/TECO Finance	BB+	Baa3	BBB-

On Jun. 9, 2008, Standard & Poor’s Rating Services changed its outlook on TECO Energy, TECO Finance and Tampa Electric Company to positive from stable. At the same time, Standard & Poor’s affirmed the senior unsecured ratings on all three entities.

In March 2008, Fitch upgraded the ratings on TECO Energy and TECO Finance senior unsecured debt to investment grade at BBB-. In addition, Fitch removed TECO Energy, TECO Finance and Tampa Electric Company from ratings watch positive and placed stable outlooks on the ratings.

Fitch’s ratings upgrade of TECO Energy and TECO Finance reflects the leverage reduction resulting from the use of TECO Transport sale proceeds to reduce debt and from earlier debt reduction efforts. Fitch also cited TECO Energy’s reduced business risk resulting from sales of non-regulated operations and focus on utility operations as factors considered in the upgrade. Moody’s has assigned a positive outlook to Tampa Electric’s rating and a stable outlook to TECO Energy.

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Standard & Poor’s, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for Standard & Poor’s is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign Tampa Electric Company’s senior unsecured debt investment grade ratings. The ratings assigned to senior unsecured debt of TECO Energy and TECO Finance by Moody’s and Fitch are investment grade and by Standard & Poor’s are below investment grade.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Any future downgrades in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings.

Off-Balance Sheet Financing

Unconsolidated affiliates have project debt balances as follows at Sep. 30, 2008. TECO Energy has no debt payment obligations with respect to these financings. Although the company is not directly obligated on the debt, the equity interest in those unconsolidated affiliates is at risk if those projects are not operated successfully.

(millions)	Long-term Debt		Ownership Interest
San José Power Station	$	65.7	100	%
Alborada Power Station	$	6.5	96	%
DECA II	$	216.1	30	%

2008 Outlook

TECO Energy is maintaining its expectation that 2008 earnings per share will be in a range between $0.80 and $0.90, excluding any charges or gains. This range assumes a continuation of the current weak Florida economic and housing market conditions; normal weather for the remainder of the year; and that TECO Coal produces about 9.5 million tons at selling prices and production costs consistent with third quarter levels. This guidance also assumes that TECO Guatemala’s results include the current lower VAD at EEGSA for the remainder of the year.

Preliminary 2009 Outlook

The preliminary outlook for 2009 includes a strong outlook for TECO Coal, with production of about 10.5 million tons at much improved prices. Currently, 88% of expected 2009 production is contracted and priced at an average price of $77 per ton. All steam coal tons and a significant portion of pulverized coal injection (PCI) coal tons are contracted and priced. Recent market prices for similar quality metallurgical and PCI coals have averaged about $200 per ton. The remaining unpriced tons are 60% met and 40% PCI tons. Fully loaded production costs, including administrative and general and depreciation and depletion costs, are expected to be in a range between $65 and $75 per ton, primarily due to higher labor costs and higher costs for contract miners. TECO Coal has hedged the diesel fuel that it expects to consume in 2009 for contracted tons through oil swaps contracts or through contract terms. Strong operational performance at TECO Guatemala is expected to be partially offset by a scheduled major maintenance outage on the San José Power Station. Results for the distribution utility, EEGSA, are expected to be reduced by the significantly lower VAD rates that became effective Aug. 1, 2008 if current efforts to achieve a more satisfactory outcome are unsuccessful. Tampa Electric and Peoples Gas are in the early stages of their respective base rate increase proceedings, with audits and discovery underway at both companies. Assuming the proceedings follow the published schedules, new rates are expected to be effective in May at Tampa Electric and in June for Peoples Gas. The Florida economy and housing markets remain weak. Tampa Electric now forecasts that the recent turmoil in the financial industry and the tightening of lending standards will delay the housing market recovery, which is now not expected to start until the second half of 2010, compared to the previous estimates for the second half of 2009.

Fair Value Measurements

Effective Jan. 1, 2008, the company adopted SFAS No. 157,Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about financial assets and liabilities carried at fair value. The majority of the company’s financial assets and liabilities are in the form of natural gas, heating oil and interest rate derivatives classified as cash flow hedges and auction rate securities. The implementation of FAS 157 did not have a material impact on our results of operations, liquidity or capital.

All natural gas derivatives were entered into by the regulated utilities to manage the impact of natural gas prices on customers. As a result of applying the provisions of FAS 71, the changes in value of natural gas derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the risks of hedging activities in the fuel recovery clause. Because the amounts are deferred and ultimately collected through the fuel clause, the unrealized gains and losses associated with the valuation of these assets and liabilities do not impact our results of operations.

Heating oil hedges are used to mitigate the fluctuations in the price of diesel fuel which is a significant component in the cost of coal production at TECO Coal and its subsidiaries.

Interest rate derivatives at the regulated utilities were entered into in 2007 as a cash flow hedge to lock in a fixed rate on a debt issuance during the second quarter of 2008. The $11.8 million settlement of these instruments in May of 2008 was recorded in accumulated other comprehensive income and will be amortized to earnings over the life of the related debt.

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Other investments reflect two auction rate securities owned by TECO Guatemala with a combined par value of $15.0 million. As a result of market conditions, a temporary impairment was recorded in other comprehensive income. These are investment grade securities backed by pools of student loans. Therefore, it is expected that the investments will not be settled at a price less than par value. Because the company has the ability and intent to hold this investment until a recovery of its original investment value, it considers the investment to be temporarily impaired at Sep. 30, 2008.

The valuation methods we used to determine fair value are described inNote 13 to theTECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2008 the fair value of derivatives was not materially affected by nonperformance risk. Our net positions with substantially all counterparties were liability positions.

Critical Accounting Policies and Estimates

Our critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of our critical accounting policies, see our Annual Report on Form 10-K for the year ended Dec. 31, 2007.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are exposed to changes in interest rates primarily as a result of our borrowing activities. We 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.

In March 2008, Tampa Electric Company converted $191.8 million aggregate principal amount of tax-exempt bonds originally issued for its benefit in auction rate mode and remarketed them in long-term interest rate modes. In addition, Tampa Electric purchased in lieu of redemption $95.0 million aggregate value of tax exempt bonds previously in auction rate mode and held such bonds at Sep. 30, 2008, pending a determination of their disposition. The result of these transactions lowered our exposure to variable interest rate risk. For further discussion of our exposure to changes in interest rates, see the section titledPotential Impacts of Financial Market ConditionsinItem 2. Management’s Discussion & Analysis of Financial Condition and Results of Operationsabove.

Credit Risk

We are exposed to credit risk as a result of our purchases and sales of energy commodities and related hedging activities. See the section titledFair Value MeasurementsinItem 2. Management’s Discussion & Analysisabove for discussion on nonperformance risk related to the credit of our counterparties.

Commodity Risk

We 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 and do affect the net fair value of derivatives. We assess and monitor risk using a variety of measurement tools based on the degree of exposure of each operating company to commodity risk. Our most significant commodity risk exposures for the remainder of 2008 are the effect of diesel oil prices on the operating costs of TECO Coal and the potential effect of high natural gas prices on our cash flows. Prudently incurred costs for natural gas are recoverable through FPSC-approved cost recovery clauses, and therefore do not affect our earnings. However, higher than expected prices for natural gas can affect the timing of recovery and thus impact cash flows.

The change in fair value of derivatives is largely due to the addition of heating oil hedges in the third quarter of 2008 and the decrease in their value of approximately 18% subsequent to execution. For natural gas, the company maintains a similar volume hedged as of Sep. 30, 2008 from Dec. 31, 2007. The price of natural gas from Dec. 31, 2007 has increased approximately 10%.

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The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine months ended Sep. 30, 2008:

Changes in Fair Value of Derivatives (millions)
Net fair value of derivatives as of Dec. 31, 2007	$	(23.9	)
Additions and net changes in unrealized fair value of derivatives		(105.7	)
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		46.6
Net fair value of derivatives as of Sep. 30, 2008	$	(83.0	)
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2007	$	(23.9	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(105.7	)
Recorded in earnings		—
Realized net settlement of derivatives		46.6
Net option premium payments		—
Net purchase (sale) of existing contracts		—
Net fair value of derivatives as of Sep. 30, 2008	$	(83.0	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sep. 30, 2008:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Sep. 30, 2008 (millions)

Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value (millions)
Actively quoted prices	$	—		$	—		$	—
Other external sources(1)		(72.4	)		(10.6	)		(83.0	)
Model prices(2)		—			—			—
Total	$	(72.4	)	$	(10.6	)	$	(83.0	)

(1) Reflects over-the-counter natural gas swaps for which the primary pricing inputs in determining fair value are NYMEX quoted closing prices of exchange traded instruments.

(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 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.

Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

(a) Evaluation of Disclosure Controls and Procedures. TECO Energy’s management, with the participation of its principal executive officer and principal 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, TECO Energy’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. There was no change in TECO Energy’s internal control over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TECO Energy’s internal controls that occurred during TECO Energy’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Tampa Electric Company

(a) Evaluation of Disclosure Controls and Procedures. Tampa Electric Company’s management, with the participation of its principal executive officer and principal 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

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Exchange Act) as of the end of the Evaluation Date. Based on such evaluation, Tampa Electric Company’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, Tampa Electric Company’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. There was no change in Tampa Electric Company’s internal control over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of Tampa Electric Company’s internal controls that occurred during Tampa Electric Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

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PART II. OTHER INFORMATION

Item 1A. RISK FACTORS

Information regarding risk factors appears in Item 1A to the Annual Report on Form 10-K for the year ended Dec. 31, 2007 (“Annual Report”) of TECO Energy and Tampa Electric Company, as updated by Item 1A to their Quarterly Reports on Form 10-Q (“Quarterly Reports”). The risk factors described below update, and should be read in conjunction with, the risk factors identified in the Annual Report and Quarterly Reports.

The recent turmoil in the financial markets could limit our access to capital markets and increase our costs of borrowing or have other adverse effects on our results.

The recent turmoil in the financial markets has restricted the ability of almost all companies to borrow in short-term debt and commercial paper markets, the availability of long-term debt to many companies, and has increased interest rates for both short- and long-term debt. Although TECO Energy (parent) does not expect to access the capital markets to meet its near-term needs, Tampa Electric expects to issue long-term debt before mid-year 2009 to support its capital spending program. If the markets remain unstable, Tampa Electric’s ability to borrow might be limited or the interest rate that it pays could be higher than expected, which could reduce earnings. Tampa Electric’s $150 million accounts receivable collateralized credit facility is scheduled for renewal in late 2008. In the current market, it is expected that the facility will be renewed but at a higher cost.

If equity markets remain depressed, pension fund balances invested in equities could be reduced and additional cash contributions to the pension fund, above those normally expected, could be required.

We enter into derivative transactions with counterparties, most of which are financial institutions, to hedge our exposure to commodity price changes. Although we believe we have appropriate credit policies in place to manage the non-performance risk associated with these transactions, the recent turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which we have an in-the-money position, we could be unable to collect from such counterparty.

If efforts to have the recent VAD tariff decision at EEGSA recalculated or revised are unsuccessful, earnings and cash flow from that company would be at risk as long as the current lower VAD remains in place.

We are working with EEGSA and its other investors to actively pursue legal and other avenues to facilitate reconsideration of the level of the VAD consistent with EEGSA’s interpretation of Guatemala’s Electricity Law. If these efforts are unsuccessful, all of EEGSA’s earnings contribution to TECO Guatemala, estimated to be a minimum of $10 million annually, could be at risk as long as the lower VAD remains in effect.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table shows the number of shares of TECO Energy common stock deemed to have been repurchased by TECO Energy.

	(a) Total Number of Shares (or Units) Purchased(1)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Jul. 1, 2008 – Jul. 31, 2008	2,431	$	19.46	—	—
Aug. 1, 2008 – Aug. 31, 2008	8,214	$	17.68	—	—
Sep. 1, 2008 – Sep. 30, 2008	4,561	$	16.07	—	—
Total 3rd Quarter 2008	15,206	$	17.48	—	—

(1) These shares were not repurchased through a publicly announced plan or program, but rather relate to compensation or retirement plans of the company. Specifically, these shares represent shares delivered in satisfaction of the

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exercise price and/or tax withholding obligations by holders of stock options who exercised options (granted under TECO Energy’s incentive compensation plans), shares delivered or withheld (under the terms of grants under TECO Energy’s incentive compensation plans) to offset tax withholding obligations associated with the vesting of restricted shares and shares purchased by the TECO Energy Group Retirement Savings Plan pursuant to directions from plan participants or dividend reinvestment.

Item 6. EXHIBITS

Exhibits - See index on page 60.

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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.

	TECO ENERGY, INC.
	(Registrant)
Date: October 31, 2008	By:	/s/ G. L. GILLETTE
		G. L. GILLETTE
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: October 31, 2008	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
3.1	*	Articles of Incorporation of TECO Energy, Inc., as amended on Apr. 20, 1993 (Exhibit 3, Form 10-Q for the quarter ended Mar. 31, 1993 of TECO Energy, Inc.).
3.2	*	Bylaws of TECO Energy, Inc., as amended effective Jan. 30, 2008 (Exhibit 3.1, Form 8-K dated Jan. 30, 2008 of TECO Energy, Inc.).
3.3	*	Articles of Incorporation of Tampa Electric Company (Exhibit 3, Registration Statement No. 2-70653 of Tampa Electric Company).
3.4	*	Bylaws of Tampa Electric Company, as amended effective Jan. 30, 2008 (Exhibit 3.4, Form 10-K for 2007 of TECO Energy, Inc. and Tampa Electric Company).
10.1		Form of Change-in-Control Severance Agreement between TECO Energy, Inc. and its executive officers, as amended and restated as of July 30, 2008.
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(a) and 15d-14(a) 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(a) and 15d-14(a) 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(a) and 15d-14(a) 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 pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) 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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