TECO Energy 10-Q 2008 Q2 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 June 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 Jul. 28, 2008 was 212,737,991. As of Jul. 28, 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 55

Index to Exhibits appears on page 55.

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 Jun. 30, 2008 and Dec. 31, 2007, and the results of their operations and cash flows for the periods ended Jun. 30, 2008 and 2007. The results of operations for the three month and six month periods ended Jun. 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 24 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Jun. 30, 2008 and Dec. 31, 2007	3-4
Consolidated Condensed Statements of Income for the three month and six month periods ended Jun. 30, 2008 and 2007	5-6
Consolidated Condensed Statements of Comprehensive Income for the three month and six month periods ended Jun. 30, 2008 and 2007	7
Consolidated Condensed Statements of Cash Flows for the six month periods ended Jun. 30, 2008 and 2007	8
Notes to Consolidated Condensed Financial Statements	9-24

2

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	Jun. 30,			Dec. 31,
(millions, except for share amounts)	2008			2007
Current assets
Cash and cash equivalents	$	171.8		$	162.6
Restricted cash		7.5			7.4
Short-term investments		2.4			—
Receivables, less allowance for uncollectibles of $3.9 and $3.3 at Jun. 30, 2008 and Dec. 31, 2007, respectively		330.8			295.9
Crude oil options receivable, net		—			78.5
Inventories, at average cost
Fuel		92.6			85.8
Materials and supplies		69.3			68.2
Current regulatory assets		138.5			67.4
Current derivative assets		142.8			0.3
Prepayments and other current assets		25.1			23.0
Income tax receivables		0.2			0.7
Total current assets		981.0			789.8
Property, plant and equipment
Utility plant in service
Electric		5,388.4			5,275.2
Gas		935.0			917.4
Construction work in progress		365.9			364.8
Other property		348.6			336.4
Property, plant and equipment		7,037.9			6,893.8
Accumulated depreciation		(2,028.6	)		(2,005.6	)
Total property, plant and equipment, net		5,009.3			4,888.2
Other assets
Deferred income taxes		384.8			424.9
Other investments		22.0			22.9
Long-term regulatory assets		184.5			186.8
Long-term derivative assets		24.8			1.9
Investment in unconsolidated affiliates		269.2			275.5
Goodwill		59.4			59.4
Deferred charges and other assets		118.6			115.8
Total other assets		1,063.3			1,087.2
Total assets	$	7,053.6		$	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	Jun. 30,			Dec. 31,
(millions, except for share amounts)	2008			2007
Current liabilities
Long-term debt due within one year
Recourse	$	5.7		$	5.7
Non-recourse		1.4			1.4
Notes payable		—			25.0
Accounts payable		356.6			302.1
Customer deposits		142.9			138.1
Current regulatory liabilities		174.8			35.4
Current derivative liabilities		—			26.0
Interest accrued		47.7			32.7
Taxes accrued		48.4			33.2
Other current liabilities		15.3			18.0
Total current liabilities		792.8			617.6
Other liabilities
Investment tax credits		11.2			12.2
Long-term regulatory liabilities		611.1			582.7
Long-term derivative liabilities		0.4			0.1
Deferred credits and other liabilities		398.3			377.2
Long-term debt, less amount due within one year
Recourse		3,204.4			3,149.4
Non-recourse		7.7			9.0
Total other liabilities		4,233.1			4,130.6
Commitments and contingencies (seeNote 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 212.7 million shares and 210.9 million shares outstanding at Jun. 30, 2008 and Dec. 31, 2007, respectively)		212.7			210.9
Additional paid in capital		1,512.9			1,489.2
Retained earnings		332.9			334.1
Accumulated other comprehensive loss		(30.8	)		(17.2	)
Total capital		2,027.7			2,017.0
Total liabilities and capital	$	7,053.6		$	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 Jun. 30,
(millions, except per share amounts)	2008			2007
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $27.6 in 2008 and $27.0 in 2007)	$	730.0		$	687.5
Unregulated		157.2			179.0
Total revenues		887.2			866.5
Expenses
Regulated operations
Fuel		176.2			207.3
Purchased power		115.9			69.5
Cost of natural gas sold		133.8			92.5
Other		71.9			68.4
Operation other expense
Mining related costs		116.8			100.0
Waterborne transportation costs		—			54.3
Other		5.6			4.1
Maintenance		45.6			47.4
Depreciation and amortization		64.9			66.8
Taxes, other than income		54.1			55.0
Transaction related costs		—			13.5
Total expenses		784.8			778.8
Income from operations		102.4			87.7
Other income
Allowance for other funds used during construction		1.7			1.1
Other income		4.0			22.6
Income from equity investments		21.6			18.7
Total other income		27.3			42.4
Interest charges
Interest expense		56.6			66.1
Allowance for borrowed funds used during construction		(0.7	)		(0.4	)
Total interest charges		55.9			65.7
Income before provision for income taxes		73.8			64.4
Provision for income taxes		22.4			25.3
Income before minority interest		51.4			39.1
Minority interest		—			20.3
Income from continuing operations		51.4			59.4
Discontinued operations
Income tax benefit		—			(14.3	)
Total discontinued operations		—			14.3
Net income	$	51.4		$	73.7
Average common shares outstanding – Basic		210.4			208.9
– Diluted		212.1			210.0
Earnings per share from continuing operations– Basic	$	0.24		$	0.28
– Diluted	$	0.24		$	0.28
Earnings per share from discontinued operations – Basic	$	—		$	0.07
– Diluted	$	—		$	0.07
Earnings per share – Basic	$	0.24		$	0.35
– Diluted	$	0.24		$	0.35
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

	Six months ended Jun. 30,
(millions, except per share amounts)	2008			2007
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $54.0 in 2008 and $54.0 in 2007)	$	1,370.2		$	1,328.1
Unregulated		308.7			359.7
Total revenues		1,678.9			1,687.8
Expenses
Regulated operations
Fuel		339.8			396.4
Purchased power		197.8			123.1
Cost of natural gas sold		252.8			200.2
Other		143.2			126.0
Operation other expense
Mining related costs		224.0			194.5
Waterborne transportation costs		—			109.0
Other		9.9			7.6
Maintenance		91.6			96.4
Depreciation		129.9			138.4
Taxes, other than income		109.0			113.8
Transaction related costs		0.9			16.3
Total expenses		1,498.9			1,521.7
Income from operations		180.0			166.1
Other income
Allowance for other funds used during construction		3.0			2.8
Other income		9.3			74.5
Income from equity investments		39.0			34.9
Total other income		51.3			112.2
Interest charges
Interest expense		114.8			133.9
Allowance for borrowed funds used during construction		(1.2	)		(1.1	)
Total interest charges		113.6			132.8
Income before provision for income taxes		117.7			145.5
Provision for income taxes		35.5			57.1
Income before minority interest		82.2			88.4
Minority interest		—			43.8
Income from continuing operations		82.2			132.2
Discontinued operations
Income tax benefit		—			(14.3	)
Total discontinued operations		—			14.3
Net income	$	82.2		$	146.5
Average common shares outstanding – Basic		210.1			208.8
– Diluted		211.6			209.7
Earnings per share from continuing operations– Basic	$	0.39		$	0.63
– Diluted	$	0.39		$	0.63
Earnings per share from discontinued operations – Basic	$	—		$	0.07
– Diluted	$	—		$	0.07
Earnings per share – Basic	$	0.39		$	0.70
– Diluted	$	0.39		$	0.70
Dividends paid per common share outstanding	$	0.395		$	0.385

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 Jun. 30,						Six months ended Jun. 30,
(millions)	2008			2007			2008			2007
Net income	$	51.4		$	73.7		$	82.2		$	146.5
Other comprehensive income (loss), net of tax
Net unrealized gains (losses) on cash flow hedges		3.9			0.6			(2.1	)		2.5
Amortization of unrecognized benefit costs		(0.1	)		0.7			0.3			1.1
Recognized benefit costs due to curtailment		—			4.1			—			4.1
Change in benefit obligations due to remeasurement		—			(1.3	)		(10.8	)		(1.3	)
Unrealized loss on available-for-sale securities		—			—			(1.0	)		—
Other comprehensive (loss) income, net of tax		3.8			4.1			(13.6	)		6.4
Comprehensive income	$	55.2		$	77.8		$	68.6		$	152.9

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended Jun. 30,
(millions)	2008			2007
Cash flows from operating activities
Net income	$	82.2		$	146.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		129.9			138.4
Deferred income taxes		39.7			37.6
Investment tax credits, net		(1.0	)		(1.3	)
Allowance for funds used during construction		(3.0	)		(2.8	)
Non-cash stock compensation		6.1			7.4
Gain on sale of business/assets, pretax		(1.1	)		(44.5	)
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		(6.8	)		(13.9	)
Minority interest		—			(43.8	)
Derivatives marked-to-market		—			(12.3	)
Deferred recovery clauses		(92.4	)		26.7
Receivables, less allowance for uncollectibles		(34.0	)		7.1
Inventories		(7.9	)		(66.7	)
Prepayments and other current assets		(2.1	)		(2.4	)
Taxes accrued		15.7			45.7
Interest accrued		15.0			0.8
Accounts payable		76.9			(21.4	)
Other		21.3			32.6
Cash flows from operating activities		238.5			233.7
Cash flows from investing activities
Capital expenditures		(265.7	)		(272.1	)
Allowance for funds used during construction		3.0			2.8
Net (settlement) proceeds from sale of business/assets		(7.3	)		45.5
Distributions from unconsolidated affiliates		13.2			14.0
Other investments		76.2			(46.2	)
Cash flows used in investing activities		(180.6	)		(256.0	)
Cash flows from financing activities
Dividends		(83.5	)		(80.8	)
Proceeds from the sale of common stock		20.0			8.4
Proceeds from long-term debt		327.9			321.0
Repayment of long-term debt/Purchase in lieu of redemption		(288.1	)		(447.8	)
Minority interest		—			47.8
Net decrease in short-term debt		(25.0	)		(48.0	)
Cash flows used in financing activities		(48.7	)		(199.4	)
Net increase (decrease) in cash and cash equivalents		9.2			(221.7	)
Cash and cash equivalents at beginning of period		162.6			441.6
Cash and cash equivalents at end of period	$	171.8		$	219.9

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 Jun. 30, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Jun. 30, 2008 and 2007. The results of operations for the three month and six month periods ended Jun. 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 Jun. 30, 2008 and Dec. 31, 2007, unbilled revenues of $52.3 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 Jun. 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 six month period ended Jun. 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 six month periods ended Jun. 30, 2007, “Other income” reflected an estimated phase-out of approximately 19%, or $12.1 million and $18.7 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 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 $115.9 million and $197.8 million for the three months and six months ended Jun. 30, 2008, respectively, compared to $69.5 million and $123.1 million for the three months and six months ended Jun. 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 $27.6 million and $54.0 million, respectively, for the three months and six months ended Jun. 30, 2008, compared to $27.0 million and $54.0 million, respectively, for the three months and six months ended Jun. 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 $27.6 million and $53.8 million, respectively, for the three months and six months ended Jun. 30, 2008, compared to $27.0 million and $53.9 million, respectively, for the three months and six months ended Jun. 30, 2007.

2. New Accounting Pronouncements

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

In June 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 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 December 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 material 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.

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.

10

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 Emerging Issues Task Force (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 FASB Staff Position (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 Jun. 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

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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.

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 six months ended Jun. 30, 2008, approximately 2,500 and 5,000 allowances were sold, respectively, resulting in proceeds of $1.0 million and $2.0 million, respectively. During the three months ended Jun. 30, 2007, approximately 35,000 allowances were sold resulting in proceeds of $17.5 million. There were no SO₂allowances sold in the first quarter of 2007.

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 Jun. 30, 2008 and Dec. 31, 2007 are presented in the following table:

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Regulatory Assets and Liabilities (millions)	Jun. 30, 2008		Dec. 31, 2007
Regulatory assets:
Regulatory tax asset(1)	$	65.0	$	62.5
Other:
Cost recovery clauses		118.8		47.2
Postretirement benefit asset		94.7		97.5
Deferred bond refinancing costs(2)		23.6		25.5
Environmental remediation		11.4		11.4
Competitive rate adjustment		4.7		5.4
Other		4.8		4.7
Total other regulatory assets		258.0		191.7
Total regulatory assets		323.0		254.2
Less: Current portion		138.5		67.4
Long-term regulatory assets	$	184.5	$	186.8
Regulatory liabilities:
Regulatory tax liability(1)	$	18.5	$	18.8
Other:
Deferred allowance auction credits		0.1		0.1
Cost recovery clauses		180.7		18.9
Environmental remediation		11.4		11.4
Transmission and delivery storm reserve		22.3		20.3
Deferred gain on property sales(3)		3.7		4.7
Accumulated reserve-cost of removal		548.7		543.5
Other		0.5		0.4
Total other regulatory liabilities		767.4		599.3
Total regulatory liabilities		785.9		618.1
Less: Current portion		174.8		35.4
Long-term regulatory liabilities	$	611.1	$	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)	Jun. 30, 2008		Dec. 31, 2007
Clause recoverable(1)	$	123.5	$	52.6
Earning a rate of return(2)		99.0		101.7
Regulatory tax assets(3)		65.0		62.5
Capital structure and other(3)		35.5		37.4
Total	$	323.0	$	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 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 six month periods ended Jun. 30, 2008, the company recorded approximately $0.4 million and $0.6 million, respectively, of pre-tax charges for interest only. During the second quarter of 2007, the company recognized a $14.3 million benefit in discontinued operations as a result of reaching favorable conclusions with the taxing authorities upon the completion of their review of the company’s 2005 tax return during the second quarter of 2007. No amounts have been recorded for penalties for the six month periods ended Jun. 30, 2008 and Jun. 30, 2007.

During the six month periods ended Jun. 30, 2008 and Jun. 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 six months ended Jun. 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 Jun. 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		—			—			0.6		0.7
Prior service (benefit) cost		(0.1	)		(0.1	)		0.4		0.7
Actuarial loss		1.0			2.3			—		—
Pension expense		3.0			5.3			5.0		5.7
Curtailment cost		—			0.3			—		6.5
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	3.0		$	5.6		$	5.0	$	12.2
Six months ended Jun. 30,
Components of net periodic benefit expense
Service cost	$	7.7		$	8.0		$	2.1	$	2.6
Interest cost on projected benefit obligations		15.9			16.4			6.0		6.0
Expected return on assets		(19.5	)		(18.2	)		—		—
Amortization of:
Transition obligation		—			—			1.2		1.4
Prior service (benefit) cost		(0.2	)		(0.2	)		0.8		1.4
Actuarial loss		2.0			4.6			—		—
Pension expense		5.9			10.6			10.1		11.4
Settlement cost		0.9			—			—		—
Curtailment cost		—			0.3			—		6.5
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	6.8		$	10.9		$	10.1	$	17.9

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 six months ended Jun. 30, 2008, TECO Energy and its subsidiaries reclassed $0.5 million and $1.1 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 $1.0 million and $2.1 million, respectively, for the same periods ended Jun. 30, 2007. In addition, during the three months and six months ended Jun. 30, 2008, Tampa Electric Company reclassed $1.4 million and $2.8 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 $5.0 million for the same periods ended Jun. 30, 2007.

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6. Short-Term Debt

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

	Jun. 30, 2008						Dec. 31, 2007
Credit Facilities (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		—		—		150.0		25.0		—
TECO Energy/TECO Finance:
5-year facility(2)		200.0		—		9.5		200.0		—		9.5
Total	$	675.0	$	—	$	10.9	$	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 Dec. 31, 2007 was 4.76%. There were no borrowings outstanding as of Jun. 30, 2008.

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 income” 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.

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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 Jun. 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 six months ended Jun. 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 Jun. 30,									Six months ended Jun. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2008
Unrealized gain (loss) on cash flow hedges	$	5.7		$	(2.1	)	$	3.6		$	(4.0	)	$	1.5		$	(2.5	)
Add: Loss reclassified to net income		0.5			(0.2	)		0.3			0.6			(0.2	)		0.4
Gain (loss) on cash flow hedges		6.2			(2.3	)		3.9			(3.4	)		1.3			(2.1	)
Amortization of unrecognized benefit costs		0.5			(0.6	)		(0.1	)		1.1			(0.8	)		0.3
Change in benefit obligation due to remeasurement		—			—			—			(17.6	)		6.8			(10.8	)
Unrealized loss on available-for-sale securities(1)		—			—			—			(1.0	)		—			(1.0	)
Total other comprehensive income (loss)	$	6.7		$	(2.9	)	$	3.8		$	(20.9	)	$	7.3		$	(13.6	)
2007
Unrealized gain on cash flow hedges	$	1.8		$	(0.7	)	$	1.1		$	4.5		$	(1.7	)	$	2.8
Less: Gain reclassified to net income		(0.8	)		0.3			(0.5	)		(0.5	)		0.2			(0.3	)
Gain on cash flow hedges		1.0			(0.4	)		0.6			4.0			(1.5	)		2.5
Amortization of unrecognized benefit costs		1.1			(0.4	)		0.7			2.2			(1.1	)		1.1
Recognized benefit costs due to curtailment		6.7			(2.6	)		4.1			6.7			(2.6	)		4.1
Change in benefit obligation due to remeasurement		(2.1	)		0.8			(1.3	)		(2.1	)		0.8			(1.3	)
Total other comprehensive income	$	6.7		$	(2.6	)	$	4.1		$	10.8		$	(4.4	)	$	6.4

Accumulated Other Comprehensive Income (Loss)
(millions)	Jun. 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)		2.6			2.3
Net unrealized losses from cash flow hedges(4)		(8.3	)		(6.2	)
Net unrecognized loss on available-for-sale securities		(1.0	)		—
Total accumulated other comprehensive loss	$	(30.8	)	$	(17.2	)

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

(2) Net of tax benefit of $14.6 million and $8.3 million as of Jun. 30, 2008 and Dec. 31, 2007, respectively.

(3) Net of tax expense of $1.7 million and $1.5 million as of Jun. 30, 2008 and Dec. 31, 2007, respectively.

(4) Net of tax benefit of $5.1 million and $3.8 million as of Jun. 30, 2008 and Dec. 31, 2007, respectively.

9. Earnings Per Share

For the three months and six months ended Jun. 30, 2008, stock options of 4.2 million and 4.5 million shares, respectively, were excluded from the computation of diluted earnings per share due to their antidilutive effect. Stock options of 4.8 million and 5.8 million shares for the three months and six months ended Jun. 30, 2007, respectively, were similarly excluded from the computation.

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	Three months ended Jun. 30,						Six months ended Jun. 30,
(millions, except per share amounts)	2008			2007			2008			2007
Numerator
Net income from continuing operations, basic and diluted	$	51.4		$	59.4		$	82.2		$	132.2
Discontinued operations, net of tax		—			14.3			—			14.3
Net income, diluted	$	51.4		$	73.7		$	82.2		$	146.5
Denominator
Average number of shares outstanding – basic		210.4			208.9			210.1			208.8
Plus: Incremental shares for assumed conversions:
Stock options and contingent performance shares		5.3			5.1			5.3			3.8
Less: Treasury shares which could be purchased		(3.6	)		(4.0	)		(3.8	)		(2.9	)
Average number of shares outstanding – diluted		212.1			210.0			211.6			209.7
Earnings per share from continuing operations
Basic	$	0.24		$	0.28		$	0.39		$	0.63
Diluted	$	0.24		$	0.28		$	0.39		$	0.63
Earnings per share from discontinued operations, net
Basic	$	—		$	0.07		$	—		$	0.07
Diluted	$	—		$	0.07		$	—		$	0.07
Earnings per share
Basic	$	0.24		$	0.35		$	0.39		$	0.70
Diluted	$	0.24		$	0.35		$	0.39		$	0.70

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.

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 Jun. 30, 2008, Tampa Electric Company has estimated its ultimate financial liability to be approximately $11.5 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.

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Guarantees and Letters of Credit

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

Letters of Credit and Guarantees

(millions)	2008		2009-2012		After(1) 2012		Total		Liabilities Recognized at Jun. 30, 2008
Letters of Credit and Guarantees for the Benefit of:
Tampa Electric
Letters of credit	$	—	$	—	$	0.3	$	0.3	$	—
Guarantees:
Fuel purchase/energy management(2)		—		—		20.0		20.0		3.8
		—		—		20.3		20.3		3.8
TECO Coal
Letters of credit		—		—		6.7		6.7		—
Guarantees: Fuel purchase related(2)		—		—		1.4		1.4		1.4
		—		—		8.1		8.1		1.4
Other subsidiaries
Guarantees:
Fuel purchase/energy management(2)		60.3		—		3.9		64.2		—
Unaffiliated parties
Letters of credit(3)		2.5		—		—		2.5		—
Total	$	62.8	$	—	$	32.3	$	95.1	$	5.2

(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 Jun. 30, 2008. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) TECO Transport was sold effective Dec. 4, 2007. These letters of credit were replaced by the purchaser in 2008 pursuant to the terms of the sale, and will be cancelled by the issuing bank upon receipt of authorization from the beneficiary.

Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Jun. 30, 2008, management believes that TECO Energy, 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) Three months ended Jun. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO (2) Guatemala		TECO(3) Transport			Other & Eliminations			TECO Energy
2008
Revenues - external	$	545.7	$	184.3	$	155.2	$	2.0	$	—		$	—		$	887.2
Sales to affiliates		0.4		—		—		—		—			(0.4	)		—
Total revenues		546.1		184.3		155.2		2.0		—			(0.4	)		887.2
Equity earnings of unconsolidated affiliates		—		—		—		21.6		—			—			21.6
Depreciation		45.0		10.3		9.3		0.2		—			0.1			64.9
Total interest charges(1)		27.9		4.5		2.0		3.7		—			17.8			55.9
Internally allocated interest(1)		—		—		1.5		3.6		—			(5.1	)		—
Provision (benefit) for taxes		23.6		3.4		0.2		2.1		—			(6.9	)		22.4
Net income (loss) from continuing operations	$	40.2	$	5.3	$	4.2	$	14.9	$	—		$	(13.2	)	$	51.4
2007
Revenues - external	$	544.3	$	143.2	$	127.1	$	2.1	$	49.6		$	0.2		$	866.5
Sales to affiliates		0.4		—		—		—		28.3			(28.7	)		—
Total revenues		544.7		143.2		127.1		2.1		77.9			(28.5	)		866.5
Equity earnings of unconsolidated affiliates		—		—		—		18.7		—			—			18.7
Depreciation		47.3		10.0		9.1		0.2		—			0.2			66.8
Total interest charges(1)		28.5		4.3		3.3		3.7		1.2			24.7			65.7
Internally allocated interest(1)		—		—		3.1		3.6		(0.2	)		(6.5	)		—
Provision (benefit) for taxes		19.4		3.4		7.7		2.1		4.7			(12.0	)		25.3
Net income (loss) from continuing operations	$	34.7	$	5.4	$	20.8	$	12.8	$	9.6		$	(23.9	)	$	59.4
(millions) Six months ended Jun. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO (2) Guatemala		TECO(3) Transport			Other & Eliminations			TECO Energy
2008
Revenues - external	$	1,006.9	$	363.3	$	304.3	$	4.3	$	—		$	0.1		$	1,678.9
Sales to affiliates		0.7		—		—		—		—			(0.7	)		—
Total revenues		1,007.6		363.3		304.3		4.3		—			(0.6	)		1,678.9
Equity earnings of unconsolidated affiliates		—		—		—		39.0		—			—			39.0
Depreciation		90.2		20.6		18.5		0.4		—			0.2			129.9
Total interest charges(1)		57.3		8.7		4.5		7.5		—			35.6			113.6
Internally allocated interest(1)		—		—		3.8		7.4		—			(11.2	)		—
Provision (benefit) for taxes		32.1		9.8		2.1		4.0		—			(12.5	)		35.5
Net income (loss) from continuing operations	$	56.1	$	15.3	$	11.7	$	25.4	$	—		$	(26.3	)	$	82.2
2007
Revenues - external	$	1,015.7	$	312.4	$	254.6	$	4.0	$	100.9		$	0.2		$	1,687.8
Sales to affiliates		0.9		—		—		—		52.3			(53.2	)		—
Total revenues		1,016.6		312.4		254.6		4.0		153.2			(53.0	)		1,687.8
Equity earnings of unconsolidated affiliates		—		—		—		34.8		0.1			—			34.9
Depreciation		93.7		19.8		18.6		0.4		5.6			0.3			138.4
Total interest charges(1)		55.3		8.4		6.1		7.5		2.6			52.9			132.8
Internally allocated interest(1)		—		—		5.7		7.3		(0.4	)		(12.6	)		—
Provision (benefit) for taxes		30.4		10.3		27.7		3.4		6.2			(20.9	)		57.1
Net income (loss) from continuing operations	$	56.5	$	16.4	$	63.2	$	23.1	$	16.0		$	(43.0	)	$	132.2

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Segment Information(1)	Tampa		Peoples		TECO		TECO(2)		Other &		TECO
(millions)	Electric		Gas		Coal		Guatemala		Eliminations		Energy
At Jun. 30, 2008
Goodwill	$	—	$	—	$	—	$	59.4	$	—	$	59.4
Investment in unconsolidated affiliates		—		—		—		269.2		—		269.2
Other non-current investments		—		—		—		14.0		8.0		22.0
Total assets	$	5,274.0	$	888.6	$	297.5	$	440.0	$	153.5	$	7,053.6
At Dec. 31, 2007
Goodwill	$	—	$	—	$	—	$	59.4	$	—	$	59.4
Investment in unconsolidated affiliates		—		—		—		275.5		—		275.5
Other non-current investments		—		—		—		15.0		8.0		23.0
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 $29.6 million and $30.3 million for the three months ended Jun. 30, 2008 and 2007, respectively and $59.5 million and $59.6 million for the six months ended Jun. 30, 2008 and 2007, respectively.

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

12. Derivatives and Hedging

At Jun. 30, 2008, TECO Energy and its affiliates had total derivative assets and liabilities (current and non-current) of $167.6 million and $0.4 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 Jun. 30, 2008 and Dec. 31, 2007, accumulated other comprehensive income (AOCI) included after-tax losses of $8.3 million and $6.2 million, respectively, representing the fair value of cash flow hedges of transactions that will occur in the future. Amounts recorded in AOCI at Jun. 30, 2008 and Dec. 31, 2007 relate to interest rate swaps. The balance at Jun. 30, 2008 is primarily comprised of interest rate swaps settled coincident with debt issued in May of 2008 (seeNote 7, Long-Term Debt). These amounts will be amortized into earnings over the life of the related debt.

For the three months ended Jun. 30, 2008 and 2007, TECO Energy and its affiliates reclassified amounts from AOCI and recognized net pretax losses of $0.5 million and net pretax gains of $0.8 million, respectively. For the six months ended Jun. 30, 2008 and 2007, the amounts reclassified and recognized from AOCI were net pretax losses of $0.6 million and net pretax gains of $0.5 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 higher 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 $2.3 million from AOCI to the Consolidated Condensed Statements of Income within the next twelve months. These amounts relate to settled interest rate 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 Jun. 30, 2008, net pretax gains of $142.8 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 six months ended Jun. 30, 2007, the company recognized a pretax (loss) gain of $(6.5) million and $12.3 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 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 Issue 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 Issue 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 Jun. 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 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 Jun. 30, 2008
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	—	$	167.6	$	—	$	167.6
Other investments		—		—		14.0		14.0
Total	$	—	$	167.6	$	14.0	$	181.6
Liabilities
Natural gas swaps	$	—	$	0.4	$	—	$	0.4
Total	$	—	$	0.4	$	—	$	0.4

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 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. An additional $1.7 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.

23

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. 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 investments are highly rated and significantly backed by a pool 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 Jun. 30, 2008.

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

The $11.8 million settled in the second quarter of 2008 related to forward starting interest rate swaps settled in conjunction with our May 2008 issuance of the related 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 cash to an unaffiliated investment group. 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 six months ended Jun. 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 Jun. 30, 2007, depreciation of $5.6 million would have been recorded had the assets of TECO Transport not been held for sale. For the three months and six months ended Jun. 30, 2007, TECO Energy recognized $13.5 million and $16.3 million, respectively, in transaction-related costs related to the then potential sale.

For the three months and six months ended Jun. 30, 2008, Tampa Electric paid United Maritime Group, formerly TECO Transport Corporation, $19.1 million and $43.7 million, respectively, for the waterborne transportation services described above. For the three months and six months ended Jun. 30, 2007, Tampa Electric paid TECO Transport $28.3 million and $52.3 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 Jun. 30, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Jun. 30, 2008 and 2007. The results of operations for the three months and six months ended Jun. 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 31-41 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Jun. 30, 2008 and Dec. 31, 2007	26-27
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended Jun. 30, 2008 and 2007	28-29
Consolidated Condensed Statements of Cash Flows for the six month periods ended Jun. 30, 2008 and 2007	30
Notes to Consolidated Condensed Financial Statements	31-41

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Jun. 30, 2008			Dec. 31, 2007
Property, plant and equipment
Utility plant in service
Electric	$	5,375.0		$	5,262.0
Gas		935.0			917.4
Construction work in progress		364.8			363.6
Property, plant and equipment, at original costs		6,674.8			6,543.0
Accumulated depreciation		(1,817.4	)		(1,808.6	)
		4,857.4			4,734.4
Other property		4.5			4.5
Total property, plant and equipment, net		4,861.9			4,738.9
Current assets
Cash and cash equivalents		60.1			11.9
Receivables, less allowance for uncollectibles of $2.0 and $1.4 at Jun. 30, 2008 and Dec. 31, 2007, respectively		280.2			238.8
Inventories, at average cost
Fuel		78.6			66.2
Materials and supplies		59.0			58.0
Current regulatory assets		138.5			67.4
Current derivative assets		142.8			0.3
Taxes receivable		—			2.9
Prepayments and other current assets		16.8			11.6
Total current assets		776.0			457.1
Deferred debits
Unamortized debt expense		23.6			22.9
Long-term regulatory assets		184.5			186.8
Long-term derivative assets		24.8			1.9
Other		13.0			11.7
Total deferred debits		245.9			223.3
Total assets	$	5,883.8		$	5,419.3

26

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets– continued

Unaudited

Liabilities and Capital (millions)	Jun. 30, 2008			Dec. 31, 2007
Capital
Common stock	$	1,660.4		$	1,510.4
Accumulated other comprehensive loss		(7.2	)		(5.0	)
Retained earnings		295.3			295.6
Total capital		1,948.5			1,801.0
Long-term debt, less amount due within one year		1,900.0			1,844.8
Total capitalization		3,848.5			3,645.8
Current liabilities
Long-term debt due within one year		5.7			5.7
Notes payable		—			25.0
Accounts payable		316.1			237.6
Customer deposits		142.9			138.1
Current regulatory liabilities		174.8			35.4
Current derivative liabilities		—			26.0
Current deferred income taxes		2.2			0.3
Interest accrued		30.3			23.5
Taxes accrued		39.4			16.8
Other		11.2			11.3
Total current liabilities		722.6			519.7
Deferred credits
Non-current deferred income taxes		435.7			407.5
Investment tax credits		11.2			12.0
Long-term derivative liabilities		0.4			0.1
Long-term regulatory liabilities		611.1			582.7
Other		254.3			251.5
Total deferred credits		1,312.7			1,253.8
Total liabilities and capital	$	5,883.8		$	5,419.3

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

(millions, except per share amounts)	Three months ended Jun. 30,
	2008			2007
Revenues
Electric (includes franchise fees and gross receipts taxes of $21.5 in 2008 and $21.0 in 2007)	$	546.0		$	544.7
Gas (includes franchise fees and gross receipts taxes of $6.1 in 2008 and $6.0 in 2007)		184.3			143.1
Total revenues		730.3			687.8
Expenses
Operations
Fuel		176.2			235.6
Purchased power		115.9			69.5
Cost of natural gas sold		133.8			92.5
Other		71.9			68.3
Maintenance		32.3			29.6
Depreciation		55.3			57.3
Taxes, federal and state		26.4	��		22.1
Taxes, other than income		44.3			44.1
Total expenses		656.1			619.0
Income from operations		74.2			68.8
Other income
Allowance for other funds used during construction		1.7			1.1
Taxes, non-utility federal and state		(0.6	)		(0.7	)
Other income, net		2.5			3.7
Total other income		3.6			4.1
Interest charges
Interest on long-term debt		30.2			30.0
Other interest		2.8			3.2
Allowance for borrowed funds used during construction		(0.7	)		(0.4	)
Total interest charges		32.3			32.8
Net income	$	45.5		$	40.1
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges		2.8			—
Other comprehensive loss, net of tax		2.8			—
Comprehensive Income	$	48.3		$	40.1

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income

Unaudited

(millions, except per share amounts)	Six months ended Jun. 30,
	2008			2007
Revenues
Electric (includes franchise fees and gross receipts taxes of $40.4 in 2008 and $40.4 in 2007)	$	1,007.4		$	1,016.6
Gas (includes franchise fees and gross receipts taxes of $13.6 in 2008 and $13.6 in 2007)		363.3			312.1
Total revenues		1,370.7			1,328.7
Expenses
Operations
Fuel		339.8			448.7
Purchased power		197.8			123.1
Cost of natural gas sold		252.8			200.2
Other		143.1			125.7
Maintenance		66.4			60.1
Depreciation		110.8			113.5
Taxes, federal and state		41.0			39.7
Taxes, other than income		87.9			89.4
Total expenses		1,239.6			1,200.4
Income from operations		131.1			128.3
Other income
Allowance for other funds used during construction		3.0			2.8
Taxes, non-utility federal and state		(0.9	)		(1.0	)
Other income, net		4.0			6.5
Total other income		6.1			8.3
Interest charges
Interest on long-term debt		61.6			58.0
Other interest		5.4			6.8
Allowance for borrowed funds used during construction		(1.2	)		(1.1	)
Total interest charges		65.8			63.7
Net income	$	71.4		$	72.9
Other comprehensive loss, net of tax
Net unrealized loss on cash flow hedges		(2.2	)		—
Other comprehensive loss, net of tax		(2.2	)		—
Comprehensive Income	$	69.2		$	72.9

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

(millions)	Six months ended Jun. 30,
	2008			2007
Cash flows from operating activities
Net income	$	71.4		$	72.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		110.8			113.5
Deferred income taxes		55.0			(15.0	)
Investment tax credits, net		(0.9	)		(1.3	)
Allowance for funds used during construction		(3.0	)		(2.8	)
Deferred recovery clause		(92.4	)		26.7
Receivables, less allowance for uncollectibles		(41.4	)		(23.8	)
Inventories		(13.4	)		(29.5	)
Prepayments		(5.2	)		(4.6	)
Taxes accrued		25.5			38.7
Interest accrued		6.9			4.6
Accounts payable		93.5			(5.6	)
Gain on sale of business/assets		(0.1	)		(0.2	)
Other		(8.8	)		20.8
Cash flows from operating activities		197.9			194.4
Cash flows from investing activities
Capital expenditures		(247.1	)		(232.7	)
Allowance for funds used during construction		3.0			2.8
Net proceeds from sale of business		—			0.4
Cash flows used in investing activities		(244.1	)		(229.5	)
Cash flows from financing activities
Proceeds from long-term debt		327.9			321.0
Common stock		150.0			—
Repayment of long-term debt/Purchase in lieu of redemption		(286.7	)		(75.0	)
Net decrease in short-term debt		(25.0	)		(48.0	)
Dividends		(71.8	)		(65.2	)
Cash flows from financing activities		94.4			132.8
Net increase in cash and cash equivalents		48.2			97.7
Cash and cash equivalents at beginning of period		11.9			5.1
Cash and cash equivalents at end of period	$	60.1		$	102.8

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

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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 Jun. 30, 2008 and Dec. 31, 2007, and the results of operations and cash flows for the periods ended Jun. 30, 2008 and 2007. The results of operations for the three month and six month periods ended Jun. 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 Jun. 30, 2008 and Dec. 31, 2007, unbilled revenues of $52.3 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 $115.9 million and $197.8 million for the three months and six months ended Jun. 30, 2008, respectively, compared to $69.5 million and $123.1 million for the three months and six months ended Jun. 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 $27.6 million and $54.0 million, respectively, for the three months and six months ended Jun. 30, 2008, compared to $27.0 million and $54.0 million, respectively, for the three months and six months ended Jun. 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 $27.6 million and $53.8 million, respectively, for the three months and six months ended Jun. 30, 2008, compared to $27.0 million and $53.9 million, respectively, for the three months and six months ended Jun. 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

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standards Board (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 material to its financial statement disclosures and we continue to evaluate the impact through its adoption.

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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.

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 FASB Staff Position (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 Jun. 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.

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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.

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 six months ended Jun. 30, 2008, approximately 2,500 and 5,000 allowances were sold, respectively, resulting in proceeds of $1.0 million and $2.0 million, respectively. During the three months ended Jun. 30, 2007, approximately 35,000 allowances were sold resulting in proceeds of $17.5 million. There were no SO₂allowances sold in the first quarter of 2007.

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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 Jun. 30, 2008 and Dec. 31, 2007 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun. 30, 2008		Dec. 31, 2007
Regulatory assets:
Regulatory tax asset(1)	$	65.0	$	62.5
Other:
Cost recovery clauses		118.8		47.2
Postretirement benefit asset		94.7		97.5
Deferred bond refinancing costs(2)		23.6		25.5
Environmental remediation		11.4		11.4
Competitive rate adjustment		4.7		5.4
Other		4.8		4.7
Total other regulatory assets		258.0		191.7
Total regulatory assets		323.0		254.2
Less: Current portion		138.5		67.4
Long-term regulatory assets	$	184.5	$	186.8
Regulatory liabilities:
Regulatory tax liability(1)	$	18.5	$	18.8
Other:
Deferred allowance auction credits		0.1		0.1
Cost recovery clauses		180.7		18.9
Environmental remediation		11.4		11.4
Transmission and delivery storm reserve		22.3		20.3
Deferred gain on property sales(3)		3.7		4.7
Accumulated reserve-cost of removal		548.7		543.5
Other		0.5		0.4
Total other regulatory liabilities		767.4		599.3
Total regulatory liabilities		785.9		618.1
Less: Current portion		174.8		35.4
Long-term regulatory liabilities	$	611.1	$	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.

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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)	Jun. 30, 2008		Dec. 31, 2007
Clause recoverable(1)	$	123.5	$	52.6
Earning a rate of return(2)		99.0		101.7
Regulatory tax assets(3)		65.0		62.5
Capital structure and other(3)		35.5		37.4
Total	$	323.0	$	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.

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 six months ended Jun. 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 Jun. 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 six months ended Jun. 30, 2008 and 2007, respectively, net pension expense was $4.2 million and $7.0 million for pension benefits, and $7.0 million and $7.3 million for other postretirement benefits.

Included in the benefit expenses discussed above, for the three months and six months ended Jun. 30, 2008, Tampa Electric Company reclassed $1.4 million and $2.8 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income compared to $2.5 million and $5.0 million, respectively, for the same periods ended Jun. 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.

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6. Short-Term Debt

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

Credit Facilities	Jun. 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		—		—		150.0		25.0		—
Total	$	475.0	$	—	$	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 Dec. 31, 2007 was 4.76%. There were no borrowings outstanding as of Jun. 30, 2008.

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 income” 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.

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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 Jun. 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 Jun. 30, 2008, Tampa Electric Company has estimated its ultimate financial liability to be approximately $11.5 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

At Jun. 30, 2008, Tampa Electric Company was not obligated under guarantees or letters of credit for the benefit of third parties, including entities under common control. At Jun. 30, 2008, TECO Energy had provided a fuel purchase guarantee on behalf of Tampa Electric Company in the face amount of $20.0 million.

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 Jun. 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 six months ended Jun. 30, 2008, Tampa Electric paid United Maritime Group, formerly TECO Transport and now an unrelated entity, $19.1 million and $43.7 million, respectively. For the three months and six months ended Jun. 30, 2007, Tampa Electric paid TECO Transport $28.3 million and $52.3 million, respectively.

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10. Segment Information

(millions) Three months ended Jun. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2008
Revenues - external	$	545.7	$	184.3	$	—		$	730.0
Sales to affiliates		0.4		—		(0.1	)		0.3
Total revenues		546.1		184.3		(0.1	)		730.3
Depreciation		45.0		10.3		—			55.3
Total interest charges		27.9		4.5		(0.1	)		32.3
Provision for taxes		23.6		3.4		—			27.0
Net income	$	40.2	$	5.3	$	—		$	45.5
2007
Revenues - external	$	544.3	$	143.2	$	—		$	687.5
Sales to affiliates		0.4		—		(0.1	)		0.3
Total revenues		544.7		143.2		(0.1	)		687.8
Depreciation		47.3		10.0		—			57.3
Total interest charges		28.5		4.3		—			32.8
Provision for taxes		19.4		3.4		—			22.8
Net income	$	34.7	$	5.4	$	—		$	40.1
Six months ended Jun. 30,
2008
Revenues - external	$	1,006.9	$	363.3	$	—		$	1,370.2
Sales to affiliates		0.7		—		(0.2	)		0.5
Total revenues		1,007.6		363.3		(0.2	)		1,370.7
Depreciation		90.2		20.6		—			110.8
Total interest charges		57.3		8.7		(0.2	)		65.8
Provision for taxes		32.1		9.8		—			41.9
Net income	$	56.1	$	15.3	$	—		$	71.4
Total assets at Jun. 30, 2008	$	5,060.5	$	836.1	$	(12.8	)	$	5,883.8
2007
Revenues - external	$	1,015.7	$	312.4	$	—		$	1,328.1
Sales to affiliates		0.9		—		(0.3	)		0.6
Total revenues		1,016.6		312.4		(0.3	)		1,328.7
Depreciation		93.7		19.8		—			113.5
Total interest charges		55.3		8.4		—			63.7
Provision for taxes		30.4		10.3		—			40.7
Net income	$	56.5	$	16.4	$	—		$	72.9
Total assets at Dec. 31, 2007	$	4,672.5	$	754.3	$	(7.5	)	$	5,419.3

11. Derivatives and Hedging

At Jun. 30, 2008 and Dec. 31, 2007, Tampa Electric Company and its affiliates had derivative assets (current and non-current) totaling $167.6 million and $2.2 million, respectively, and had derivative liabilities (current and non-current) totaling $0.4 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 $7.2 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 Jun. 30, 2008, net pretax gains of $142.8 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 Issue 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 Issue 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 Jun. 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 Jun. 30, 2008
(in millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	—	$	167.6	$	—	$	167.6
Total	$	—	$	167.6	$	—	$	167.6
Liabilities
Natural gas swaps	$	—	$	0.4	$	—	$	0.4
Total	$	—	$	0.4	$	—	$	0.4

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.

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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	$	—		$	—

The $11.8 million settled in the second quarter of 2008 related to forward starting interest rate swaps settled in conjunction with our May 2008 issuance of the related debt.

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

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. 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; 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 changes in electric tariffs or contract terms affecting TECO Guatemala’s operations. 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 Form 10-Q.

Earnings Summary - Unaudited
(millions, except per share amounts)	Three months ended Jun. 30,				Six months ended Jun. 30,
	2008		2007		2008		2007
Consolidated revenues	$	887.2	$	866.5	$	1,678.9	$	1,687.8
Net income from continuing operations		51.4		59.4		82.2		132.2
Discontinued operations		—		14.3		—		14.3
Net income	$	51.4	$	73.7	$	82.2	$	146.5
Average common shares outstanding
Basic		210.4		208.9		210.1		208.8
Diluted		212.1		210.0		211.6		209.7
Earnings per share - basic
Continuing operations	$	0.24	$	0.28	$	0.39	$	0.63
Discontinued operations		—		0.07		—		0.07
Earnings per share - basic	$	0.24	$	0.35	$	0.39	$	0.70
Earnings per share - diluted
Continuing operations	$	0.24	$	0.28	$	0.39	$	0.63
Discontinued operations		—		0.07		—		0.07
Earnings per share - diluted	$	0.24	$	0.35	$	0.39	$	0.70

Operating Results

Three Months Ended Jun. 30, 2008:

Second quarter net income and earnings per share from continuing operations were $51.4 million and $0.24 per share, respectively, compared to $59.4 million and $0.28 per share in the same period in 2007. In 2007, second quarter results included a $14.3 million 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. 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, second quarter net income in 2008 included no benefits from the operations of TECO Transport or from the production of synthetic fuel, which contributed $9.6 million and $11.0 million, respectively, or $0.10 per share collectively, in the 2007 period.

Six Months Ended Jun. 30, 2008:

Year-to-date net income and earnings per share were $82.2 million or $0.39 per share in 2008, compared to $146.5 million or $0.70 per share in the same period in 2007. Year-to-date net income and earnings per share from continuing operations were $82.2 million or $0.39 per share in 2008, compared to $132.2 million or $0.63 per share in the same period in 2007. TECO Transport and the production of synthetic fuel contributed $16.0 million and $41.7 million, respectively, or $0.28 per share collectively, to year-to-date 2007 net income.

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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 second quarter was $40.2 million, compared with $34.7 million for the same period in 2007. Results for the quarter reflect higher retail energy sales due to hotter weather than 2007, and increased sales to other utilities. Net income included $1.7 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 (NO_x) pollution control equipment, compared to $1.1 million included in the 2007 period. Base revenues increased $7.6 million pretax in the quarter due to more favorable weather.

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost recovery clauses, increased $1.9 million after tax in the second quarter of 2008, primarily reflecting $1.2 million higher spending on planned outage requirements on power generating equipment compared to 2007 and $0.4 million higher bad-debt expense.

Compared to the second quarter of 2007, net income included $1.5 million lower depreciation expense, largely as a result of a depreciation study that reduced depreciation rates approved by the FPSC in the third quarter of 2007 and $0.3 million lower property tax expense, as a result of lower property tax rates from legislation passed in Florida in 2007, and as adjustments to property valuations previously agreed to with various taxing authorities.

Tampa Electric’s retail energy sales increased 2.7% in the second quarter due to hotter weather and the operation of a large water desalinization facility that was idle in 2007, partially offset by lower sales to industrial customers due to phosphate production facility outages and economic conditions. Total heating and cooling degree-days for the Tampa area in the second quarter were 3% above normal and 8% above actual 2007 levels.

Average customer growth of 0.2% and 0.4% in the 2008 quarter and year-to-date periods, respectively, reflected the weak Florida housing market and the general statewide economic slowdown.

Year-to-date net income was $56.1 million, compared to $56.5 million in the 2007 period, driven primarily by $1.8 million higher earnings on investments in emissions control equipment recovered through the Environmental Cost Recovery Clause, which were offset by higher operations and maintenance expense. These results reflect 0.4% higher retail energy sales and off-system energy sales that were essentially unchanged from the same period last year. Total heating and cooling degree days were 1% below normal due to mild winter weather, but 1% above actual 2007 degree days. Year-to-date pretax base revenue growth of $4.3 million was limited by slow customer growth and mild first quarter weather.

Excluding all FPSC-approved cost recovery clause-related expenses, net income reflects $6.4 million higher operations and maintenance expense, including $3.7 million higher spending on planned outage requirements on power generating equipment compared to 2007, and $0.9 million higher bad-debt expense. Net income also included $3.0 million of AFUDC – Equity related to the installation of NOx pollution control equipment, compared to $2.8 million included in the 2007 period.

Compared to the 2007 year-to-date period, net income also reflected $2.2 million lower depreciation expense, and $0.7 million lower property tax expense for the reasons described above. Interest expense at Tampa Electric increased $1.3 million, due to higher levels of long-term debt outstanding and higher interest on auction-rate bonds for one month in the first quarter of the year. In addition, interest income decreased due to lower cash balances and lower interest earned on under-recovered fuel balances early in the year.

On Jun. 12, 2008, Tampa Electric notified the FPSC that it plans to file for an increase to its base rates, the first time the company has made such a request since 1992. In that notification Tampa Electric indicated that a base revenue increase in a range between $225 million and $235 million will be needed, and that it would file all details related to its proposal in 60 days. That filing will start an eight-month process during which the request for new base rates is considered by the FPSC, with new rates effective at its conclusion.

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

(millions, except average customers)	Operating Revenues						Kilowatt-hour sales
	2008		2007		% Change		2008	2007	% Change
Three months ended Jun. 30,
By Customer Type
Residential	$	247.3	$	238.4	3.7		2,153.5	2,068.3	4.1
Commercial		161.9		160.3	1.0		1,621.5	1,598.2	1.5
Industrial – Phosphate		16.5		17.4	(5.2	)	240.2	249.1	(3.6	)
Industrial – Other		30.3		30.1	0.7		324.2	334.9	(3.2	)
Other sales of electricity		46.8		43.4	7.8		464.0	425.2	9.1
Deferred and other revenues(1)		13.0		10.9	19.3		—	—	—
		515.8		500.5	3.1		4,803.4	4,675.7	2.7
Sales for resale		19.2		17.6	9.1		230.6	223.1	3.4
Other operating revenue		10.1		9.0	12.2		—	—	—
SO2 Allowance sales		1.0		17.6	(94.3	)	—	—	—
	$	546.1	$	544.7	0.3		5,034.0	4,898.8	2.8
Average customers (thousands)		668.0		666.0	0.3
Retail output to line (kilowatt hours)							5,278.0	5,168.6	2.1
Six months ended Jun. 30,
By Customer Type
Residential	$	454.3	$	454.7	(0.1	)	3,931.5	3,930.9	0.0
Commercial		309.3		306.9	0.8		3,089.5	3,057.0	1.1
Industrial – Phosphate		33.1		36.1	(8.3	)	484.8	520.5	(6.9	)
Industrial – Other		57.7		58.8	(1.9	)	630.1	654.6	(3.7	)
Other sales of electricity		89.4		83.9	6.6		882.6	817.2	8.0
Deferred and other revenues(1)		5.8		7.4	(21.6	)	—	—	—
		949.6		947.8	0.2		9,018.5	8,980.2	0.4
Sales for resale		35.2		33.1	6.3		419.8	421.2	(0.3	)
Other operating revenue		20.9		18.2	14.8		—	—	—
SO2 Allowance sales		1.9		17.6	(89.2	)	—	—	—
	$	1,007.6	$	1,016.7	(0.9	)	9,438.3	9,401.4	0.4
Average customers (thousands)		668.3		665.4	0.4
Retail output to line (kilowatt hours)							9,635.7	9,580.9	0.6

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

Tampa Electric Company – Natural gas division (PGS)

Peoples Gas reported net income of $5.3 million for the second quarter, compared to $5.4 million in the same period in 2007. Quarterly results reflect higher off-system sales, higher volumes transported for power generation and industrial customers and average customer growth of 0.3%, which reflects the continued slowdown in the Florida housing market. Higher residential therm sales reflect weather that was cooler than 2007 and increased therm sales to industrial customers reflect a new customer with significant usage. The effects of these higher volumes were more than offset by higher non-fuel operations and maintenance costs, 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. Volumes for commercial customers in 2008, particularly the restaurant sector, were lower reflecting the slowdown in the Florida economy.

Year-to-date net income was $15.3 million, compared to $16.4 million in the 2007 period, driven largely by the same factors as the second quarter. Results also reflect average customer growth of 0.3% and lower sales to weather-sensitive residential customers in the first quarter due to very mild winter weather.

On Jun. 12, 2008, Peoples Gas notified the FPSC that it plans to file for an increase to its base rates, the first time the company has made such a request since 2002. In that notification Peoples Gas indicated that a base revenue increase of about $25 million will be needed, and that it would file all details related to its proposal in 60 days. That filing will start an eight-month process during which the request for new base rates is considered by the FPSC, with new rates effective at its conclusion.

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

(millions, except average customers)	Operating Revenues						Therms
	2008		2007		% Change		2008	2007	% Change
Three months ended Jun. 30,
By Customer Type
Residential	$	32.2	$	31.0	3.9		14.8	14.5	2.1
Commercial		38.0		41.4	(8.2	)	90.8	92.1	(1.4	)
Industrial		2.3		2.4	(4.2	)	53.4	48.4	10.3
Off system sales		97.8		53.6	82.5		82.1	65.9	24.6
Power generation		3.8		3.6	5.6		132.9	117.1	13.5
Other revenues		8.6		9.4	(8.5	)	—	—	—
	$	182.7	$	141.4	29.2		374.0	338.0	10.7
By Sales Type
System supply		151.7		109.7	38.3		111.0	96.4	15.1
Transportation		22.4		22.3	0.4		263.0	241.6	8.9
Other revenues		8.6		9.4	(8.5	)	—	—	—
	$	182.7	$	141.4	29.2		374.0	338.0	10.7
Average customers (thousands)		336.3		335.2	0.3
Six months ended Jun. 30,
By Customer Type
Residential	$	80.9	$	85.4	(5.3	)	42.6	43.6	(2.3	)
Commercial		82.4		91.7	(10.1	)	197.8	199.6	(0.9	)
Industrial		4.5		4.9	(8.2	)	100.2	99.8	0.4
Off system sales		166.4		100.4	65.7		160.6	128.6	24.9
Power generation		7.2		6.3	14.3		239.6	182.6	31.2
Other revenues		18.4		20.3	(9.4	)	—	—	—
	$	359.8	$	309.0	16.4		740.8	654.2	13.2
By Sales Type
System supply		294.4		242.4	21.5		234.9	208.5	12.7
Transportation		47.0		46.3	1.5		505.9	445.7	13.5
Other revenues		18.4		20.3	(9.4	)	—	—	—
	$	359.8	$	309.0	16.4		740.8	654.2	13.2
Average customers (thousands)		336.2		335.1	0.3

TECO Coal

TECO Coal achieved second quarter net income of $4.2 million, compared to $20.8 million in the same period in 2007. In 2007, TECO Coal’s results included an $11.0 million benefit related to synthetic fuel production.

Second quarter total sales were 2.4 million tons, compared to 2.2 million tons in the second quarter of 2007, which included 1.5 million tons of synthetic fuel. TECO Coal experienced slightly lower than expected production due to difficult mining conditions in an underground mine, which temporarily reduced production from that mine in the first two months of the second quarter. Compared to the second quarter in 2007, results reflect an average per ton selling price almost 10% higher across all products, excluding transportation allowances. In the second quarter of 2008, the cash cost of production per ton increased almost 20% over 2007’s level, driven by diesel fuel prices that were more than double 2007 prices; the per-ton cost for steel products used in underground mining, such as roof bolts, that were more than double 2007 levels, and the cost of explosives used in surface mining operations that were 42% higher than in 2007.

TECO Coal recorded year-to-date net income of $11.7 million in 2008, compared to $63.2 million in the 2007 period, which included a $41.7 million benefit associated with the production of synthetic fuel.

Year-to-date 2008 total sales were 4.9 million tons, compared to 4.3 million tons in the 2007 period, which included 2.8 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 5% higher than 2007. In 2008, the cash cost of production for the year-to-date period was approximately 13% higher than 2007, driven by the same factors as in the second 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 second quarter net income of $14.9 million in 2008, compared to $12.8 million in the 2007 period. Year-to-date 2008 net income was $25.4 million, compared to $23.1 million in the 2007 period. Proceeds from spot energy sales at the San José Power Station significantly improved due to higher spot market prices. Earnings under the power sales contract were down slightly due to the timing of a scheduled maintenance outage. 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 second quarter and year-to-date results reflect customer growth and higher energy sales, which resulted in higher net income, offset by higher costs at EEGSA. The earnings from the unregulated EEGSA-affiliated companies (DECA II), which provide, among other things, electricity transmission services, telecommunication carrier service, wholesale power sales to unregulated electric customers and engineering services, increased in both periods from fundamental growth in the businesses. Results for EEGSA and affiliated companies also include 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 second quarter of 2008 was $13.2 million, compared to a cost of $23.9 million in the same period in 2007, which included $8.3 million of charges related to the sale of TECO Transport. Results in the 2008 quarter were driven by lower interest expense partially offset by lower investment income due to lower cash balances. Total parent/TECO Finance interest expense declined by $4.9 million in the second quarter of 2008, reflecting parent debt retirements.

The year-to-date “Parent/other” cost was $26.3 million in 2008, compared to $43.0 million in the 2007 period. The 2008 year-to-date cost includes $0.6 million of costs related to previously estimated transaction costs associated with the sale of TECO Transport, compared to the 2007 year-to-date cost, which included $10.1 million of charges related to the sale of TECO Transport. Year-to-date 2008 total parent/TECO Finance interest expense declined by $11.3 million, due to parent debt retirements.

TECO Transport

The sale of TECO Transport closed Dec. 4, 2007. Due to the ongoing contractual relationship for solid fuel waterborne transportation services, TECO Transport was not classified as a discontinued operation and is included in TECO Energy’s historical results.

In 2007, TECO Transport recorded second quarter net income of $9.6 million, and year-to-date net income of $16.0 million.

Discontinued Operations

Net income from discontinued operations was $14.3 million in 2007, reflecting a favorable conclusion reached with taxing authorities related to the 2005 disposition of the Union and Gila River merchant power plants.

Income Taxes

The provision for income taxes from continuing operations for the six month periods ended Jun. 30, 2008 and Jun. 30, 2007 was an expense of $35.5 million and $57.1 million, respectively. The provision for income taxes from continuing operations in the six months ended Jun. 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. 4, 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 six month periods ended Jun. 30, 2008 and Jun. 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 six months ended Jun. 30, 2008 were $55.9 million and $113.6 million, respectively, compared to $65.7 million and $132.8 million for the three and six months ended Jun. 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, partially offset by the impact of higher long-term debt balances at the regulated utilities.

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Liquidity and Capital Resources

The table below sets forth the Jun. 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.

(millions)	Balances as of Jun. 30, 2008
	Consolidated		Tampa Electric Company		Other		Parent
Credit facilities	$	675.0	$	475.0	$	—	$	200.0
Drawn amounts / LCs		10.9		1.4		—		9.5
Available credit facilities		664.1		473.6		—		190.5
Cash and short-term investments		174.2		60.1		60.4		53.7
Total liquidity	$	838.3	$	533.7	$	60.4	$	244.2
Consolidated restricted cash (not included above)	$	7.5	$	—	$	0.2	$	7.3

Consolidated other cash and short-term investments includes $10.3 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 Jun. 30, 2008, unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash and short-term investment balances of $18.1 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 current 2008 $72 million under-recovery in its fuel and purchased power clause, which is projected to increase to approximately $209 million by year-end. Tampa Electric will seek to recover under-recovered 2008 fuel costs through the 2009 fuel adjustment process.

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, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. TECO Energy, Tampa Electric Company and the other operating companies are in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Jun. 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	Financial Covenant (1)	Requirement/Restriction	Calculation at Jun. 30, 2008
Tampa Electric Company
PGS senior notes	EBIT/interest(2)	Minimum of 2.0 times		3.1 times
	Restricted payments	Shareholder equity at least $500	$	1,949
	Funded debt/capital	Cannot exceed 65%		50.3	%
	Sale of assets	Less than 20% of total assets		0	%
Credit facility(3)	Debt/capital	Cannot exceed 65%		49.5	%
Accounts receivable credit facility(3)	Debt/capital	Cannot exceed 65%		49.5	%
6.25% senior notes	Debt/capital	Cannot exceed 60%		49.5	%
	Limit on liens(5)	Cannot exceed $700	$	0 liens outstanding
Insurance agreements relating to certain pollution bonds	Limit on liens(5)	Cannot exceed $388 (7.5% of net assets)	$	0 liens outstanding
TECO Energy/TECO Finance
Credit facility(3)	Debt/EBITDA(2)	Cannot exceed 5.0 times		3.0 times
	EBITDA/interest (2)	Minimum of 2.6 times		4.7 times
	Limit on additional indebtedness	Cannot exceed $1,074	$	0
	Dividend restriction (4)	Cannot exceed $51 per quarter	$	42
TECO Energy 7.5% notes	Limit on liens(5)	Cannot exceed $282 (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)	$	554

(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 Jun. 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.

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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 Jun. 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 and our commitments with respect to those projects are at risk if those projects are not operated successfully.

(millions)	Long-term Debt		Ownership Interest
San José Power Station	$	67.8	100	%
Alborada Power Station	$	6.5	96	%
DECA II	$	217.3	30	%

Outlook

TECO Energy indicated in February an outlook for 2008 results from continuing operations within a range of $0.95 and $1.10 per share, excluding any charges or gains. Based on the year-to-date performance and expectations of continued production cost pressures at TECO Coal and a continuation of the effects of a slow Florida economy on customer growth and energy sales for the remainder of 2008, TECO Energy now expects 2008 earnings to be in a range between $0.80 and $0.90 per share, excluding any charges or gains. This range assumes a continued weak Florida economy and housing market; includes the effects of a very rainy July, which reduced energy sales at Tampa Electric, but assumes normal weather for the remainder of the year; and assumes continued high production costs at TECO Coal.

Year-to-date, Tampa Electric has experienced total degree days 1% below normal, lower residential per-customer usage due to mild weather, voluntary conservation, and customer growth indicative of a continued weak housing market and economic slowdown. At Peoples Gas, mild winter weather has reduced year-to-date sales, and customer growth has slowed due to the housing market slowdown. At TECO Coal, sales in 2008 are now expected to be about 10 million tons, compared to the 10.5 million tons previously forecast, due to the second quarter production issues discussed above and the availability of contract miners. TECO Coal’s selling prices for over 90% of this year’s production reflect contracts signed in 2006 and 2007 or before, prior to the run up in coal prices, and the remaining 10% of the current year contracts were signed early in 2008. At the same time, the cost of production reflects the current prices for diesel oil, steel and petroleum-related products, all of which are substantially higher than at the time the outlook was provided in February 2008. TECO Guatemala had previously indicated that earnings for 2008 would be lower than 2007 levels; however, 2008 net income from TECO Guatemala is now expected to be at about 2007 levels, given the strong year-to-date performance. As indicated in February, costs at the TECO Energy parent level are expected to decline due to debt retirement actions in 2007 partially offset by lower investment income due to lower cash balances.

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 and interest rate derivatives classified as cash flow hedges. 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.

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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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 $191.75 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 Jun. 30, 2008, pending a determination of their disposition. The result of these transactions lowered our exposure to variable interest rate risk.

Credit Risk

We are exposed to credit risk as a result of our purchases and sales of energy commodities and related hedging activities. As of Jun. 30, 2008, there was no significant change in our exposure to credit risk since Dec. 31, 2007.

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 increase in the price of natural gas. The company maintains a similar volume hedged as of Jun. 30, 2008 from Dec. 31, 2007, but the price of natural gas has increased, on average, 66% since the end of 2007. In addition, derivative balances at Dec. 31, 2007 included $8.2 million in interest rate swap liabilities that were settled during the 2^nd quarter.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the six months ended Jun. 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		165.2
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		25.9
Net fair value of derivatives as of Jun. 30, 2008	$	167.2
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		165.2
Recorded in earnings		—
Realized net settlement of derivatives		25.9
Net option premium payments		—
Net purchase (sale) of existing contracts		—
Net fair value of derivatives as of Jun. 30, 2008	$	167.2

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

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Jun. 30, 2008 (millions)
Contracts Maturing in	Current		Non-current		Total Fair Value
Source of fair value (millions)
Actively quoted prices		—		—		—
Other external sources(1)	$	142.9	$	24.3	$	167.2
Model prices(2)		—		—		—
Total	$	142.9	$	24.3	$	167.2

(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 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 of TECO Energy and Tampa Electric Company. The risk factors described below updates, and should be read in conjunction with, the risk factors identified in the Annual Report on Form 10-K for the period ended Dec. 31, 2007.

The significant, phased reductions in GHG emissions called for by the governor of Florida in 2007 could add to Tampa Electric’s costs and adversely affect its operating results.

In the 2008 Florida Legislative session, legislation was passed, and later signed by the Governor, that granted the Florida Department of Environmental Protection (FDEP) the authority to develop a utility carbon reduction schedule and to develop a carbon cap and trade program. The Bill requires FDEP to consider various costs and benefits when developing the program and to present the rule to the Legislature for ratification in the 2010 Legislative Session. While the impact of this legislation will be uncertain until final rules are developed, the final rules could result in increased costs to Tampa Electric, or further changes in customer usage patterns in response to higher rates, and Tampa Electric’s operating results could be adversely affected.

A mandatory renewable energy portfolio standard could add to Tampa Electric’s costs and adversely affect its operating results.

In the 2008 Florida Legislative session, legislation was passed, and later signed by the Governor, that directed the Florida Public Service Commission (FPSC) to develop a draft rule requiring electric utilities to supply a certain amount of their power from renewable energy resources, either directly through production or purchase, or through renewable energy credits. In developing the rule, the FPSC must analyze the cost of various renewable energy generation methods, and conditions under which a utility will be excused from meeting the renewable energy requirement due to cost or inadequate supply of renewable energy. The legislation specifically gives the FPSC rule making authority for providing cost recovery and incentive-based rates to utilities. The draft rule must be presented to the Legislature by February 1, 2009, for ratification. In addition, there is proposed legislation in the U.S. Congress to introduce a renewable energy portfolio standard at the federal level. It remains unclear, however, if or when action on such federal legislation would be completed. Tampa Electric could incur significant costs to comply with a renewable energy portfolio standard, as proposed. Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers, or if customers change usage patterns in response to increased rates.

New or revised emission reduction regulations could add to Tampa Electric’s costs and adversely affect its operating results.

In July 2008, a United States Appeals Court vacated the Clean Air Interstate Rule (CAIR), which was scheduled to require reduced SO₂, NOx and mercury emissions beginning in 2009. While the court’s decision to vacate CAIR is not expected to impact Tampa Electric’s ongoing emissions reduction programs, and it is unclear at this time when or in what form new or revised emission reduction rules will be implemented, Tampa Electric’s operating results could be adversely affected by new or revised rules which could increase capital expenditures or increase operating costs.

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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
Apr. 1, 2008 – Apr. 30, 2008	31,917	$	16.70	—	—
May 1, 2008 – May 31, 2008	7,106	$	19.37	—	—
Jun. 1, 2008 – Jun. 30, 2008	4,564	$	21.18	—	—
Total 2nd Quarter 2008	43,587	$	17.60	—	—

(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 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the Annual Meeting of Shareholders held on Apr. 30, 2008, the shareholders of TECO Energy, Inc. elected four directors and ratified the actions taken by the Audit Committee appointing PricewaterhouseCoopers LLP as TECO Energy, Inc.’s independent auditor. The following table details the voting results:

	Votes Cast For	Votes Cast Against	Abstentions	Broker Non-Vote
Election of Directors
DuBose Ausley	158,141,664	27,591,524	2,696,789
James L. Ferman, Jr.	180,990,129	4,822,774	2,617,074
John B. Ramil	181,563,044	4,264,394	2,602,539
Paul L. Whiting	181,739,571	3,947,034	2,743,372
Resolution to ratify appointment by Audit Committee of PricewaterhouseCoopers LLP as independent auditor.	183,124,341	2,785,507	2,520,129

For a complete listing of the Board of Directors, please seeItem 10. Directors, Executive Officers and Corporate Governance of TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2007.

Item 6. EXHIBITS

Exhibits - See index on page 55.

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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: July 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: July 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).
4.1	*	Seventh Supplemental Indenture dated as of May 1, 2008 between Tampa Electric Company and The Bank of New York, as trustee, supplementing the Indenture dated as of Jul. 1, 1998, as amended (Exhibit 4.20, Form 8-K dated May 16, 2008 of Tampa Electric Company).
4.2	*	6.10% Notes due 2018 (Exhibit 4.21, Form 8-K dated May 16, 2008 of Tampa Electric Company).
10.1		Form of Performance Shares Agreement under the TECO Energy, Inc. 2004 Equity Incentive Plan.
10.2		Form of Restricted Stock Agreement under the TECO Energy, Inc. 2004 Equity Incentive Plan.
10.3		Form of Restricted Stock Agreement between TECO Energy, Inc. and Sherrill W. Hudson under the TECO Energy, Inc. 2004 Equity Incentive Plan.
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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