Tampa Electric 10-Q 2009 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, 2009

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

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 the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).    YES  ¨    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. 27, 2009 was213,744,776. As of Jul. 27, 2009, 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.

Index to Exhibits appears on page 61.

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, 2009 and Dec. 31, 2008, and the results of their operations and cash flows for the periods ended Jun. 30, 2009 and 2008. The results of operations for the three month and six month periods ended Jun. 30, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009. 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/A for the year ended Dec. 31, 2008 and to the notes on pages 9 through 27 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Jun. 30, 2009 and Dec. 31, 2008	3-4
Consolidated Condensed Statements of Income for the three month and six month periods ended Jun. 30, 2009 and 2008	5-6
Consolidated Condensed Statements of Comprehensive Income for the three month and six month periods ended Jun. 30, 2009 and 2008	7
Consolidated Condensed Statements of Cash Flows for the six month periods ended Jun. 30, 2009 and 2008	8
Notes to Consolidated Condensed Financial Statements	9-27

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Jun. 30, 2009			Dec. 31, 2008
Current assets
Cash and cash equivalents	$	28.0		$	12.2
Short-term investments		—			2.4
Receivables, less allowance for uncollectibles of $4.6 and $3.5 at Jun. 30, 2009 and Dec. 31, 2008, respectively		309.7			285.9
Inventories, at average cost
Fuel		142.9			90.2
Materials and supplies		67.5			72.8
Current regulatory assets		172.4			272.6
Current derivative assets		0.2			—
Income tax receivables		0.5			3.5
Prepayments and other current assets		25.1			25.8
Total current assets		746.3			765.4
Property, plant and equipment
Utility plant in service
Electric		5,743.5			5,528.3
Gas		993.3			964.4
Construction work in progress		460.7			463.5
Other property		366.9			354.8
Property, plant and equipment		7,564.4			7,311.0
Accumulated depreciation		(2,155.8	)		(2,089.7	)
Total property, plant and equipment, net		5,408.6			5,221.3
Other assets
Deferred income taxes		278.5			333.8
Other investments		9.8			21.3
Long-term regulatory assets		319.2			325.3
Long-term derivative assets		0.6			0.1
Investment in unconsolidated affiliates		273.6			284.0
Goodwill		59.4			59.4
Deferred charges and other assets, including restricted cash of $7.3 and $7.5 at Jun. 30, 2009 and Dec. 31, 2008, respectively		134.1			136.8
Total other assets		1,075.2			1,160.7
Total assets	$	7,230.1		$	7,147.4

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

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)	Jun. 30, 2009			Dec. 31, 2008
Current liabilities
Long-term debt due within one year
Recourse	$	5.5		$	5.5
Non-recourse		1.4			1.4
Notes payable		188.0			93.0
Accounts payable		264.5			304.4
Customer deposits		148.6			144.6
Current regulatory liabilities		26.9			21.7
Current derivative liabilities		113.7			132.1
Interest accrued		48.1			45.1
Taxes accrued		46.2			21.2
Other current liabilities		15.6			15.3
Total current liabilities		858.5			784.3
Other liabilities
Investment tax credits		11.0			11.2
Long-term regulatory liabilities		579.8			588.2
Long-term derivative liabilities		10.3			19.4
Deferred credits and other liabilities		527.9			530.0
Long-term debt, less amount due within one year
Recourse		3,199.0			3,199.0
Non-recourse		6.2			7.6
Total other liabilities		4,334.2			4,355.4
Commitments and contingencies (see Note 9)
Capital
Common equity (400.0 million shares authorized; par value $1; 213.7 and 212.9 shares outstanding at Jun. 30, 2009 and Dec. 31, 2008, respectively)		213.7			212.9
Additional paid in capital		1,523.9			1,518.2
Retained earnings		332.9			322.6
Accumulated other comprehensive loss		(33.1	)		(46.0	)
Total capital		2,037.4			2,007.7
Total liabilities and capital	$	7,230.1		$	7,147.4

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)	2009			2008
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $28.2 in 2009 and $27.6 in 2008)	$	662.9		$	730.0
Unregulated		162.3			157.2
Total revenues		825.2			887.2
Expenses
Regulated operations
Fuel		225.5			176.2
Purchased power		56.1			115.9
Cost of natural gas sold		50.9			133.8
Other		81.0			71.9
Operation other expense
Mining related costs		110.9			116.8
Other		4.3			5.6
Maintenance		46.2			45.6
Depreciation and amortization		71.3			64.9
Taxes, other than income		55.9			54.1
Total expenses		702.1			784.8
Income from operations		123.1			102.4
Other income
Allowance for other funds used during construction		2.5			1.7
Other income		6.1			4.0
Income from equity investments		12.9			21.6
Total other income		21.5			27.3
Interest charges
Interest expense		57.4			56.6
Allowance for borrowed funds used during construction		(1.0	)		(0.7	)
Total interest charges		56.4			55.9
Income before provision for income taxes		88.2			73.8
Provision for income taxes		27.3			22.4
Net income	$	60.9		$	51.4
Average common shares outstanding– Basic		211.7			210.4
– Diluted		212.5			212.1
Earnings per share– Basic	$	0.29		$	0.24
– Diluted	$	0.29		$	0.24
Dividends paid per common share outstanding	$	0.20		$	0.20

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Six months ended Jun. 30,
(millions, except per share amounts)	2009			2008
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $58.3 in 2009 and $54.0 in 2008)	$	1,316.7		$	1,370.2
Unregulated		332.5			308.7
Total revenues		1,649.2			1,678.9
Expenses
Regulated operations
Fuel		454.2			339.8
Purchased power		98.3			197.8
Cost of natural gas sold		139.2			252.8
Other		158.0			143.2
Operation other expense
Mining related costs		229.4			224.0
Other		8.4			9.9
Maintenance		98.6			91.6
Depreciation and amortization		141.0			129.9
Taxes, other than income		116.3			109.0
Transaction related costs		—			0.9
Total expenses		1,443.4			1,498.9
Income from operations		205.8			180.0
Other income
Allowance for other funds used during construction		5.8			3.0
Other income		20.1			9.3
Income from equity investments		21.7			39.0
Total other income		47.6			51.3
Interest charges
Interest expense		115.0			114.8
Allowance for borrowed funds used during construction		(2.3	)		(1.2	)
Total interest charges		112.7			113.6
Income before provision for income taxes		140.7			117.7
Provision for income taxes		45.1			35.5
Net income	$	95.6		$	82.2
Average common shares outstanding– Basic		211.6			210.1
– Diluted		212.3			211.6
Earnings per share– Basic	$	0.45		$	0.39
– Diluted	$	0.45		$	0.39
Dividends paid per common share outstanding	$	0.40		$	0.395

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)	2009		2008			2009		2008
Net income	$	60.9	$	51.4		$	95.6	$	82.2
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) on cash flow hedges		8.1		3.9			10.5		(2.1	)
Amortization of unrecognized benefit costs		0.4		(0.1	)		0.7		0.3
Change in benefit obligations due to remeasurement		—		—			—		(10.8	)
Unrealized loss on available-for-sale securities		—		—			—		(1.0	)
Reclassification to earnings—loss on available-for-sale securities		—		—			1.7		—
Other comprehensive income (loss), net of tax		8.5		3.8			12.9		(13.6	)
Comprehensive income	$	69.4	$	55.2		$	108.5	$	68.6

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended Jun. 30,
(millions)	2009			2008
Cash flows from operating activities
Net income	$	95.6		$	82.2
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		141.0			129.9
Deferred income taxes		45.5			39.7
Investment tax credits, net		(0.2	)		(1.0	)
Allowance for funds used during construction		(5.8	)		(3.0	)
Non-cash stock compensation		4.7			6.1
Gain on sale of business/assets, pretax		(18.6	)		(1.1	)
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		0.3			(6.8	)
Deferred recovery clauses		83.3			(92.4	)
Receivables, less allowance for uncollectibles		(23.8	)		(34.0	)
Inventories		(47.4	)		(7.9	)
Prepayments and other current assets		0.7			(2.1	)
Taxes accrued		27.2			15.7
Interest accrued		3.0			15.0
Accounts payable		(9.6	)		76.9
Other		32.1			21.3
Cash flows from operating activities		328.0			238.5
Cash flows from investing activities
Capital expenditures		(367.8	)		(265.7	)
Allowance for funds used during construction		5.8			3.0
Net proceeds (settlement) from sale of business/assets		29.2			(7.3	)
Restricted cash		0.2			—
Distributions from unconsolidated affiliates		—			13.2
Other investments		9.7			76.2
Cash flows used in investing activities		(322.9	)		(180.6	)
Cash flows from financing activities
Dividends		(85.3	)		(83.5	)
Proceeds from the sale of common stock		2.4			20.0
Proceeds from long-term debt		—			327.9
Repayment of long-term debt/Purchase in lieu of redemption		(1.4	)		(288.1	)
Net increase (decrease) in short-term debt		95.0			(25.0	)
Cash flows from (used) in financing activities		10.7			(48.7	)
Net increase in cash and cash equivalents		15.8			9.2
Cash and cash equivalents at beginning of period		12.2			162.6
Cash and cash equivalents at end of period	$	28.0		$	171.8

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

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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 is 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, 2009 and Dec. 31, 2008, and the results of operations and cash flows for the periods ended Jun. 30, 2009 and 2008. The results of operations for the three month and six month periods ended Jun. 30, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009.

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, 2009 and Dec. 31, 2008, unbilled revenues of $56.6 million and $47.4 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 $56.1 million and $98.3 million for the three months and six months ended Jun. 30, 2009, respectively, compared to $115.9 million and $197.8 million for the three months and six months ended Jun. 30, 2008, 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 $28.2 million and $58.3 million, respectively, for the three months and six months ended Jun. 30, 2009, compared to $27.6 million and $54.0 million, respectively, for the three months and six months ended Jun. 30, 2008. 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 $28.2 million and $58.2 million, respectively, for the three months and six months ended Jun. 30, 2009, compared to $27.6 million and $53.8 million, respectively, for the three months and six months ended Jun. 30, 2008.

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.

9

2. New Accounting Pronouncements

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles

In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (FAS 168). FAS 168 replaces FAS 162, The Hierarchy of Generally Accepted Accounting Principles (FAS 162). It names the FASB Accounting Standards Codification (Codification) as the single source of authoritative U.S. Generally Accepted Accounting Principles (GAAP) for non-governmental entities recognized by the FASB. FAS 168 is effective for reporting periods ending after Sep. 15, 2009, and once effective, will supersede all U.S. GAAP accounting standards, aside from rules and interpretive releases issued by the Securities and Exchange Commission (SEC). The Codification is not intended to change GAAP; rather, it will change the referencing of U.S. GAAP. Therefore, it is not expected to have an impact on the company’s results of operations, statement of position or cash flows.

Accounting for Transfers of Financial Assets

In June 2009, the FASB issued SFAS No. 166,Accounting for Transfers of Financial Assets (FAS 166). FAS 166 revises SFAS 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement No. 125 and requires companies to provide more information about sales of securitized financial assets. It is effective for fiscal periods beginning after Nov. 15, 2009. The new requirements will not have an impact on the company’s results of operations, statement of position or cash flows.

Variable Interest Entities

In June 2009, the FASB issued SFAS No.167,Amendments to FASB Interpretation No. 46(R) (FAS 167). FAS 167 changes the way a company determines if a variable interest entity (VIE) should be consolidated. It is effective for fiscal years beginning after Nov. 15, 2009. TECO Energy is evaluating the effects of FAS 167 and believes that at the time of adoption it could have a significant effect on the company’s statement of position or cash flows, but not a significant impact on the results of operations.

Subsequent Events

In May 2009, the FASB issued SFAS No. 165,Subsequent Events (FAS 165). FAS 165 requires companies to disclose the date through which they evaluated subsequent events and whether that date corresponds with the filing of their financial statements. It is effective for fiscal periods ending after Jun. 15, 2009, and the adoption does not have an effect on the company’s 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.

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 FASB Staff Position (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 non-financial 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 and Jan. 1, 2009 for non-financial assets and liabilities. No adoption adjustment was necessary. Financial assets and liabilities of the company measured at fair value include derivatives and certain investments, for which fair values are primarily based on observable inputs. Non-financial assets and liabilities of the company measured at fair value include asset retirement obligations (AROs) when they are incurred and any long-lived assets or equity-method investments that are impaired in a currently reported period.

In April 2009, the FASB issued FSP FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4),FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2), and FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1) to address fair value valuation concerns in the current market environment.

FSP FAS 157-4 affirms that when the market for an asset is not active, the objective of fair value is the price that would be received to sell the asset in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date in the inactive market. The determination of whether a transaction was not orderly should be based on the weight of the evidence. The FSP requires an entity to disclose a change in valuation technique and the related inputs resulting from the application of the FSP and to quantify its effects. Retrospective application is not permitted. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. This FSP did not materially affect the company’s results of operations, statement of position or cash flows. The company adopted this FSP effective Apr. 1, 2009.

10

FSP FAS 115-2 and FAS 124-2 is applicable to debt securities and require that a company recognize the credit component of an other-than-temporary impairment in earnings and the remaining portion in other comprehensive income if management asserts it does not have the intent to sell the security and it is more likely than not it will not have to sell the security before recovery of its cost basis. It requires an entity to present separately in the financial statement where the components of other comprehensive income are reported, amounts recognized in accumulated other comprehensive income related to the noncredit portion of other-than-temporary impairments recognized for available-for-sale and held-to-maturity debt securities. Additionally, disclosure requirements are amended and will be required for interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. The FSP did not materially affect the company’s results of operations, statement of position or cash flows. The company adopted this FSP effective Apr. 1, 2009.

FSP FAS 107-1 and APB 28-1 requires an entity to disclose fair value information, including methods and significant assumptions in measuring fair value, of financial instruments within the scope of FAS 107 in interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. The new disclosure requirements of FSP FAS 107-1 and APB 28-1 had no effect on the company’s results of operations, statement of position or cash flows. The company adopted this FSP effective Apr. 1, 2009.

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued FSP No. FAS 132(R)-1,Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1). This FSP requires enhanced disclosures about plan assets of defined benefit pension plans or other postretirement plans, including the concentrations of risk in those plans. The guidance in FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009. FSP FAS 132(R)-1 will be significant to the company’s financial statement disclosures but will have no effect on the company’s results of operations, statement of position or cash flows.

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

In June 2008, the FASB issued FSP No. Emerging Issues Task Force (EITF) 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1). FSP EITF 03-6-1 requires that the two-class method earnings per share calculation include unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether the dividend or dividend equivalents are paid or not paid. The guidance in FSP EITF 03-6-1 is effective for fiscal years beginning after Dec. 15, 2008. The company adopted FSP EITF 03-6-1 effective Jan. 1, 2009 with no material impact to its results of operations, statement of position or cash flows (seeNote 8).

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued 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. FAS 161 is significant to the company’s financial statement disclosures but has no effect on its results of operations, statement of position or cash flows. The company adopted FAS 161 effective Jan. 1, 2009.

Additionally, in April 2008, the FASB revised Statement 133 Implementation Issues Nos. I1 and K4 to reflect the enhanced disclosures required by FAS 161. These revisions are significant to its financial statement disclosures but have no effect on the company’s results of operations, statement of position or cash flows.

3. Regulatory

As discussed inNote 1, Tampa Electric’s and PGS’ retail businesses are regulated by the FPSC. Tampa Electric is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). However, pursuant to a waiver granted in accordance with FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by FERC’s regulations under PUHCA 2005.

Base Rates – Tampa Electric

In order for Tampa Electric to continue meeting customers’ growing needs for reliable, efficient and affordable electric service, Tampa Electric filed with the FPSC for a base rate increase in August 2008. On Mar. 17, 2009, the FPSC approved an increase to base rates, effective on May 7, 2009, of $104.2 million that reflects a return on equity of 11.25%, which is the middle of a range between 10.25% and 12.25%. Additionally, the FPSC approved a step increase of $33.6 million effective Jan. 1, 2010 for capital additions placed in service in 2009 bringing the total approved base rate increase to $137.8 million.

On May 15, 2009, Tampa Electric filed a Motion for Reconsideration regarding the calculation of the annual revenue requirements approved by the FPSC. On Jul. 14, 2009, the FPSC approved Tampa Electric’s Motion resulting in an overall weighted

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cost of capital of 8.29%, compared to the 8.11% previously approved. This change will increase the previously approved $104.2 million to $113.6 million and the $33.6 million step increase to $34.1 million, bringing the total approved base rate increase to $147.7 million.

As part of its base rate increase, Tampa Electric also requested modifications to its cost of service methodology and rate design, which were also approved by the FPSC. In addition to several base rate design changes, residential base rates reflect a two-block structure which offers a lower rate for the first 1,000 kilowatt-hours of usage each month. The new base rates and service charges will remain in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties.

Base Rates – PGS

Recognizing the significant decline in ROE, PGS filed with the FPSC for a $3.7 million interim rate increase in August 2008. The FPSC approved an interim rate increase of $2.4 million effective Oct. 29, 2008. PGS also filed in August 2008 with the FPSC for a $26.5 million base rate increase. On May 5, 2009, the FPSC approved a base rate increase of $19.2 million that became effective on Jun. 18, 2009 and reflects a return on equity of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital on an allowed rate base of $560.8 million.

Cost Recovery – Tampa Electric

Tampa Electric’s fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC’s cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred.

In September 2008, Tampa Electric filed with the FPSC for approval of rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2009. In November 2008, the FPSC approved Tampa Electric’s requested rates. The rates included: 1) the 2009 projected costs for fuel and purchased power, including higher natural gas and coal prices, 2) the recovery of $132.9 million of under-recovered fuel and purchased power expenses in 2008 and 2007 and 3) the operating cost for and a return on the capital invested in the third selective catalytic reduction (SCR) project at the Big Bend Station, which also includes the operations and maintenance expense associated with the projects as required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment. Rates in 2009 also reflect a two-block fuel factor structure with a lower factor for the first 1,000 kilowatt-hours used each month.

On Mar. 5, 2009, Tampa Electric filed a mid-course adjustment of its fuel and purchased power costs to reflect the significant decline in fuel commodity prices. Tampa Electric’s re-forecasted 2009 fuel and purchased power costs using actual costs for January and updated data for the balance of the year resulted in a decrease of projected fuel and purchased power costs of $190.8 million. Additionally, the FPSC approved the refund by Tampa Electric of the 2008 final true-up amount of $35.4 million as part of the mid-course adjustment.

The FPSC determined in 2004 and 2005 that it was appropriate for Tampa Electric to recover SCR operating costs through the ECRC as well as earn a return on its SCR investment installed on Big Bend Units 1-4 for NO_x control in compliance with the environmental consent decree. The SCRs for Big Bend Units 4, 3 and 2 entered service in 2007, 2008 and 2009, respectively, and cost recovery started in 2007, 2008 and 2009, respectively. The SCR for Big Bend Unit 1 is scheduled to enter service in May 2010 and cost recovery for the capital investment, which is dependent on a filing, is expected to start in 2010.

Cost Recovery – PGS

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2008, the FPSC approved rates under PGS’ PGA for the period January 2009 through December 2009 for the recovery of the costs of natural gas purchased for its distribution customers.

In addition to PGS’ base rates and purchased gas adjustment clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover its costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers.

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Other Items

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually effective May 2009, an increase of $4.0 million from the prior year, to a FERC-authorized and FPSC-approved, self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $25.3 million and $22.7 million as of Jun. 30, 2009 and Dec. 31, 2008, respectively.

Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting treatment permitted by FAS 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.

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Details of the regulatory assets and liabilities as of Jun. 30, 2009 and Dec. 31, 2008 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Jun. 30, 2009		Dec. 31, 2008
Regulatory assets:
Regulatory tax asset(1)	$	67.0	$	65.1
Other:
Cost recovery clauses		160.4		266.8
Postretirement benefit asset		215.7		220.3
Deferred bond refinancing costs(2)		19.8		21.7
Environmental remediation		11.1		10.8
Competitive rate adjustment		3.3		4.7
Other		14.3		8.5
Total other regulatory assets		424.6		532.8
Total regulatory assets		491.6		597.9
Less: Current portion		172.4		272.6
Long-term regulatory assets	$	319.2	$	325.3
Regulatory liabilities:
Regulatory tax liability(1)	$	15.7	$	17.5
Other:
Cost recovery clauses		2.4		3.4
Environmental remediation		10.4		10.6
Transmission and delivery storm reserve		25.3		22.7
Deferred gain on property sales(3)		3.8		4.1
Accumulated reserve-cost of removal		547.9		551.2
Other		1.2		0.4
Total other regulatory liabilities		591.0		592.4
Total regulatory liabilities		606.7		609.9
Less: Current portion		26.9		21.7
Long-term regulatory liabilities	$	579.8	$	588.2

(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 the regulatory assets and the related recovery periods:

Regulatory assets

(millions)	Jun. 30, 2009		Dec. 31, 2008
Clause recoverable(1)	$	163.7	$	271.5
Components of rate base(2)		223.9		227.7
Regulatory tax assets(3)		67.0		65.1
Capital structure and other(3)		37.0		33.6
Total	$	491.6	$	597.9

(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar–for-dollar basis in the next year. The decrease between years is principally due to the recovery of previously unrecovered fuel costs.

(2) Primarily reflects allowed working capital, which is included in rate base and earns a 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 2007 consolidated federal income tax return during 2008. The U.S. federal statute of limitations remains open for the year 2008 and onward. Year 2008 is 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 2009. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from 3 to 5 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 2003 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in the Consolidated Condensed Statements of Income in accordance with FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. During the six month periods ended Jun. 30, 2009 and Jun. 30, 2008, the company recorded $0.5 million and $0.4 million, respectively, of pre-tax charges for interest only. No amounts have been recorded for penalties for the six month periods ended Jun. 30, 2009 and Jun. 30, 2008.

During the six month periods ended Jun. 30, 2009 and Jun. 30, 2008, the company experienced events that have impacted the overall effective tax rate on continuing operations. These events included depletion and the sale of a foreign subsidiary (seeNote 13).

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. There have been no significant changes to these benefit plans during the current year.

Pension Expense

(millions) Three months ended Jun. 30,	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009		2008
Components of net periodic benefit expense
Service cost	$	3.9		$	3.9		$	0.7	$	1.0
Interest cost on projected benefit obligations		8.5			8.0			2.8		3.0
Expected return on assets		(9.4	)		(9.8	)		—		—
Amortization of:
Transition obligation		—			—			0.6		0.6
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.4
Actuarial loss		2.5			1.0			—		—
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	3.0		$	4.3	$	5.0
Six months ended Jun. 30,
Components of net periodic benefit expense
Service cost	$	7.8		$	7.7		$	1.5	$	2.1
Interest cost on projected benefit obligations		16.8			15.9			5.6		6.0
Expected return on assets		(18.9	)		(19.5	)		—		—
Amortization of:
Transition obligation		—			—			1.1		1.2
Prior service (benefit) cost		(0.2	)		(0.2	)		0.4		0.8
Actuarial loss		4.3			2.0			—		—
Pension expense		9.8			5.9			8.6		10.1
Settlement cost		—			0.9			—		—
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	9.8		$	6.8		$	8.6	$	10.1

For the fiscal 2009 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 6.05% for pension benefits under its qualified pension plan as of its Jan. 1, 2009 measurement date, and a discount rate of 6.05% for its SERP and other postretirement benefits as of their Jan. 1, 2009 measurement date. During the three months ended Jun. 30, 2009, the pension plan trust experienced a net gain on its invested assets, offsetting the net loss experienced by the trust during the first quarter of 2009.

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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, 2009, TECO Energy and its subsidiaries reclassed $0.6 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. In addition, during the three months and six months ended Jun. 30, 2009, Tampa Electric Company reclassed $2.6 million and $4.6 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.

6. Short-Term Debt

At Jun. 30, 2009 and Dec. 31, 2008, the following credit facilities and related borrowings existed:

Credit Facilities

	Jun. 30, 2009						Dec. 31, 2008
(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	$	60.0	$	6.3	$	325.0	$	—	$	1.4
1-year accounts receivable facility		150.0		99.0		—		150.0		29.0		—
TECO Energy/TECO Finance:
5-year facility(2)		200.0		29.0		7.1		200.0		64.0		7.1
Total	$	675.0	$	188.0	$	13.4	$	675.0	$	93.0	$	8.5

(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 7.0 to 125.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Jun. 30, 2009 and Dec. 31, 2008 was 1.22% and 2.65%, respectively.

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7. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (OCI) for the three months and six months ended Jun. 30, 2009 and 2008, 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 (millions)	Three months ended Jun. 30,								Six months ended Jun. 30,
	Gross		Tax			Net			Gross			Tax			Net
2009
Unrealized gain on cash flow hedges	$	6.3	$	(2.3	)	$	4.0		$	3.2		$	(1.2	)	$	2.0
Add: Loss reclassified to net income		6.5		(2.4	)		4.1			13.5			(5.0	)		8.5
Gain on cash flow hedges		12.8		(4.7	)		8.1			16.7			(6.2	)		10.5
Amortization of unrecognized benefit costs		0.6		(0.2	)		0.4			1.1			(0.4	)		0.7
Reclassification to earnings loss on available-for-sale securities		—		—			—			1.7			—			1.7
Total other comprehensive income	$	13.4	$	(4.9	)	$	8.5		$	19.5		$	(6.6	)	$	12.9
				��
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	)
Accumulated Other Comprehensive Income (Loss) (millions)									Jun. 30, 2009						Dec. 31, 2008
Unrecognized pension losses and prior service costs(2)									$	(29.2	)				$	(29.8	)
Unrecognized other benefit losses, prior service costs and transition obligations(3)										10.7						10.6
Net unrealized losses from cash flow hedges(4)										(14.6	)					(25.1	)
Net unrecognized loss on available-for-sale securities										—						(1.7	)
Total accumulated other comprehensive loss									$	(33.1	)				$	(46.0	)

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

(2) Net of tax benefit of $18.1 million and $18.4 million as of Jun. 30, 2009 and Dec. 31, 2008, respectively.

(3) Net of tax expense of $6.4 million and $6.3 million as of Jun. 30, 2009 and Dec. 31, 2008, respectively.

(4) Net of tax benefit of $8.8 million and $15.0 million as of Jun. 30, 2009 and Dec. 31, 2008, respectively.

8. Earnings Per Share

In accordance with FSP EITF 03-6-1, TECO Energy adopted the two-class method for computing earnings per share (EPS) in the first quarter of 2009. FSP EITF 03-6-1 defines share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method described in FAS 128¸Earnings Per Share (FAS 128). FSP EITF 03-6-1 requires retrospective application for all prior periods presented.

The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.

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	Three months ended Jun. 30,						Six months ended Jun. 30,
(millions, except per share amounts)	2009			2008			2009			2008
Basic earnings per share
Net income	$	60.9		$	51.4		$	95.6		$	82.2
Amount allocated to nonvested participating shareholders		(0.6	)		(0.3	)		(0.8	)		(0.5	)
Income available to common shareholders—basic	$	60.3		$	51.1		$	94.8		$	81.7
Average shares outstanding common		211.7			210.4			211.6			210.1
Basic earnings per share	$	0.29		$	0.24		$	0.45		$	0.39
Diluted earnings per share
Net income	$	60.9		$	51.4		$	95.6		$	82.2
Amount allocated to nonvested participating shareholders		(0.6	)		(0.3	)		(0.8	)		(0.5	)
Income available to common shareholders—diluted	$	60.3		$	51.1		$	94.8		$	81.7
Average shares outstanding common		211.7			210.4			211.6			210.1
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		0.8			1.7			0.7			1.5
Adjusted average shares outstanding common—diluted		212.5			212.1			212.3			211.6
Diluted earnings per share	$	0.29		$	0.24		$	0.45		$	0.39
Anti-dilutive shares		5.9			4.2			6.5			4.5

9. 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 PGS divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its PGS 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, 2009, Tampa Electric Company has estimated its ultimate financial liability to be approximately $10.4 million, and this amount has been accrued in the company’s consolidated condensed 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 and Tampa Electric Company’s letters of credit and guarantees as of Jun. 30, 2009 is as follows:

Letters of Credit and Guarantees-TECO Energy

(millions) Letters of Credit and Guarantees for the Benefit of:	2009		2010-2013		After(1) 2013		Total		Liabilities Recognized at Jun. 30, 2009
Tampa Electric
Letters of credit	$	—	$	—	$	0.3	$	0.3	$	—
Guarantees:
Fuel purchase/energy management(2)		—		—		20.0		20.0		2.8
		—		—		20.3		20.3		2.8
TECO Coal
Letters of credit		—		—		6.8		6.8		—
Guarantees: Fuel purchase related(2)		—		—		1.4		1.4		1.8
		—		—		8.2		8.2		1.8
Other subsidiaries
Guarantees:
Fuel purchase/energy management(2)		94.8		—		2.9		97.7		11.0
Total	$	94.8	$	—	$	31.4	$	126.2	$	15.6
Letters of Credit-Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2009		2010-2013		After (1) 2013		Total		Liabilities Recognized at Jun. 30, 2009
Tampa Electric
Letters of credit	$	4.9	$	—	$	1.4	$	6.3	$	5.2
Total	$	4.9	$	—	$	1.4	$	6.3	$	5.2

(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2013.

(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, 2009. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance and Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Jun. 30, 2009, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants.

10. 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		Other & Eliminations			TECO Energy
2009
Revenues—external	$	563.2	$	99.7	$	160.2	$	2.0	$	0.1		$	825.2
Sales to affiliates		0.4		3.4		—		—		(3.8	)		—
Total revenues		563.6		103.1		160.2		2.0		(3.7	)		825.2
Equity earnings of unconsolidated affiliates		—		—		—		12.9		—			12.9
Depreciation		49.3		11.0		10.8		0.2		—			71.3
Total interest charges(1)		28.7		4.8		1.9		3.1		17.9			56.4
Internally allocated interest(1)		—		—		1.7		3.1		(4.8	)		—
Provision (benefit) for taxes		27.8		2.9		1.7		—		(5.1	)		27.3
Net income (loss) from continuing operations	$	48.5	$	4.6	$	10.1	$	7.9	$	(10.2	)	$	60.9
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
(millions) Six months ended Jun. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO(2) Guatemala		Other & Eliminations			TECO Energy
2009
Revenues—external	$	1,070.5	$	246.2	$	328.3	$	4.1	$	0.1		$	1,649.2
Sales to affiliates		0.7		9.9		—		—		(10.6	)		—
Total revenues		1,071.2		256.1		328.3		4.1		(10.5	)		1,649.2
Equity earnings of unconsolidated affiliates		—		—		—		21.7		—			21.7
Depreciation		97.3		21.8		21.4		0.4		0.1			141.0
Total interest charges(1)		56.9		9.5		3.7		6.3		36.3			112.7
Internally allocated interest(1)		—		—		3.2		6.2		(9.4	)		—
Provision (benefit) for taxes		37.2		10.1		3.0		9.6		(14.8	)		45.1
Net income (loss) from continuing operations	$	66.8	$	15.8	$	18.1	$	21.1	$	(26.2	)	$	95.6
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

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Segment Information⁽¹⁾

(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO(2) Guatemala		Other & Eliminations			TECO Energy
At Jun. 30, 2009
Goodwill	$	—	$	—	$	—	$	59.4	$	—		$	59.4
Investment in unconsolidated affiliates		—		—		—		273.6		—			273.6
Other non-current investments		—		—		—		—		9.8			9.8
Total assets	$	5,684.7	$	851.3	$	323.7	$	378.5	$	(8.1	)	$	7,230.1
At Dec. 31, 2008
Goodwill	$	—	$	—	$	—	$	59.4	$	—		$	59.4
Investment in unconsolidated affiliates		—		—		—		284.0		—			284.0
Other non-current investments		—		—		—		—		21.3			21.3
Total assets	$	5,538.8	$	878.0	$	309.1	$	383.1	$	38.4		$	7,147.4

(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 2009 and 2008 were at a pretax rate of 7.15% and 7.25%, 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 $12.7 million and $29.6 million for the three months ended Jun. 30, 2009 and 2008, respectively and $31.4 million and $59.5 million for the six months ended Jun. 30, 2009 and 2008, respectively. Net income from continuing operations for the six months ended Jun. 30, 2009 includes the gain on the sale of a 16.5% interest in the Central American fiber optic telecommunications provider Navega (SeeNote 13).

11. Accounting for Derivative Instruments and Hedging Activities

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

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

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

• To limit the exposure to price fluctuations for physical purchases of fuel and explosives at TECO Coal.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

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

The company applies the provisions of SFAS 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138,Accounting for Certain Derivative Instruments and Certain Hedging Activities, SFAS 149,Amendment on Statement 133 on Derivative Instruments and Hedging Activities, and SFAS 161,Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133(FAS 161). These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

FAS 161 became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. FAS 161 requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. To meet the objectives, FAS 161 requires qualitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. The company adopted FAS 161 effective Jan. 1, 2009.

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The company applies FAS 71 for financial instruments used to hedge the purchase of natural gas for our regulated companies. The provisions of FAS 71, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities to reflect the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (seeNote 3).

A company’s physical contracts qualify for the normal purchase/normal sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Jun. 30, 2009, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at Jun. 30, 2009 and Dec. 31, 2008:

	Total Derivatives
(millions)	Jun. 30, 2009		Dec. 31, 2008
Current assets	$	0.2	$	—
Long-term assets		0.6		0.1
Total assets	$	0.8	$	0.1
Current liabilities(1)	$	113.7	$	141.8
Long-term liabilities		10.3		19.4
Total liabilities	$	124.0	$	161.2

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with FIN 39, Offsetting of Amounts Related to Certain Contracts.The Consolidated Condensed Balance Sheets reflect the company’s net positions reduced by posted collateral of $9.7 million at Dec. 31, 2008, permitted by FSP FIN 39-1,Amendment of FASB Interpretation No. 39. As of Jun. 30, 2009, there was no outstanding collateral held or posted with counterparties.

The following table presents the derivative hedges of heating oil contracts at Jun. 30, 2009 and Dec. 31, 2008 to limit the exposure to changes in the market price for diesel fuel:

	Heating Oil Derivatives
(millions)	Jun. 30, 2009		Dec. 31, 2008
Current assets	$	—	$	—
Long-term asset		—		—
Total assets	$	—	$	—
Current liability	$	9.5	$	21.4
Long-term liability		1.0		4.6
Total liabilities	$	10.5	$	26.0

The following table presents the derivative hedges of natural gas contracts at Jun. 30, 2009 and Dec. 31, 2008 to limit the exposure to changes in market price for natural gas used to produce energy, natural gas purchased for resale to customers and natural gas used as a component price for explosives purchased:

	Natural Gas Derivatives
(millions)	Jun. 30, 2009		Dec. 31, 2008
Current assets	$	0.2	$	—
Long-term asset		0.6		0.1
Total assets	$	0.8	$	0.1
Current liability	$	104.2	$	120.4
Long-term liability		9.3		14.8
Total liabilities	$	113.5	$	135.2

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The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Jun. 30, 2009 is a net loss of $14.6 million after tax and accumulated amortization. This compares to a net loss of $25.1 million in AOCI after tax and accumulated amortization at Dec. 31, 2008.

The following table presents the fair values and locations of derivative instruments recorded in the balance sheet at Jun. 30, 2009:

	Derivatives Designated As Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) at Jun. 30, 2009	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Heating oil derivatives:
Current	Derivative assets	$	—	Derivative liabilities	$	9.5
Long-term	Derivative assets		—	Derivative liabilities		1.0
Natural gas derivatives:
Current	Derivative assets		0.2	Derivative liabilities		104.2
Long-term	Derivative assets		0.6	Derivative liabilities		9.3
Total derivatives designated as hedging instruments		$	0.8		$	124.0

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the balance sheet as of Jun. 30, 2009:

	Asset Derivatives			Liability Derivatives
(millions) at Jun. 30, 2009	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.2	Regulatory assets	$	103.8
Long-term	Regulatory liabilities		0.6	Regulatory assets		9.3
Total		$	0.8		$	113.1

(1) Natural gas derivatives are deferred, in accordance with FAS 71 and all increases and decreases in the cost of natural gas supply are passed on to customers with the fuel recovery clause mechanism. As gains and losses are realized in future periods, they will be recorded as fuel costs in the Consolidated Condensed Statements of Income.

Based on the fair value of the instruments at Jun. 30, 2009, net pretax losses of $103.6 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

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The following table presents the effect of hedging instruments on OCI and income for the quarter ended Jun. 30, 2009:

(millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Effective Portion(1)		Effective Portion(1)
Interest rate contracts:	$	—	Interest expense	$	(0.6	)
Commodity Contracts:
Heating oil derivatives		4.0	Mining related costs		(3.3	)
Natural gas derivatives		—	Mining related costs		(0.2	)
Total	$	4.0		$	(4.1	)

(1) Changes in OCI and AOCI are reported in after-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Jun. 30, 2009, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the quarter ended Jun. 30, 2009:

(millions) For the quarter ended Jun. 30, 2009	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI(1)		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Heating oil derivatives	$	(10.5	)	$	4.0	$	(3.3	)
Interest rate swaps		—			—		(0.6	)
Natural gas derivatives		(112.7	)		—		(0.2	)
Total	$	(123.2	)	$	4.0	$	(4.1	)

(1) Changes in OCI and AOCI are reported in after-tax dollars.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2011 for both financial natural gas and financial heating oil fuel contracts. The following table presents by commodity type the company’s derivative volumes at Jun. 30, 2009 that are expected to settle each year:

(millions)	Heating Oil Contracts (Gallons)		Natural Gas Contracts (MMBTUs)
Year	Physical	Financial	Physical	Financial
2009	—	6.4	—	28.2
2010	—	6.6	—	20.5
2011	—	3.4	—	4.5
Total	—	16.4	—	53.2

The company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with diesel fuel and natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Jun. 30, 2009, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies while the remaining are either rated below investment grade or are not rated by rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) Edison Electric Institute agreements (EEI)—standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA)—standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB)—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

The company has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. The company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of Jun. 30, 2009, substantially all positions with counterparties are net liabilities.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where Tampa Electric Company is the counterparty, Tampa Electric Company’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including Tampa Electric Company’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at Jun. 30, 2009:

(millions) At Jun. 30, 2009			Derivative
Contingent Feature	Fair Value Asset/(Liability)		Exposure Asset/(Liability)		Posted Collateral
Credit Rating	$	123.2	$	123.5	$	—
Total	$	123.2	$	123.5	$	—

12. Fair Value Measurements

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.

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, 2009. As required by FAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and heating oil swaps, the market approach was used in determining fair value. For other investments, the income approach was used.

25

Recurring Fair Value Measures

(millions)	At fair value as of Jun. 30, 2009
	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	—	$	0.8	$	—	$	0.8
Other investments		—		—		1.9		1.9
Total	$	—	$	0.8	$	1.9	$	2.7
Liabilities
Natural gas swaps	$	—	$	113.4	$	—	$	113.4
Heating oil swaps		—		10.6		—		10.6
Total	$	—	$	124.0	$	—	$	124.0

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

The primary pricing inputs in determining the fair value of interest rate swaps are LIBOR swap rates as reported by Bloomberg. For each instrument, the projected forward swap rate is used to determine the stream of cash flows over the life of the contract. The cash flows are then discounted using a spot discount rate to determine the fair value. A $1.9 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.

The fair value of TECO Energy’s long-term debt at Jun. 30, 2009 is $3,210.8 million. The determination of fair value for these instruments includes obtaining prices from third-party financial institutions and in some cases utilizing a model to discount the future cash flows produced by the instruments by a rate determined by applying a spread based on TECO Energy’s or Tampa Electric Company’s credit ratings (also provided by third-party financial institutions) to U.S. Treasury rates.

Other investments reflect an auction rate security backed by pools of student loans. As a result of auction failures and the lack of an alternative active market, the valuation technique for this security is an income approach using a discounted cash flow model and is considered Level 3 within FAS 157’s three tier fair value hierarchy. The model assumes a continuation of failed auctions and interest payments at the default rate. Cash flows are discounted at a rate approximating current market spreads for similar securities. The valuation at Jun. 30, 2009 reflects a discount rate of 15%; a 100 basis point change in the discount rate results in a $0.2 million change in value. Settlements during the quarter reflect sales of securities at fair value of $7.3 million.

Based on the protracted disruption of the market for these securities and the uncertain potential for its recovery, the company no longer expects to hold the security indefinitely to recover the original value. Accordingly, the impairment was deemed other-than-temporary and recognized in “Other income” on the Consolidated Condensed Statement of Income for the first quarter.

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Jun. 30, 2009, the fair value of derivatives was not materially affected by nonperformance risk. Net positions with substantially all counterparties were liability positions.

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

(millions)	Auction Rate Securities
Balance at Dec. 31, 2008	$	13.3
Transfers to Level 3		—
Change in fair market value included in earnings		(4.1	)
Balance at Mar. 31, 2009	$	9.2
Transfers to Level 3		—
Change in fair market value included in earnings		—
Settled		(7.3	)
Balance at Jun. 30, 2009	$	1.9

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13. Mergers, Acquisitions and Dispositions

Sale of Navega

On Mar. 13, 2009, TECO Guatemala sold its 16.5% interest in the Central American fiber optic telecommunications provider Navega. The sale resulted in a pre-tax gain of $18.3 million and total proceeds of $29.0 million.

14. Subsequent Events

The company has evaluated all events subsequent to the balance sheet date of Jun. 30, 2009 through the date of issuance, Jul. 31, 2009.

Organizational changes

On Jul. 29, 2009 the Board of Directors of TECO Energy approved a new executive management structure. The company expects to recognize a restructuring charge in the quarter ending Sep. 30, 2009 as a result of this management change and additional steps that the company expects to undertake to further reduce expenses by integrating operations and support functions.

Issuance of Tampa Electric Company 6.10% Notes due 2018

On Jul. 7, 2009, Tampa Electric Company completed an offering of $100 million aggregate principal amount of 6.10% Notes due 2018 (the “Notes”). The Notes form a single series and are fungible with Tampa Electric Company’s 6.10% notes due 2018 issued on May 16, 2008 in the aggregate principal amount of $150 million. The Notes were sold at 102.988% of par. The offering resulted in net proceeds to Tampa Electric Company (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $102.1 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Tampa Electric Company may redeem all or any part of the 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 Notes to be redeemed or (ii) the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the Indenture), plus 35 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

Tampa Electric Company’s Motion for Reconsideration

On May 15, 2009, Tampa Electric filed a Motion for Reconsideration regarding the calculation of the annual revenue requirements approved by the FPSC. On Jul. 14, 2009, the FPSC approved Tampa Electric’sMotion (seeNote 3).

27

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, 2009 and Dec. 31, 2008, and the results of operations and cash flows for the periods ended Jun. 30, 2009 and 2008. The results of operations for the three months and six months ended Jun. 30, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009. 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/A for the year ended Dec. 31, 2008 and to the notes on pages 34-46 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Jun. 30, 2009 and Dec. 31, 2008	29-30
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended Jun. 30, 2009 and 2008	31-32
Consolidated Condensed Statements of Cash Flows for the six month periods ended Jun. 30, 2009 and 2008	33
Notes to Consolidated Condensed Financial Statements	34-46

28

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Jun. 30, 2009			Dec. 31, 2008
Property, plant and equipment
Utility plant in service
Electric	$	5,730.0		$	5,514.9
Gas		993.3			964.4
Construction work in progress		458.5			462.4
Property, plant and equipment, at original costs		7,181.8			6,941.7
Accumulated depreciation		(1,923.7	)		(1,868.5	)
		5,258.1			5,073.2
Other property		4.3			4.5
Total property, plant and equipment, net		5,262.4			5,077.7
Current assets
Cash and cash equivalents		5.6			3.6
Receivables, less allowance for uncollectibles of $2.6 and $1.6 at Jun. 30, 2009 and Dec. 31, 2008, respectively		256.1			236.1
Inventories, at average cost
Fuel		105.8			76.8
Materials and supplies		57.3			61.8
Current regulatory assets		172.4			272.6
Current derivative asset		0.2			—
Taxes receivable		—			0.2
Prepayments and other current assets		13.3			14.1
Total current assets		610.7			665.2
Deferred debits
Unamortized debt expense		20.8			22.3
Long-term regulatory assets		319.2			325.3
Long-term derivative assets		0.6			0.1
Other		16.9			18.0
Total deferred debits		357.5			365.7
Total assets	$	6,230.6		$	6,108.6

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

29

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets –continued

Unaudited

Liabilities and Capital (millions)	Jun. 30, 2009			Dec. 31, 2008
Capital
Common stock	$	1,802.4		$	1,802.4
Accumulated other comprehensive loss		(6.5	)		(6.8	)
Retained earnings		300.2			295.0
Total capital		2,096.1			2,090.6
Long-term debt, less amount due within one year		1,895.0			1,894.8
Total capitalization		3,991.1			3,985.4
Current liabilities
Long-term debt due within one year		5.5			5.5
Notes payable		159.0			29.0
Accounts payable		220.1			262.5
Customer deposits		148.6			144.6
Current regulatory liabilities		26.9			21.7
Current derivative liabilities		103.8			119.4
Current deferred income taxes		6.8			36.6
Interest accrued		31.0			27.1
Taxes accrued		36.0			20.1
Other		11.5			11.2
Total current liabilities		749.2			677.7
Deferred credits
Non-current deferred income taxes		498.6			447.6
Investment tax credits		11.0			11.2
Long-term derivative liabilities		9.3			14.8
Long-term regulatory liabilities		579.8			588.2
Other		391.6			383.7
Total deferred credits		1,490.3			1,445.5
Total liabilities and capital	$	6,230.6		$	6,108.6

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

	Three months ended Jun. 30,
(millions)	2009			2008
Revenues
Electric (includes franchise fees and gross receipts taxes of $22.7 in 2009 and $21.5 in 2008)	$	563.5		$	546.0
Gas (includes franchise fees and gross receipts taxes of $5.5 in 2009 and $6.1 in 2008)		99.7			184.3
Total revenues		663.2			730.3
Expenses
Operations
Fuel		225.5			176.2
Purchased power		56.1			115.9
Cost of natural gas sold		50.9			133.8
Other		80.9			71.9
Maintenance		31.8			32.3
Depreciation		60.3			55.3
Taxes, federal and state		30.4			26.4
Taxes, other than income		44.2			44.3
Total expenses		580.1			656.1
Income from operations		83.1			74.2
Other income
Allowance for other funds used during construction		2.5			1.7
Taxes, non-utility federal and state		(0.3	)		(0.6	)
Other income, net		1.2			2.5
Total other income		3.4			3.6
Interest charges
Interest on long-term debt		31.4			30.2
Other interest		3.0			2.8
Allowance for borrowed funds used during construction		(1.0	)		(0.7	)
Total interest charges		33.4			32.3
Net income		53.1			45.5
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) on cash flow hedges		0.1			2.8
Total other comprehensive income (loss), net of tax		0.1			2.8
Comprehensive income	$	53.2		$	48.3

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

31

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Six months ended Jun. 30,
(millions)	2009			2008
Revenues
Electric (includes franchise fees and gross receipts taxes of $44.8 in 2009 and $40.4 in 2008)	$	1,071.0		$	1,007.4
Gas (includes franchise fees and gross receipts taxes of $13.5 in 2009 and $13.6 in 2008)		246.2			363.3
Total revenues		1,317.2			1,370.7
Expenses
Operations
Fuel		454.2			339.8
Purchased power		98.3			197.8
Cost of natural gas sold		139.2			252.8
Other		157.8			143.1
Maintenance		68.0			66.4
Depreciation		119.1			110.8
Taxes, federal and state		46.9			41.0
Taxes, other than income		92.4			87.9
Total expenses		1,175.9			1,239.6
Income from operations		141.3			131.1
Other income
Allowance for other funds used during construction		5.8			3.0
Taxes, non-utility federal and state		(0.4	)		(0.9	)
Other income, net		2.2			4.0
Total other income		7.6			6.1
Interest charges
Interest on long-term debt		62.8			61.6
Other interest		5.8			5.4
Allowance for borrowed funds used during construction		(2.3	)		(1.2	)
Total interest charges		66.3			65.8
Net income		82.6			71.4
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) on cash flow hedges		0.3			(2.2	)
Total other comprehensive income (loss), net of tax		0.3			(2.2	)
Comprehensive income	$	82.9		$	69.2

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

	Six months ended Jun. 30,
(millions)	2009			2008
Cash flows from operating activities
Net income	$	82.6		$	71.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		119.1			110.8
Deferred income taxes		17.3			55.0
Investment tax credits, net		(0.2	)		(0.9	)
Allowance for funds used during construction		(5.8	)		(3.0	)
Deferred recovery clause		83.3			(92.4	)
Receivables, less allowance for uncollectibles		(20.0	)		(41.4	)
Inventories		(24.5	)		(13.4	)
Prepayments		0.8			(5.2	)
Taxes accrued		16.1			25.5
Interest accrued		4.0			6.9
Accounts payable		(12.1	)		93.5
Gain on sale of assets		(0.3	)		(0.1	)
Other		22.5			(8.8	)
Cash flows from operating activities		282.8			197.9
Cash flows from investing activities
Capital expenditures		(339.3	)		(247.1	)
Allowance for funds used during construction		5.8			3.0
Net proceeds from sale of assets		0.1			—
Cash flows used in investing activities		(333.4	)		(244.1	)
Cash flows from financing activities
Proceeds from long-term debt		—			327.9
Common stock		—			150.0
Repayment of long-term debt/Purchase in lieu of redemption		—			(286.7	)
Net increase (decrease) in short-term debt		130.0			(25.0	)
Dividends		(77.4	)		(71.8	)
Cash flows from financing activities		52.6			94.4
Net increase in cash and cash equivalents		2.0			48.2
Cash and cash equivalents at beginning of period		3.6			11.9
Cash and cash equivalents at end of period	$	5.6		$	60.1

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, 2009 and Dec. 31, 2008, and the results of operations and cash flows for the periods ended Jun. 30, 2009 and 2008. The results of operations for the three month and six month periods ended Jun. 30, 2009 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2009.

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, 2009 and Dec. 31, 2008, unbilled revenues of $56.6 million and $47.4 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 $56.1 million and $98.3 million for the three months and six months ended Jun. 30, 2009, respectively, compared to $115.9 million and $197.8 million for the three months and six months ended Jun. 30, 2008, 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 $28.2 million and $58.3 million, respectively, for the three months and six months ended Jun. 30, 2009, compared to $27.6 million and $54.0 million, respectively, for the three months and six months ended Jun. 30, 2008. 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 $28.2 million and $58.2 million, respectively, for the three months and six months ended Jun. 30, 2009, compared to $27.6 million and $53.8 million, respectively, for the three months and six months ended Jun. 30, 2008.

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

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles

In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (FAS 168). FAS 168 replaces FAS 162, The Hierarchy of Generally Accepted Accounting Principles (FAS 162). It names the FASB Accounting Standards Codification (Codification) as the single source of authoritative U.S. Generally Accepted Accounting Principles (GAAP) for non-governmental entities recognized by the FASB. FAS 168 is effective for reporting periods ending after

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Sep. 15, 2009, and once effective, will supersede all U.S. GAAP accounting standards, aside from rules and interpretive releases issued by the Securities and Exchange Commission (SEC). The Codification is not intended to change GAAP; rather, it will change the referencing of U.S. GAAP. Therefore, it is not expected to have an impact on the company’s results of operations, statement of position or cash flows.

Accounting for Transfers of Financial Assets

In June 2009, the FASB issued SFAS No. 166,Accounting for Transfers of Financial Assets (FAS 166). FAS 166 revises SFAS 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement No. 125 and requires companies to provide more information about sales of securitized financial assets. It is effective for fiscal periods beginning after Nov. 15, 2009. The new requirements will not have an impact on the company’s results of operations, statement of position or cash flows.

Variable Interest Entities

In June 2009, the FASB issued SFAS No.167,Amendments to FASB Interpretation No. 46(R) (FAS 167). FAS 167 changes the way a company determines if a variable interest entity (VIE) should be consolidated. It is effective for fiscal years beginning after Nov. 15, 2009. Tampa Electric Company is evaluating the potential effects FAS 167 may have on its results of operations, statement of position or cash flows.

Subsequent Events

In May 2009, the FASB issued SFAS No. 165,Subsequent Events (FAS 165). FAS 165 requires companies to disclose the date through which they evaluated subsequent events and whether that date corresponds with the filing of their financial statements. It is effective for fiscal periods ending after Jun. 15, 2009, and the adoption does not have an effect on Tampa Electric Company’s 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.

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 FASB Staff Position (FSP) 157-2,Effective Date of FASB Statement No. 157, 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 non-financial 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 and Jan. 1, 2009 for non-financial assets and liabilities. No adoption adjustment was necessary. Financial assets and liabilities of the company measured at fair value include derivatives and certain investments, for which fair values are primarily based on observable inputs. Non-financial assets and liabilities of the company measured at fair value include asset retirement obligations (AROs) when they are incurred.

In April 2009, the FASB issued FSP FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4),FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2), and FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1) to address fair value valuation concerns in the current market environment.

FSP FAS 157-4 affirms that when the market for an asset is not active, the objective of fair value is the price that would be received to sell the asset in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date in the inactive market. The determination of whether a transaction was not orderly should be based on the weight of the evidence. The FSP requires an entity to disclose a change in valuation technique and the related inputs resulting from the application of the FSP and to quantify its effects. Retrospective application is not permitted. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. This FSP did not materially affect the company’s results of operations, statement of position or cash flows. The company adopted this FSP effective Apr. 1, 2009.

FSP FAS 115-2 and FAS 124-2 is applicable to debt securities and require that a company recognize the credit component of an other-than-temporary impairment in earnings and the remaining portion in other comprehensive income if management asserts it does not have the intent to sell the security and it is more likely than not it will not have to sell the security before recovery of its cost basis. It requires an entity to present separately in the financial statement where the components of other comprehensive income are reported, amounts recognized in accumulated other comprehensive income related to the noncredit portion of other-than-temporary impairments recognized for available-for-sale and held-to-maturity debt securities. Additionally, disclosure requirements are amended and will be required for interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. The FSP did not materially affect the company’s results of operations, statement of position or cash flows. The company adopted this FSP effective Apr. 1, 2009.

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FSP FAS 107-1 and APB 28-1 requires an entity to disclose fair value information, including methods and significant assumptions in measuring fair value, of financial instruments within the scope of FAS 107 in interim periods. The FSP is effective for interim and annual periods ending after Jun. 15, 2009. The new disclosure requirements of FSP FAS 107-1 and APB 28-1 had no effect on the company’s results of operations, statement of position or cash flows. The company adopted this FSP effective Apr. 1, 2009.

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued FSP No. FAS 132(R)-1,Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1). This FSP requires enhanced disclosures about plan assets of defined benefit pension plans or other postretirement plans, including the concentrations of risk in those plans. The guidance in FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009. FSP FAS 132(R)-1 will be significant to the company’s financial statement disclosures but will have no effect on the company’s results of operations, statement of position or cash flows.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued 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. FAS 161 is significant to the company’s financial statement disclosures but has no effect on its results of operations, statement of position or cash flows. The company adopted FAS 161 effective Jan. 1, 2009.

Additionally, in April 2008, the FASB revised Statement 133 Implementation Issues Nos. I1 and K4 to reflect the enhanced disclosures required by FAS 161. These revisions are significant to the company’s financial statement disclosures but have no effect on its results of operations, statement of position or cash flows.

3. Regulatory

As discussed inNote 1, Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005). However, pursuant to a waiver granted in accordance with FERC’s regulations, Tampa Electric is not subject to certain accounting, record-keeping and reporting requirements prescribed by FERC’s regulations under PUHCA 2005.

Base Rates – Tampa Electric

In order for Tampa Electric to continue meeting customers’ growing needs for reliable, efficient and affordable electric service, Tampa Electric filed with the FPSC for a base rate increase in August 2008. On Mar. 17, 2009, the FPSC approved an increase to base rates, effective on May 7, 2009, of $104.2 million that reflects a return on equity of 11.25%, which is the middle of a range between 10.25% and 12.25%. Additionally, the FPSC approved a step increase of $33.6 million effective Jan. 1, 2010 for capital additions placed in service in 2009 bringing the total approved base rate increase to $137.8 million.

On May 15, 2009, Tampa Electric filed a Motion for Reconsideration regarding the calculation of the annual revenue requirements approved by the FPSC. On Jul. 14, 2009, the FPSC approved Tampa Electric’s Motion resulting in an overall weighted cost of capital of 8.29%, compared to the 8.11% previously approved. This change will increase the previously approved $104.2 million to $113.6 and the $33.6 million step increase to $34.1 million, bringing the total approved base rate increase to $147.7 million.

As part of its base rate increase, Tampa Electric also requested modifications to its cost of service methodology and rate design, which were also approved by the FPSC. In addition to several base rate design changes, residential base rates reflect a two-block structure which offers a lower rate for the first 1,000 kilowatt-hours of usage each month. The new base rates and service charges will remain in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties.

Base Rates – PGS

Recognizing the significant decline in ROE, PGS filed with the FPSC for a $3.7 million interim rate increase in August 2008. The FPSC approved an interim rate increase of $2.4 million effective Oct. 29, 2008. PGS also filed in August 2008 with the FPSC for a $26.5 million base rate increase. On May 5, 2009, the FPSC approved a base rate increase of $19.2 million that became effective on Jun. 18, 2009 and reflects a return on equity of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital on an allowed rate base of $560.8 million.

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Cost Recovery – Tampa Electric

Tampa Electric’s fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC’s cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred.

In September 2008, Tampa Electric filed with the FPSC for approval of rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2009. In November 2008, the FPSC approved Tampa Electric’s requested rates. The rates included: 1) the 2009 projected costs for fuel and purchased power, including higher natural gas and coal prices, 2) the recovery of $132.9 million of under-recovered fuel and purchased power expenses in 2008 and 2007 and 3) the operating cost for and a return on the capital invested in the third selective catalytic reduction (SCR) project at the Big Bend Station, which also includes the operations and maintenance expense associated with the projects as required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment. Rates in 2009 also reflect a two-block fuel factor structure with a lower factor for the first 1,000 kilowatt-hours used each month.

On Mar. 5, 2009, Tampa Electric filed a mid-course adjustment of its fuel and purchased power costs to reflect the significant decline in fuel commodity prices. Tampa Electric’s re-forecasted 2009 fuel and purchased power costs using actual costs for January and updated data for the balance of the year resulted in a decrease of projected fuel and purchased power costs of $190.8 million. Additionally, the FPSC approved the refund by Tampa Electric of the 2008 final true-up amount of $35.4 million as part of the mid-course adjustment.

The FPSC determined in 2004 and 2005 that it was appropriate for Tampa Electric to recover SCR operating costs through the ECRC as well as earn a return on its SCR investment installed on Big Bend Units 1-4 for NO_x control in compliance with the environmental consent decree. The SCRs for Big Bend Units 4, 3 and 2 entered service in 2007, 2008 and 2009, respectively, and cost recovery started in 2007, 2008 and 2009, respectively. The SCR for Big Bend Unit 1 is scheduled to enter service in May 2010 and cost recovery for the capital investment, which is dependent on a filing, is expected to start in 2010.

Cost Recovery – PGS

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment (PGA) clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2008, the FPSC approved rates under PGS’ PGA for the period January 2009 through December 2009 for the recovery of the costs of natural gas purchased for its distribution customers.

In addition to PGS’ base rates and purchased gas adjustment clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover its costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers.

Other Items

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually effective May 2009, an increase of $4.0 million from the prior year, to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $25.3 million and $22.7 million as of Jun. 30, 2009 and Dec. 31, 2008, respectively.

Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting treatment permitted by FAS 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.

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Details of the regulatory assets and liabilities as of Jun. 30, 2009 and Dec. 31, 2008 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Jun. 30, 2009		Dec. 31, 2008
Regulatory assets:
Regulatory tax asset(1)	$	67.0	$	65.1
Other:
Cost recovery clauses		160.4		266.8
Postretirement benefit asset		215.7		220.3
Deferred bond refinancing costs(2)		19.8		21.7
Environmental remediation		11.1		10.8
Competitive rate adjustment		3.3		4.7
Other		14.3		8.5
Total other regulatory assets		424.6		532.8
Total regulatory assets		491.6		597.9
Less: Current portion		172.4		272.6
Long-term regulatory assets	$	319.2	$	325.3
Regulatory liabilities:
Regulatory tax liability(1)	$	15.7	$	17.5
Other:
Cost recovery clauses		2.4		3.4
Environmental remediation		10.4		10.6
Transmission and delivery storm reserve		25.3		22.7
Deferred gain on property sales(3)		3.8		4.1
Accumulated reserve-cost of removal		547.9		551.2
Other		1.2		0.4
Total other regulatory liabilities		591.0		592.4
Total regulatory liabilities		606.7		609.9
Less: Current portion		26.9		21.7
Long-term regulatory liabilities	$	579.8	$	588.2
(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 the regulatory assets and the related recovery periods:

Regulatory assets

(millions)	Jun. 30, 2009		Dec. 31, 2008
Clause recoverable(1)	$	163.7	$	271.5
Components of rate base(2)		223.9		227.7
Regulatory tax assets(3)		67.0		65.1
Capital structure and other(3)		37.0		33.6
Total	$	491.6	$	597.9
(1)    To be recovered through cost recovery clauses approved by the FPSC on a dollar-for-dollar basis in the next year. The decrease between years is principally due to the recovery of previously unrecovered fuel costs. (2)    Primarily reflects allowed working capital, which is included in rate base and earns a rate of return as permitted by the FPSC. (3)    “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs, which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.

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4. Income Taxes

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Tampa Electric Company’s effective tax rates for the six months ended Jun. 30, 2009 and Jun. 30, 2008 differ from the statutory rate principally due to state income taxes, equity portion of Allowance for Funds Used During Construction (AFUDC), 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 return for the year 2007 during 2008. The U.S. federal statute of limitations remains open for the year 2008 and onward. Year 2008 is 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 2009. 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 2005 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 2009.

5. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Other than the remeasurement of the Supplemental Executive Retirement Plan (SERP) plan obligations at Jan. 1, 2008 for certain participant retirements and 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.

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, 2009 and 2008, respectively, was $4.2 million and $2.1 million for pension benefits, and $3.4 million and $3.5 million for other postretirement benefits. For the six months ended Jun. 30, 2009 and 2008, respectively, net benefit expenses were $7.6 million and $4.2 million for pension benefits, and $6.8 million and $7.0 million for other postretirement benefits.

Included in the benefit expenses discussed above, for the three months and six months ended Jun. 30, 2009, Tampa Electric Company reclassed $2.6 million and $4.6 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

For the fiscal 2009 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 6.05% for pension benefits under its qualified pension plan as of its Jan. 1, 2009 measurement date, and a discount rate of 6.05% for its SERP and other postretirement benefits as of their Jan. 1, 2009 measurement date.

6. Short-Term Debt

At Jun. 30, 2009 and Dec. 31, 2008, the following credit facilities and related borrowings existed:

Credit Facilities

	Jun. 30, 2009						Dec. 31, 2008
(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	$	60.0	$	6.3	$	325.0	$	—	$	1.4
1-year accounts receivable facility		150.0		99.0		—		150.0		29.0		—
Total	$	475.0	$	159.0	$	6.3	$	475.0	$	29.0	$	1.4

(1) Borrowings outstanding are reported as notes payable.

These credit facilities require commitment fees ranging from 7.0 to 125.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Jun. 30, 2009 and Dec. 31, 2008 was 1.04% and 2.13%, respectively.

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7. 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, 2009, Tampa Electric Company has estimated its ultimate financial liability to be approximately $10.4 million, and this amount has been accrued in the company’s consolidated condensed 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, 2009, Tampa Electric Company was not obligated under guarantees, but had $6.3 million of letters of credit outstanding.

Letters of Credit -Tampa Electric Company

(millions) Letters of Credit for the Benefit of:	2009		2010-2013		After (1) 2013		Total		Liabilities Recognized at Jun. 30, 2009
Tampa Electric
Letters of credit	$	4.9	$	—	$	1.4	$	6.3	$	5.2
Total	$	4.9	$	—	$	1.4	$	6.3	$	5.2

(1) These renew annually and are shown on the basis that they will continue to renew beyond 2013.

At Jun. 30, 2009, TECO Energy had provided a $20.0 million fuel purchase guarantee and a $0.3 million letter of credit on behalf of Tampa Electric Company.

Financial Covenants

In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Jun. 30, 2009, Tampa Electric Company was in compliance with all applicable financial covenants.

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8. Segment Information

(millions) Three months ended Jun. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2009
Revenues - external	$	563.2	$	99.7	$	—		$	662.9
Sales to affiliates		0.4		3.4		(3.5	)		0.3
Total revenues		563.6		103.1		(3.5	)		663.2
Depreciation		49.3		11.0		—			60.3
Total interest charges		28.6		4.8		—			33.4
Provision for taxes		27.8		2.9		—			30.7
Net income	$	48.5	$	4.6	$	—		$	53.1
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
Six months ended Jun. 30,
2009
Revenues - external	$	1,070.5	$	246.2	$	—		$	1,316.7
Sales to affiliates		0.7		9.9		(10.1	)		0.5
Total revenues		1,071.2		256.1		(10.1	)		1,317.2
Depreciation		97.3		21.8		—			119.1
Total interest charges		56.8		9.5		—			66.3
Provision for taxes		37.2		10.1		—			47.3
Net income	$	66.8	$	15.8	$	—		$	82.6
Total assets at Jun. 30, 2009	$	5,439.7	$	800.5	$	(9.6	)	$	6,230.6
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 Dec. 31, 2008	$	5,294.7	$	823.4	$	(9.5	)	$	6,108.6

9. Accounting for Derivative Instruments and Hedging Activities

From time to time, Tampa Electric Company enters into futures, forwards, swaps and option contracts for the following purposes:

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

• To limit the exposure to interest rate fluctuations on debt securities.

Tampa Electric Company uses derivatives only to reduce normal operating and market risks, not for speculative purposes. Tampa Electric Company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

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

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Tampa Electric Company applies the provisions of SFAS 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138,Accounting for Certain Derivative Instruments and Certain Hedging Activity, SFAS 149,Amendment on Statement 133 on Derivative Instruments and Hedging Activities, and SFAS 161,Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133(FAS 161). These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

FAS 161 became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. FAS 161 requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. To meet the objectives, FAS 161 requires qualitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. Tampa Electric Company adopted FAS 161 effective Jan. 1, 2009.

Tampa Electric Company applies FAS 71 for financial instruments used to hedge the purchase of natural gas for the regulated companies. The provisions of FAS 71, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities to reflect the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (SeeNote 3).

A company’s physical contracts qualify for the normal purchase/normal sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Jun. 30, 2009, all of Tampa Electric Company’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at Jun. 30, 2009 and Dec. 31, 2008 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

	Natural Gas Derivatives
(millions)	Jun. 30, 2009		Dec. 31, 2008
Current assets	$	0.2	$	—
Long-term assets		0.6		0.1
Total assets	$	0.8	$	0.1
Current liabilities(1)	$	103.8	$	120.1
Long-term liabilities		9.3		14.8
Total liabilities	$	113.1	$	134.9
(1)     Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with FIN 39, Offsetting of Amounts Related to Certain Contracts.The Consolidated Condensed Balance Sheet as of Dec. 31, 2008 reflects Tampa Electric Company’s net positions reduced by posted collateral of $0.7 million permitted by FSP FIN 39-1,Amendment of FASB Interpretation No. 39. As of Jun. 30, 2009, there was no outstanding collateral held or posted with counterparties.

The ending balance in accumulated other comprehensive income (AOCI) related to previously settled interest rate swaps at Jun. 30, 2009 is a net loss of $6.5 million after tax and accumulated amortization. This compares to a net loss of $6.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2008.

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The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the balance sheet as of Jun. 30, 2009:

	Asset Derivatives			Liability Derivatives
(millions) at Jun. 30, 2009	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.2	Regulatory assets	$	103.8
Long-term	Regulatory liabilities		0.6	Regulatory assets		9.3
Total		$	0.8		$	113.1
(1)     Natural gas derivatives are deferred in accordance with FAS 71 and all increases and decreases in the cost of natural gas supply are passed on to customers with the fuel recovery clause mechanism. As gains and losses are realized in future periods, they will be recorded as fuel costs in the Consolidated Condensed Statements of Income.

Based on the fair value of the instruments at Jun. 30, 2009, net pretax losses of $103.6 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next twelve months.

The following table presents the effect of hedging instruments on OCI and income for the quarter ended Jun. 30, 2009:

(millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income			Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Effective Portion(1)		Effective Portion				Ineffective Portion and Amount Excluded from Effectiveness Testing
Interest rate contracts:	$	—	Interest expense	$	(0.1	)	Interest expense	$	—
Total	$	—		$	(0.1	)		$	—

(1) Changes in OCI are reported in after-tax dollars.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Jun. 30, 2009, all hedges were effective.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2011 for the financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes at Jun. 30, 2009 that are expected to settle each year:

(millions)	(MMBTUs)
Year	Physical	Financial
2009	—	28.1
2010	—	20.5
2011	—	4.5
Total	—	53.1

Tampa Electric Company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company

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could suffer a material financial loss. However, as of Jun. 30, 2009, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies while the remaining are either rated below investment grade or are not rated by rating agencies. Tampa Electric Company assesses credit risk internally for counterparties that are not rated.

Tampa Electric Company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) Edison Electric Institute agreements (EEI) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - standardized physical gas contracts. Tampa Electric Company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

Tampa Electric Company has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. Tampa Electric Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are generally not adjusted as Tampa Electric Company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, Tampa Electric Company considers general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of Jun. 30, 2009, substantially all positions with counterparties are net liabilities.

Certain of Tampa Electric Company’s derivative instruments contain provisions that require Tampa Electric Company’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. Tampa Electric Company has no other contingent risk features associated with any derivative instruments.

The table below presents the fair value of the overall contractual contingent liability positions for Tampa Electric Company’s derivative activity at Jun. 30, 2009:

(millions)
At Jun. 30, 2009
Contingent Feature	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(112.3	)	$	(112.5	)	$	—
Total	$	(112.3	)	$	(112.5	)	$	—

10. Fair Value Measurements

Determination of Fair Value

Tampa Electric 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, Tampa Electric 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.

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, 2009. 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.

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Recurring Derivative Fair Value Measures	At fair value as of Jun. 30, 2009
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	—	$	0.8	$	—	$	0.8
Total	$	—	$	0.8	$	—	$	0.8
Liabilities
Natural gas swaps	$	—	$	113.1	$	—	$	113.1
Total	$	—	$	113.1	$	—	$	113.1

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 fair value of Tampa Electric Company’s long-term debt at Jun. 30, 2009 is $1,934.7 million. The determination of fair value for these instruments includes obtaining prices from third party financial institutions and in some cases utilizing a model to discount the future cash flows produced by the instruments by a rate determined by applying a spread based on Tampa Electric Company’s credit ratings (also provided by third party financial institutions) to U.S. Treasury rates.

Tampa Electric Company considered the impact of nonperformance risk in determining the fair value of derivatives. Tampa Electric Company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Jun. 30, 2009, the fair value of derivatives was not materially affected by nonperformance risk. Tampa Electric Company’s net positions with substantially all counterparties were liability positions.

11. Other Comprehensive Income

Other Comprehensive Income	Three months ended Jun. 30,							Six months ended Jun. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2009
Unrealized gain (loss) on cash flow hedges	$	—	$	—		$	—	$	—		$	—		$	—
Add: Loss reclassified to net income		0.2		(0.1	)		0.1		0.5			(0.2	)		0.3
Gain on cash flow hedges		0.2		(0.1	)		0.1		0.5			(0.2	)		0.3
Total other comprehensive income	$	0.2	$	(0.1	)	$	0.1	$	0.5		$	(0.2	)	$	0.3
2008
Unrealized gain (loss) on cash flow hedges	$	4.5	$	(1.7	)	$	2.8	$	(3.6	)	$	1.4		$	(2.2	)
Add: Loss reclassified to net income		—		—			—		—			—			—
Gain (loss) on cash flow hedges		4.5		(1.7	)		2.8		(3.6	)		1.4			(2.2	)
Total other comprehensive income (loss)	$	4.5	$	(1.7	)	$	2.8	$	(3.6	)	$	1.4		$	(2.2	)
Accumulated Other Comprehensive Loss
(millions)								Jun. 30, 2009						Dec. 31, 2008
Net unrealized losses from cash flow hedges(1)								$	(6.5	)				$	(6.8	)
Total accumulated other comprehensive loss								$	(6.5	)				$	(6.8	)

(1) Net of tax benefit of $4.0 million and $4.3 million as of Jun. 30, 2009 and Dec. 31, 2008, respectively.

12. Subsequent Events

Tampa Electric Company has evaluated all events subsequent to the balance sheet date of Jun. 30, 2009 through the date of issuance, Jul. 31, 2009.

Organizational changes

On Jul. 29, 2009 the Board of Directors of Tampa Electric Company approved a new executive management structure, including the establishment of a single management team over the electric and gas divisions of Tampa Electric Company. The company expects to recognize a restructuring charge in the quarter ending Sep. 30, 2009 as a result of this management change and additional steps that the company expects to undertake to further reduce expenses by integrating operations and support functions.

Issuance of Tampa Electric Company 6.10% Notes due 2018

On Jul. 7, 2009, Tampa Electric Company completed an offering of $100 million aggregate principal amount of 6.10% Notes due 2018 (the “Notes”). The Notes form a single series and are fungible with Tampa Electric Company’s 6.10% notes due 2018 issued on May 16, 2008 in the aggregate principal amount of $150 million. The Notes were sold at 102.988% of par. The offering resulted in net proceeds to Tampa Electric Company (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $102.1 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Tampa Electric Company may redeem all or any part of the 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 Notes to be redeemed or (ii) the present

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value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the Indenture), plus 35 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

Tampa Electric Company’s Motion for Reconsideration

On May 15, 2009, Tampa Electric filed a Motion for Reconsideration regarding the calculation of the annual revenue requirements approved by the FPSC. On Jul. 14, 2009, the FPSC approved Tampa Electric’s Motion (seeNote 3).

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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 Management’s Discussion and Analysis, 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 ability to access capital and credit markets when required; 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; operating conditions, commodity price and operating cost changes affecting the production levels and margins at TECO Coal; fuel cost recoveries and related cash at Tampa Electric and natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; changes in the U.S. federal tax code on earnings from foreign investments that could reduce earnings; the ability to increase the utilization of the coal-fired San José Power Station versus competing oil-fired generators during a period of lower oil prices; and the ultimate outcome of efforts to revise the significantly lower EEGSA VAD tariff rates implemented by regulatory authorities in Guatemala effective Aug. 1, 2008 affecting TECO Guatemala’s results. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Amendment No. 1 to Annual Report on Form 10-K/A for the period ended Dec. 31, 2008.

Earnings Summary - Unaudited

	Three months ended Jun. 30,				Six months ended Jun. 30,
(millions, except per share amounts)	2009		2008		2009		2008
Consolidated revenues	$	825.2	$	887.2	$	1,649.2	$	1,678.9
Net income	$	60.9	$	51.4	$	95.6	$	82.2
Average common shares outstanding
Basic		211.7		210.4		211.6		210.1
Diluted		212.5		212.1		212.3		211.6
Earnings per share - basic
Earnings per share - basic	$	0.29	$	0.24	$	0.45	$	0.39
Earnings per share - diluted
Earnings per share - diluted	$	0.29	$	0.24	$	0.45	$	0.39

Three Months Ended Jun. 30, 2009

TECO Energy recorded second quarter net income of $60.9 million or $0.29 per share, compared to $51.4 million or $0.24 per share in the second quarter of 2008.

Six Months Ended Jun. 30, 2009

Year-to-date net income and earnings per share were $95.6 million or $0.45 per share in 2009, compared to $82.2 million or $0.39 per share in the same period in 2008. Year-to-date net income and earnings per share include an $8.7 million gain on the sale of the telecommunication company, Navega, recorded in the first quarter at TECO Guatemala, and the $3.6 million valuation adjustment recorded in the first quarter on student-loan securities held at TECO Energy parent.

Operating Company Results:

All amounts included in the operating company and Parent / Other results discussions are after tax, unless otherwise noted.

Tampa Electric Company – Electric Division

Tampa Electric reported net income for the second quarter of $48.5 million, compared with $40.2 million for the same period in 2008. Results for the quarter reflected 4.8% higher base revenues due to the increase in base rates effective May 7, 2009, higher earnings on nitrogen oxide (NO_x) control projects, a 0.2% lower average number of customers and slightly higher operations and maintenance expenses. Net income included $2.5 million of AFUDC - equity, which represents allowed equity cost capitalized to construction costs, related to the installation of NO_x control equipment and combustion turbines for peak loads, compared with $1.7 million in the 2008 period.

In the second quarter of 2009, there was no reduction in net income due to the previous waterborne transportation disallowance for the transportation of solid fuel, which reduced net income $2.3 million in the 2008 period. In November 2008,

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the Florida Public Service Commission (FPSC) approved Tampa Electric’s fuel adjustment filing, which included full recovery of waterborne transportation costs under new contracts effective Jan. 1, 2009. This approval eliminated the annual reduction in net income that occurred in 2004 through 2008 during the previous transportation contract.

Total retail energy sales decreased 4.7% in the second quarter of 2009, compared to the same period in 2008. Although total degree days in Tampa Electric’s service area were 5% above normal and 3% above the second quarter of 2008, the 15 consecutive days of rain in May, the third wettest May on record, contributed to the lower energy sales. Sales to the residential, commercial and industrial customer segments decreased 4.5%, 3.6% and 10.1%, respectively, in the second quarter, driven primarily by the weak housing market, economic conditions and the weather. Pretax base revenues increased approximately $15 million in the second quarter due to higher base rates approved by the Florida Public Service Commission for Tampa Electric effective May 7, 2009, which were partially offset by the lower number of customers and the effects of the weather.

Operations and maintenance expense, excluding all FPSC-approved cost recovery clauses, increased $0.6 million. The increase included the write-off of $0.6 million of disallowed rate case expenses, and higher employee-related expenses, including pension, that were offset by lower power generating unit maintenance and lower overhead expenses. Bad-debt expense was $0.1 million higher than in the second quarter of 2008.

Compared to the second quarter of 2008, depreciation expense increased $2.3 million, reflecting additions to facilities to serve customers. Interest expense at Tampa Electric increased slightly due to higher long-term debt balances outstanding, and interest income decreased due to lower interest rates and lower under-recovered fuel balances on which interest is accrued.

Year-to-date net income was $66.8 million, compared with $56.1 million in the 2008 period, driven primarily by the higher base revenues from the new base rates and higher earnings on NO_x control projects, partially offset by 0.2% lower average number of customers, and higher operations and maintenance expenses. Net income included $5.8 million of AFUDC - equity related to the installation of NO_x control equipment and combustion turbines for peak loads, compared with $3.0 million in the 2008 period. Sales to other utilities declined 37% from the 2008 period, reflecting lower demand and lower natural gas prices. In the 2009 year-to-date period, there was no reduction in net income due to the waterborne transportation disallowance for the transportation of solid fuel, compared to a $3.9 million reduction in the 2008 period.

In the 2009 year-to-date period, total retail energy sales decreased 2.4%, compared to the 2008 period, driven primarily by the economy, weather in the second quarter, and the 0.2% decline in the average number of customers. Total degree days in Tampa Electric’s service area were 5% above normal and 6% above the prior year; however, extended periods of rain reduced sales in May. Colder winter weather in the first quarter contributed to a 0.3% increase in sales to the weather-sensitive residential customer class. Sales to commercial and industrial customers declined by 4.1% and 7.9%, respectively, primarily due to economic conditions.

Operations and maintenance expense, excluding all FPSC-approved cost recovery clauses, increased $3.5 million. The increase included the second quarter write-off of disallowed rate case expenses and higher employee related expenses that were partially offset by lower power generating unit maintenance and overhead costs. Bad-debt expense was $0.3 million higher in the 2009 year-to-date period than in 2008.

Compared to the 2008 year-to-date period, depreciation expense increased $4.0 million, reflecting additions to facilities to serve customers. Interest expense at Tampa Electric increased slightly due to higher long-term debt balances outstanding.

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A summary of Tampa Electric’s operating statistics for the three months and six months ended Jun. 30, 2009 and 2008 follows:

	Operating Revenues							Kilowatt-hour sales
(millions, except average customers)	2009			2008		% Change		2009	2008	% Change
Three months ended Jun. 30,
By Customer Type
Residential	$	257.6		$	247.3	4.2		2,057.1	2,153.5	(4.5	)
Commercial		173.3			161.9	7.0		1,563.6	1,621.5	(3.6	)
Industrial – Phosphate		19.9			16.5	20.6		220.3	240.2	(8.3	)
Industrial – Other		29.3			30.3	(3.3	)	287.1	324.2	(11.4	)
Other sales of electricity		50.5			46.8	7.9		450.3	464.0	(3.0	)
Deferred and other revenues(1)		7.4			13.0	(43.1	)	—	—	—
Total		538.0			515.8	4.3		4,578.4	4,803.4	(4.7	)
Sales for resale		13.1			19.2	(31.8	)	121.1	230.6	(47.5	)
Other operating revenue		12.4			10.1	22.8		—	—	—
SO2Allowance sales		0.1			1.0	(90.0	)	—	—	—
Total	$	563.6		$	546.1	3.2		4,699.5	5,034.0	(6.6	)
Average customers (thousands)		666.4			668.0	(0.2	)
Retail output to line (kilowatt hours)								5,100.7	5,278.0	(3.4	)
Six months ended Jun. 30,
By Customer Type
Residential	$	508.7		$	454.3	12.0		3,944.8	3,931.5	0.3
Commercial		339.5			309.3	9.8		2,963.5	3,089.5	(4.1	)
Industrial – Phosphate		40.8			33.1	23.3		467.1	484.8	(3.7	)
Industrial – Other		58.6			57.7	1.6		559.2	630.1	(11.3	)
Other sales of electricity		100.5			89.4	12.4		864.8	882.6	(2.0	)
Deferred and other revenues(1)		(25.1	)		5.8	—		—	—	—
Total		1,023.0			949.6	7.7		8,799.4	9,018.5	(2.4	)
Sales for resale		25.2			35.2	(28.4	)	266.7	419.8	(36.5	)
Other operating revenue		22.9			20.9	9.6		—	—	—
SO2Allowance sales		0.1			1.9	(94.7	)	—	—	—
Total	$	1,071.2		$	1,007.6	6.3		9,066.1	9,438.3	(3.9	)
Average customers (thousands)		666.8			668.3	(0.2	)
Retail output to line (kilowatt hours)								9,463.4	9,635.7	(1.8	)

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

Tampa Electric Company – Natural gas division (PGS)

Peoples Gas reported net income of $4.6 million for the second quarter, compared to $5.3 million in the same period in 2008. Quarterly results reflect a 0.2% lower average number of customers due to the weak Florida housing market, decreased sales to residential customers and increased sales to commercial customers due to several higher volume new customers. Base rates increased due to an interim base rate increase granted in October 2008 and the higher permanent base rates effective Jun. 18, 2009. Gas transported for power generation customers increased in 2009, compared to the second quarter of 2008 when mild weather, generating unit outages, and the use of other fuels for power generation due to high gas prices affected natural gas used for power generation. Lower sales volumes to industrial customers reflected economic conditions and reduced operations by industries sensitive to the housing market, such as cement plants and wallboard producers. Non-fuel operations and maintenance expense increased, primarily due to higher spending on pipeline integrity inspections and the $0.4 million write-off of disallowed rate case expenses partially offset by lower overhead costs. Results also reflect increased depreciation expense due to routine plant additions.

Peoples Gas reported net income of $15.8 million for the year-to-date period, compared to $15.3 million in the same period in 2008. Results reflect a 0.2% lower average number of customers. Residential customer usage increased due to colder winter weather in the first quarter of 2009, compared to the very mild winter weather in 2008. Gas transported for power generation customers increased over the year-to-date period 2008. Non-fuel operations and maintenance expense increased, due

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to the same factors as the second quarter. Revenues associated with off-system sales declined in 2009 due to lower commodity natural gas prices, which are included in off-system sales revenues. Average commodity gas prices in 2008 were almost three times higher than average prices in 2009. In addition, off-system sales volumes were lower in 2009 largely reflecting lower demand for gas used in power generation due to lower power demand. Off-system sales of natural gas are low margin and therefore do not have a material impact on net income.

A summary of PGS’ regulated operating statistics for the three months and six months ended Jun. 30, 2009 and 2008 follows:

Tampa Electric Company – Natural gas division (PGS)

	Operating Revenues						Therms
(millions, except average customers)	2009		2008		% Change		2009	2008	% Change
Three months ended Jun. 30,
By Customer Type
Residential	$	27.1	$	32.2	(15.8	)	13.7	14.8	(7.4	)
Commercial		33.2		38.0	(12.6	)	91.6	90.8	0.9
Industrial		1.8		2.3	(21.7	)	45.4	53.4	(15.0	)
Off system sales		26.3		97.8	(73.1	)	62.2	82.1	(24.2	)
Power generation		2.6		3.8	(31.6	)	144.9	132.9	9.0
Other revenues		10.0		8.6	16.3		—	—	—
Total	$	101.0	$	182.7	(44.7	)	357.8	374.0	(4.3	)
By Sales Type
System supply	$	69.5	$	151.7	(54.2	)	89.0	111.0	(19.8	)
Transportation		21.5		22.4	(4.0	)	268.8	263.0	2.2
Other revenues		10.0		8.6	16.3		—	—	—
Total	$	101.0	$	182.7	(44.7	)	357.8	374.0	(4.3	)
Average customers (thousands)		335.5		336.3	(0.2	)
Six months ended Jun. 30,
By Customer Type
Residential	$	86.5	$	80.9	6.9		46.8	42.6	9.9
Commercial		80.5		82.4	(2.3	)	201.7	197.8	2.0
Industrial		4.0		4.5	(11.1	)	92.3	100.2	(7.9	)
Off system sales		52.7		166.4	(68.3	)	113.2	160.6	(29.5	)
Power generation		5.3		7.2	(26.4	)	253.0	239.6	5.6
Other revenues		23.0		18.4	25.0		—	—	—
Total	$	252.0	$	359.8	(30.0	)	707.0	740.8	(4.6	)
By Sales Type
System supply	$	183.2	$	294.4	(37.8	)	191.2	234.9	(18.6	)
Transportation		45.8		47.0	(2.6	)	515.8	505.9	2.0
Other revenues		23.0		18.4	25.0		—	—	—
Total	$	252.0	$	359.8	(30.0	)	707.0	740.8	(4.6	)
Average customers (thousands)		335.5		336.2	(0.2	)

TECO Coal

In 2009, TECO Coal achieved second quarter net income of $10.1 million on sales of 2.2 million tons, compared to $4.2 million on sales of 2.4 million tons in the same period in 2008. Results reflect an average net per-ton selling price, excluding transportation allowances, of more than $70 per ton, almost 17% higher than 2008, but below prior guidance due to a sales mix that was more heavily weighted to steam coal. Second quarter 2009 metallurgical coal sales were below prior projections due to economic conditions that have reduced demand for steel products worldwide. In the second quarter of 2009, the all-in total per-ton cost of production increased to more than $65 per ton, almost 12% over 2008’s level, and within the cost guidance range previously provided. Net income for the quarter included $2.0 million related to a payment for a contract renegotiation with a steam coal customer, which resulted in higher selling prices in 2009 in exchange for deferred deliveries of contracted tons into 2010 and 2011. Due to tax percentage depletion differences between periods, in the second quarter of 2009 TECO Coal’s effective income tax rate was 14% compared to 6% in the 2008 period.

TECO Coal recorded year-to-date net income of $18.1 million on sales of 4.5 million tons in 2009, compared to $11.7 million on sales of 4.9 million tons in the 2008 period. The year-to-date sales mix was driven by the same factors as the second

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quarter. The 2009 year-to-date average net per-ton selling price and the all-in total per-ton cost of production were similar to those in the second quarter. Results in 2008 reflected a $0.6 million benefit in the first quarter from the true-up of the 2007 synthetic fuel tax credit rate. In the 2009 year-to-date period, TECO Coal’s effective income tax rate was 14% compared to 15% in the 2008 period.

TECO Guatemala

TECO Guatemala reported second quarter net income of $7.9 million in 2009, compared to $14.9 million in the 2008 period. Year-to-date 2009 net income was $21.1 million, compared to $25.4 million in the 2008 period. Year-to-date 2009 net income includes the $8.7 million gain on the sale of the telecommunication company, Navega, recorded in the first quarter. Results in the 2009 second quarter for the distribution utility (EEGSA) and affiliated companies also include a $2.5 million benefit related to an adjustment to previously estimated year-end equity balances, compared to a similar $3.1 million benefit in 2008.

Lower contract and spot energy sales at the San José Power Station reduced net income $3.8 million in the second quarter of 2009 due to the extended unplanned outage as a result of a generator rotor failure. The repairs were completed and the unit returned to service July 2. The 2009 results reflect $2.5 million of lower net income from EEGSA as a result of the reduction in the Value Added Distribution tariff (VAD) in August 2008, partially offset by energy sales growth and lower operating expenses. The earnings from the unregulated EEGSA-affiliated companies (DECA II), which provide, among other things, electricity transmission services, wholesale power sales to unregulated electric customers and engineering services, increased in both periods from fundamental growth in the businesses.

Other and Eliminations

The cost for “Parent/other” in the second quarter of 2009 was $10.2 million, compared to a cost of $13.2 million in the same period in 2008. Results in 2009 included a $2.6 million benefit from a sale of property by TECO Properties. The year-to-date “Parent/other” cost was $26.2 million in 2009, compared to $26.3 million in the 2008 period. The 2009 year-to-date Parent/other included the $3.6 million valuation adjustment recorded in the first quarter on student-loan securities held at TECO Energy parent. In 2008, the year-to-date cost for Parent/other included the $0.6 million after-tax adjustment to previously estimated transaction costs related to the sale of TECO Transport.

Income Taxes

The provisions for income taxes from continuing operations for the six month periods ended Jun. 30, 2009 and Jun. 30, 2008 were $45.1 million and $35.5 million, respectively. The provision for income taxes from continuing operations in the six months ended Jun. 30, 2009 was impacted by $9.7 million related to TECO Guatemala’s sale of its 16.5% interest in Navega.

Liquidity and Capital Resources

The table below sets forth the Jun. 30, 2009 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.

			Balances as of Jun. 30, 2009
(millions)	Consolidated		Tampa Electric Company		Unregulated Companies		Parent
Credit facilities	$	675.0	$	475.0	$	—	$	200.0
Drawn amounts / LCs		201.4		165.3		—		36.1
Available credit facilities		473.6		309.7		—		163.9
Cash and short-term investments		28.0		5.6		17.9		4.5
Total liquidity	$	501.6	$	315.3	$	17.9	$	168.4

Consolidated other cash and short-term investments includes $17.9 million of cash at the unregulated operating companies for normal operations. In addition to consolidated cash, as of Jun. 30, 2009 unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash balances of $18.9 million, which are not included in the table above.

On Jul. 7, 2009, Tampa Electric Company issued $100 million of senior unsecured notes at a premium to yield net proceeds of $102.1 million and an effective interest rate of 5.7%. Proceeds were used to reduce amounts drawn under its credit facilities and for general corporate purposes.

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Capital Expenditures

(millions)	2009 Forecast
Tampa Electric
Transmission	$	40
Distribution		100
Generation		190
Committed generation expansion		85
Other		30
NOx control projects		50
Other environmental		5
Tampa Electric total		500
Peoples Gas		50
Unregulated companies		50
Total	$	600

TECO Energy now estimates capital expenditures for ongoing operations will be $600 million for 2009, which is $140 million lower than previous estimates.

For 2009, Tampa Electric expects to spend $500 million. For the transmission and distribution systems, Tampa Electric expects to spend $140 million in 2009, including $20 million for transmission and distribution system storm hardening, and $40 million for new high-voltage transmission system improvements and to meet reliability requirements. Based on the most recent Florida Reliability Coordinating Council studies, the central Florida transmission system upgrades have been deferred due to lower state-wide transmission system demand. Capital expenditures for the existing generating facilities of $190 million include $60 million for the construction of Big Bend Station rail coal facilities for delivery of solid fuel and $130 million for generating system reliability, including approximately $75 million in major improvements to coal-fired units at Big Bend Station during the extended outages to install NO_x control equipment. In addition, Tampa Electric expects to spend $85 million for the addition of five combustion turbines, $50 million for the additional NO_x control equipment at the Big Bend Power Station and $5 million for other environmental compliance programs in 2009.

Capital expenditures at Peoples Gas are expected to be about $50 million in 2009. Capital expenditures for the unregulated companies are expected to be about $50 million.

In 2010 and beyond, Tampa Electric’s capital spending is expected to be about $300 million annually, absent any spending on generation expansion or for sources of renewable energy. Peoples Gas expects to spend about $50 million annually in 2010 and beyond.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. TECO Energy, TECO Finance, 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, 2009. 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, 2009
Tampa Electric Company
PGS senior notes	EBIT/interest(2)	Minimum of 2.0 times	3.0 times
	Restricted payments	Shareholder equity at least $500	$2,096
	Funded debt/capital	Cannot exceed 65%	49.9%
	Sale of assets	Less than 20% of total assets	0%
Credit facility(3)	Debt/capital	Cannot exceed 65%	49.6%
Accounts receivable credit facility(3)	Debt/capital	Cannot exceed 65%	49.6%
6.25% senior notes	Debt/capital	Cannot exceed 60%	49.6%
	Limit on liens(4)	Cannot exceed $700	$0 liens outstanding
Insurance agreements relating to certain pollution bonds	Limit on liens(4)	Cannot exceed $423 (7.5% of net assets)	$0 liens outstanding
TECO Energy/TECO Finance
Credit facility(3)	EBITDA/interest(2)	Minimum of 2.6 times	3.7 times
TECO Energy floating rate and 6.75% notes and TECO Finance 6.75% notes	Restrictions on secured debt(6)	(5)	(5)
TECO Diversified
Coal supply agreement guarantee	Dividend restriction	Net worth not less than $302 (40% of tangible net assets)	$552

(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 TECO Energy, Inc. Annual Report on Form 10-K/A for the year ended Dec. 31, 2008.

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

(5) 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.

(6) These limitations would not include first mortgage bonds of Tampa Electric Company if any were outstanding.

Credit Ratings of Senior Unsecured Debt at Jun. 30, 2009

	Standard & Poor’s	Moody’s	Fitch
Tampa Electric Company	BBB	Baa1	BBB+
TECO Energy/TECO Finance	BBB-	Baa3	BBB-

On May 6, 2009, Standard & Poor’s Rating Services upgraded the senior unsecured debt ratings on Tampa Electric Company and TECO Energy to ‘BBB’ and ‘BBB-’ respectively, from ‘BBB-’ and ‘BB+’. At the same time, Standard & Poor’s affirmed the outlook on all entities as stable. The higher ratings reflect an improvement in credit metrics by 2010 tied to rate increases at Tampa Electric Company and stability premised on a modest rebound in service territory economy by 2010.

On May 15, 2009, Moody’s Investors Service upgraded the ratings of Tampa Electric Company’s senior unsecured to ‘Baa1’ from ‘Baa2’ with a stable outlook. The higher rating also reflects recently obtained favorable decisions in rate cases.

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 have assigned investment grade ratings to TECO Energy, Inc. and its subsidiaries’ senior unsecured debt.

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.

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Off-Balance Sheet Financing

Unconsolidated affiliates have project debt balances as follows at Jun. 30, 2009. TECO Energy has no debt payment obligations with respect to these financings. Although the company is not directly obligated on the debt, the equity interest in those unconsolidated affiliates is at risk if those projects are not operated successfully.

(millions)	Long-term Debt		Ownership Interest
San José Power Station	$	59.0	100	%
Alborada Power Station	$	2.2	96	%
DECA II	$	184.7	30	%

2009 Earnings Outlook

TECO Energy indicated in May an outlook for 2009 earnings per share to be within a range of $1.00 and $1.15 per share, excluding charges and gains, and continues to expect earnings to be within that range.

The May guidance was provided in the form of a range to allow for varying outcomes with respect to important variables, such as a start to an economic recovery late in 2009, weather and customer usage at the Florida utilities, pricing and demand for production at TECO Coal for uncontracted tons and the potential impact of the world-wide economic slowdown on coal demand. The upper end of the guidance range in May included TECO Coal’s full sales forecast of 9.9 million tons, including the 0.4 million tons that were unsold at that time, at an average selling price of $73 per ton and an average all-in, total cost of production in a range between $63 and $66 per ton. At the same time, Tampa Electric forecasted that an economic recovery would begin later in 2009 and there would be 0.1% customer growth for the year with energy sales growth slightly above that.

Consistent with the guidance provided in May, for the remainder of 2009 Tampa Electric will benefit from the higher base rates that became effective May 7. Additionally, a base rate increase will become effective August 13 as a result of the recent FPSC decision on Tampa Electric’s Motion for Reconsideration. Tampa Electric and Peoples Gas have continued to experience lower numbers of retail customers and continued economic weakness in the areas served, which has reduced sales to commercial and industrial customers. Both utilities are focused on managing costs to offset the lower number of customers and lower energy sales forecasts than were included in their base rate proceedings. Tampa Electric continues to anticipate the start of an economic recovery late in 2009 to produce limited customer and weather-normalized energy sales growth, and also expects higher AFUDC, and ECRC-related earnings on an additional NO_xcontrol project that entered service in May. Peoples Gas will benefit from higher base rates that were effective June 18, but expects resumption of customer growth to lag Tampa Electric. The rate design approved by the FPSC in Peoples Gas’ base rate proceeding makes it less volume and weather sensitive.

At TECO Coal, the world-wide demand for metallurgical coal remains weak, and domestic steam coal usage has been reduced due to declining electricity sales to commercial and industrial customers nationwide. TECO Coal expects total sales volumes below prior guidance due to the 0.4 million tons of metallurgical coal that remains unsold and the possible net deferral of 0.2 to 0.7 million tons of steam and metallurgical coal from 2009 into 2010 and 2011. Due to less metallurgical coal in the product mix, the average per-ton selling price is expected to be slightly below the previously provided guidance. TECO Coal expects the all-in total cost of production to be within the previously provided range but towards the high end reflecting the lower volume. TECO Coal’s effective income tax rate is now expected to be about 18% in 2009.

TECO Guatemala previously indicated earnings for 2009 would be lower than 2008 levels and that outlook remains unchanged. Repairs were completed on the San José Power Station and the unit returned to service July 2. Provided crude oil prices remain in the $60 per barrel or higher range, the station is expected to run at 65% capacity factor or more for the remainder of the year. TECO Guatemala benefited from the second quarter adjustment to previously estimated year-end equity balances, and the DECA II companies continue to seek opportunities to offset the impact of the 2008 VAD decision.

Organizational changes

On Jul. 29, 2009 the Board of Directors approved a new executive management structure, including the establishment of a single management team over the electric and gas divisions of Tampa Electric Company. The company expects that the consolidation of functions will reduce costs through the identification of efficiencies in electric and gas operations and support functions. The company expects to recognize a restructuring charge in the quarter ending Sep. 30, 2009 as a result of this management change and additional steps that the company expects to undertake to reduce costs.

Fair Value Measurements

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

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

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

The valuation methods we used to determine fair value are described inNote 12 to theTECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in

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determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Jun. 30, 2009 the fair value of derivatives was not materially affected by nonperformance risk. Our net positions with substantially all counterparties were liability positions.

Critical Accounting Policies and Estimates

Our critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of our critical accounting policies, see Amendment No. 1 to TECO Energy, Inc.’s Annual Report on Form 10-K/A for the year ended Dec. 31, 2008.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are exposed to changes in interest rates primarily as a result of our borrowing activities. We may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt.

In March 2008, Tampa Electric Company converted $191.8 million aggregate principal amount of tax-exempt bonds originally issued for its benefit in auction rate mode and remarketed them in long-term interest rate modes. In addition, Tampa Electric purchased in lieu of redemption $95.0 million aggregate value of tax-exempt bonds previously in auction rate mode and held such bonds at Jun. 30, 2009, pending a determination of their disposition. The result of these transactions lowered our exposure to variable interest rate risk.

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 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 exposure for the remainder of 2009 is 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 decrease in the price of natural gas of about 36% from Dec. 31, 2008 to Jun. 30, 2009. For natural gas, the company maintains a similar volume hedged as of Jun. 30, 2009 compared to Dec. 31, 2008.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the six months ended Jun. 30, 2009:

Changes in Fair Value of Derivatives(millions)
Net fair value of derivatives as of Dec. 31, 2008	$	(151.4	)
Additions and net changes in unrealized fair value of derivatives		166.8
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		(138.6	)
Net fair value of derivatives as of Jun. 30, 2009	$	(123.2	)
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2008	$	(151.4	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		166.8
Recorded in earnings		—
Realized net settlement of derivatives		(138.6	)
Net option premium payments		—
Net purchase (sale) of existing contracts		—
Net fair value of derivatives as of Jun. 30, 2009	$	(123.2	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Jun. 30, 2009:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Jun. 30, 2009(millions)

Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	—		$	—		$	—
Other external sources(1)		(113.5	)		(9.7	)		(123.2	)
Model prices(2)		—			—			—
Total	$	(113.5	)	$	(9.7	)	$	(123.2	)

(1) Reflects over-the-counter natural gas or heating oil 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.

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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 period covered by this quarterly report (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, 2008 of TECO Energy and Tampa Electric Company. The risk factor described below updates, and should be read in conjunction with, the risk factors identified in the Amendment No. 1 to Annual Report on Form 10-K/A for the period ended Dec. 31, 2008.

Our financial results could be reduced if certain proposed revisions to the U.S. tax code related to foreign earnings are implemented.

The administration has announced initiatives that could substantially reduce our ability to defer U.S. income taxes. These proposals include: repealing the deferral of U.S. taxation of foreign earnings, eliminating utilization of, or substantially reducing our ability to claim foreign tax credits, and eliminating certain tax deductions until foreign earnings are repatriated to the U.S.

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.

Period	(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, 2009 – Apr. 30, 2009	29,339	$	10.51	—	—
May 1, 2009 – May 31, 2009	11,558	$	11.07	—	—
Jun. 1, 2009 – Jun. 30, 2009	1,413	$	11.49	—	—
Total 2nd Quarter 2009	42,310	$	10.70	—	—

(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.

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

At the Annual Meeting of Shareholders held on Apr. 29, 2009, the shareholders of TECO Energy, Inc. elected three directors, ratified the actions taken by the Audit Committee appointing PricewaterhouseCoopers LLP as TECO Energy, Inc.’s independent auditor, re-approved the performance criteria under the Company’s 2004 Equity Incentive Plan and approved a shareholder proposal recommending the declassification of the Board. The following table details the voting results:

	Votes Cast For	Votes Cast Against	Abstentions	Broker Non-Vote
Election of Directors
Sherrill W. Hudson	171,263,651	9,958,752	1,631,809
Joseph P. Lacher	173,803,596	7,257,402	1,793,214
Loretta A. Penn	170,277,353	10,828,334	1,748,524
Ratification of appointment by Audit Committee of PricewaterhouseCoopers LLP as independent auditor	179,007,566	2,908,291	938,354
Re-approval of performance criteria under the TECO Energy, Inc. 2004 Equity Incentive Plan	164,815,260	14,855,461	3,183,489
Shareholder proposal for declassification of the Board	88,412,300	47,486,900	2,384,050	44,570,961

For a complete listing of the Board of Directors, please seeItem 10. Directors, Executive Officers and Corporate Governance of TECO Energy, Inc.’s Amendment No. 1 to Annual Report on Form 10-K/A for the year ended Dec. 31, 2008.

Item 6. EXHIBITS

Exhibits - See index on page 61.

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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, 2009	By:	/s/ S. W. CALLAHAN
			S. W. CALLAHAN
			Vice President-Finance and Accounting and Chief Financial Officer (Treasurer and Chief Accounting Officer) (Principal Financial and Accounting Officer)
		TAMPA ELECTRIC COMPANY
		(Registrant)
Date:	July 31, 2009	By:	/s/ S. W. CALLAHAN
			S. W. CALLAHAN
			Vice President-Finance and Accounting and Chief Financial Officer (Treasurer and Chief Accounting Officer) (Principal Financial and Accounting 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 Apr. 29, 2009 (Exhibit 3.1, Form 8-K dated Feb. 4, 2009 of TECO Energy, Inc.).	*
3.3	Articles of Incorporation of Tampa Electric Company (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.4	Bylaws of Tampa Electric Company, as amended effective Jan. 30, 2008 (Exhibit 3.4, Form 10-K for 2007 of TECO Energy, Inc. and Tampa Electric Company).	*
10.1	Amendment No. 1 to TECO Energy Directors’ Deferred Compensation Plan, effective as of Apr. 29, 2009.
10.2	Form of Restricted Stock Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2004 Equity Incentive Plan.
10.3	Form of Performance Shares Agreement between TECO Energy, Inc. and certain officers 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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