10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

OR

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

For the transition period from                  to                 

Commission File No.	Exact name of each Registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number
1-8180	TECO ENERGY, INC. (a Florida corporation) TECO Plaza 702 N. Franklin Street Tampa, Florida 33602 (813) 228-1111	59-2052286
1-5007	TAMPA ELECTRIC COMPANY (a Florida corporation) TECO Plaza 702 N. Franklin Street Tampa, Florida 33602 (813) 228-1111	59-0475140

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  x    NO   ¨

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

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

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

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

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

YES  ¨    NO  x

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

YES  ¨    NO   x

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Oct. 31, 2011 was 215,766,935. As of Oct. 31, 2011, 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 59.

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of their operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 and to the notes on pages 10 through 28 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2011 and Dec. 31, 2010		3-4
Consolidated Condensed Statements of Income for the three month and nine month periods ended Sep. 30, 2011 and 2010		5-6
Consolidated Condensed Statements of Comprehensive Income for the three month and nine month periods ended Sep. 30, 2011 and 2010		7
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2011 and 2010		8
Notes to Consolidated Condensed Financial Statements		9-27

2

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Sep. 30 2011			Dec. 31, 2010
Current assets
Cash and cash equivalents	$	165.8		$	67.5
Short-term investments		0.0			14.8
Receivables, less allowance for uncollectables of $4.5 and $4.5 at Sep. 30, 2011 and Dec. 31, 2010, respectively		342.8			333.4
Inventories, at average cost
Fuel		124.1			169.5
Materials and supplies		83.8			78.1
Current derivative assets		1.3			2.7
Current regulatory assets		55.8			62.7
Deferred tax asset-current		76.3			0.0
Prepayments and other current assets		33.5			28.5
Income tax receivables		0.2			0.4
Total current assets		883.6			757.6
Property, plant and equipment
Utility plant in service
Electric		6,697.3			6,558.9
Gas		1,145.4			1,115.0
Construction work in progress		191.0			212.4
Other property		428.6			398.5
Property, plant and equipment		8,462.3			8,284.8
Accumulated depreciation		(2,578.3	)		(2,443.8	)
Total property, plant and equipment, net		5,884.0			5,841.0
Other assets
Deferred income taxes, net		0.0			57.3
Long-term regulatory assets		331.2			341.9
Long-term derivative assets		0.2			0.2
Goodwill		55.4			55.4
Deferred charges and other assets		141.5			141.2
Total other assets		528.3			596.0
Total assets	$	7,295.9		$	7,194.6

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

3

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)	Sep. 30, 2011			Dec. 31, 2010
Current liabilities
Long-term debt due within one year
Recourse	$	374.9		$	67.1
Non-recourse		11.2			11.2
Notes payable		0.0			12.0
Accounts payable		252.5			281.5
Customer deposits		158.3			156.5
Current regulatory liabilities		95.5			110.0
Current derivative liabilities		29.5			27.2
Interest accrued		62.1			42.4
Taxes accrued		61.2			26.2
Other current liabilities		19.4			18.2
Total current liabilities		1,064.6			752.3
Other liabilities
Deferred income taxes, net		138.3			0.0
Investment tax credits		10.1			10.4
Long-term regulatory liabilities		637.5			630.8
Long-term derivative liabilities		6.0			2.6
Deferred credits and other liabilities		487.0			479.8
Long-term debt, less amount due within one year
Recourse		2,664.9			3,114.6
Non-recourse		25.1			33.5
Total other liabilities		3,968.9			4,271.7
Commitments and Contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 215.8 million shares and 214.9 million shares outstanding at Sep. 30, 2011 and Dec. 31, 2010, respectively)		215.8			214.9
Additional paid in capital		1,550.4			1,542.0
Retained earnings		512.6			430.0
Accumulated other comprehensive loss		(16.9	)		(17.2	)
Total TECO Energy, Inc. capital		2,261.9			2,169.7
Noncontrolling interest		0.5			0.9
Total capital		2,262.4			2,170.6
Total liabilities and capital	$	7,295.9		$	7,194.6

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

4

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Three months ended Sep. 30,
(millions, except per share amounts)	2011			2010
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $28.8 in 2011 and $31.0 in 2010)	$	685.5		$	707.4
Unregulated		225.9			194.4
Total revenues		911.4			901.8
Expenses
Regulated operations
Fuel		226.3			224.5
Purchased power		32.1			45.2
Cost of natural gas sold		41.5			61.0
Other		82.2			96.1
Operation other expense
Mining related costs		132.3			119.9
Guatemalan power generation		22.1			15.6
Other		2.1			1.9
Maintenance		44.0			44.6
Depreciation and amortization		82.4			78.8
Recoveries from previously impaired assets		0.0			(2.9	)
Taxes, other than income		57.0			57.4
Total expenses		722.0			742.1
Income from operations		189.4			159.7
Other income
Allowance for other funds used during construction		0.2			0.3
Other income		2.6			10.4
Income from equity investments		0.0			3.6
Total other income		2.8			14.3
Interest charges
Interest expense		50.8			57.5
Allowance for borrowed funds used during construction		(0.1	)		(0.1	)
Total interest charges		50.7			57.4
Income before provision for income taxes		141.5			116.6
Provision for income taxes		51.2			65.5
Net income		90.3			51.1
Less: Net income attributable to noncontrolling interest		(0.1	)		(0.1	)
Net income attributable to TECO Energy	$	90.2		$	51.0
Average common shares outstanding — Basic		213.8			212.8
— Diluted		215.3			215.1
Earnings per share attributable to TECO Energy — Basic	$	0.42		$	0.24
— Diluted	$	0.42		$	0.24
Dividends paid per common share outstanding	$	0.215		$	0.205

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

5

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Nine months ended Sep. 30,
(millions, except per share amounts)	2011			2010
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $84.3 in 2011 and $90.0 in 2010)	$	1,929.1		$	2,079.1
Unregulated		664.1			633.8
Total revenues		2,593.2			2,712.9
Expenses
Regulated operations
Fuel		565.4			573.9
Purchased power		103.2			151.5
Cost of natural gas sold		177.6			236.4
Other		242.6			280.5
Operation other expense
Mining related costs		387.0			375.1
Guatemalan power generation		64.9			48.5
Other		5.2			5.0
Maintenance		141.3			137.1
Depreciation and amortization		243.4			233.7
Restructuring charges		0.0			1.5
Recoveries from previously impaired assets		0.0			(2.9	)
Taxes, other than income		171.2			174.1
Total expenses		2,101.8			2,214.4
Income from operations		491.4			498.5
Other income (expense)
Allowance for other funds used during construction		0.8			1.6
Other income		5.6			16.0
(Loss) on debt extinguishment		0.0			(33.0	)
Income from equity investments		0.0			10.5
Total other income (expense)		6.4			(4.9	)
Interest charges
Interest expense		154.9			175.8
Allowance for borrowed funds used during construction		(0.4	)		(0.9	)
Total interest charges		154.5			174.9
Income before provision for income taxes		343.3			318.7
Provision for income taxes		123.7			135.9
Net income		219.6			182.8
Less: Net income attributable to noncontrolling interest		(0.2	)		(0.5	)
Net income attributable to TECO Energy	$	219.4		$	182.3
Average common shares outstanding —Basic		213.5			212.5
— Diluted		215.1			214.6
Earnings per share attributable to TECO Energy — Basic	$	1.02		$	0.85
— Diluted	$	1.02		$	0.85
Dividends paid per common share outstanding	$	0.635		$	0.610

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Sep. 30,						Nine months ended Sep. 30,
(millions)	2011			2010			2011			2010
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Other comprehensive (loss) income, net of tax
Net unrealized (losses) gains on cash flow hedges		(1.8	)		1.4			(0.9	)		1.8
Amortization of unrecognized benefit costs and other		0.4			0.4			1.2			2.6
Recognized benefit costs due to settlement		0.0			0.0			0.0			1.0
Other comprehensive (loss) income, net of tax		(1.4	)		1.8			0.3			5.4
Comprehensive income		88.9			52.9			219.9			188.2
Comprehensive loss attributable to noncontrolling interests		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Comprehensive income attributable to TECO Energy, Inc.	$	88.8		$	52.8		$	219.7		$	187.7

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sep. 30,
(millions)	2011			2010
Cash flows from operating activities
Net income	$	219.6		$	182.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		243.4			233.7
Deferred income taxes		117.5			136.5
Investment tax credits, net		(0.3	)		(0.3	)
Allowance for funds used during construction		(0.8	)		(1.6	)
Non-cash stock compensation		6.6			5.4
Gain on sale of business/assets, pretax		(0.5	)		(0.9	)
Non-cash debt extinguishment, pretax		0.0			0.9
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		0.0			6.8
Deferred recovery clauses		3.6			44.6
Receivables, less allowance for uncollectibles		(9.4	)		(82.0	)
Inventories		39.7			(28.4	)
Prepayments and other current assets		(4.4	)		(4.3	)
Taxes accrued		35.2			38.6
Interest accrued		23.2			23.7
Accounts payable		(26.9	)		36.8
Other		25.1			0.7
Cash flows from operating activities		671.6			593.0
Cash flows from investing activities
Capital expenditures		(298.3	)		(374.9	)
Allowance for funds used during construction		0.8			1.6
Net proceeds from sale of business/assets		3.4			1.4
Net cash increase from consolidation		0.0			24.1
Contributions to unconsolidated affiliates		0.0			(1.7	)
Other investments		14.4			(13.9	)
Cash flows used in investing activities		(279.7	)		(363.4	)
Cash flows from financing activities
Dividends		(136.8	)		(130.7	)
Proceeds from the sale of common stock		6.6			5.6
Proceeds from long-term debt issuance		0.0			543.5
Repayment of long-term debt/Purchase in lieu of redemption		(150.8	)		(513.7	)
Dividend to noncontrolling interest		(0.6	)		(0.7	)
Net decrease in short-term debt		(12.0	)		(28.0	)
Cash flows used in financing activities		(293.6	)		(124.0	)
Net increase in cash and cash equivalents		98.3			105.6
Cash and cash equivalents at beginning of period		67.5			46.0
Cash and cash equivalents at end of period	$	165.8		$	151.6

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

8

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

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

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries, and the accounts of variable interest entities (VIEs) for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Effective Jan. 1, 2010, amended accounting standards on consolidation resulted in the reconsolidation of two projects in Guatemala.

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 its subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011.

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

Revenues

As of Sep. 30, 2011 and Dec. 31, 2010, unbilled revenues of $58.1 million and $65.5 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

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 Florida Public Service Commission (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 $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.0 million and $90.0 million for the three and nine months ended Sep. 30, 2010. 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 amounts totaled $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.1 million and $89.9 million for the three and nine months ended Sep. 30, 2010.

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 $32.1 million and $103.2 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $45.2 million and $151.5 million for the three and nine months ended Sep. 30, 2010. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through FPSC-approved cost recovery clauses.

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 which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas swaps, the cash inflows and outflows are also 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

Intangibles – Goodwill and Other

In September 2011, the Financial Accounting Standards Board (FASB) issued guidance that allows companies to perform a qualitative analysis as the first step in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If it is determined that it is not more likely than not that the fair value of the reporting unit is less than its carrying amount, then a quantitative analysis for impairment is not required. The guidance is effective for interim and annual impairment tests for fiscal periods beginning after Dec. 15, 2011. The company will adopt the guidance as required. It will have no effect on the company’s results of operations, financial position or cash flows.

Presentation of Comprehensive Income

In June 2011, the FASB issued guidance requiring companies to present the total of comprehensive income, the components of net income and the components of other comprehensive income, in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. The company will adopt the guidance as required. It will have no effect on the company’s results of operations, financial position or cash flows.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS)

In May 2011, the FASB issued guidance to more closely align its fair value measurement and disclosure requirements with IFRS. The guidance relates to: measuring the fair value of financial instruments that are managed in a portfolio; the application of premiums and discounts in fair value measurement; and disclosures for items required to be disclosed, but not reported on the statement of financial position, at fair value and Level 3 measures. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. The company will adopt the guidance as required. It will have no effect on the company’s results of operations, financial position or cash flows.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric also 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 the FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to an FPSC-approved self-insured storm damage reserve. Tampa Electric’s storm reserve was $41.5 million and $37.4 million as of Sep. 30, 2011 and Dec. 31, 2010, 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 standards for regulated operations. 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.

10

Details of the regulatory assets and liabilities as of Sep. 30, 2011 and Dec. 31, 2010 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	64.4	$	66.6
Other:
Cost recovery clauses		38.0		41.9
Postretirement benefit asset		228.9		237.5
Deferred bond refinancing costs (2)		12.2		15.4
Environmental remediation		23.2		23.6
Competitive rate adjustment		3.2		3.3
Other		17.1		16.3
Total other regulatory assets		322.6		338.0
Total regulatory assets		387.0		404.6
Less: Current portion		55.8		62.7
Long-term regulatory assets	$	331.2	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	16.7	$	17.7
Other:
Cost recovery clauses		70.7		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.5		37.4
Deferred gain on property sales (3)		5.4		6.3
Provision for stipulation and other (4)		0.8		9.8
Accumulated reserve-cost of removal		576.7		572.2
Total other regulatory liabilities		716.3		723.1
Total regulatory liabilities		733.0		740.8
Less: Current portion		95.5		110.0
Long-term regulatory liabilities	$	637.5	$	630.8

(1) Primarily related to plant life and derivative positions.

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

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

(4) Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS’s 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.

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)	Sep. 30, 2011		Dec 31, 2010
Clause recoverable (1)	$	41.2	$	45.2
Components of rate base (2)		240.9		248.1
Regulatory tax assets (3)		64.4		66.6
Capital structure and other (3)		40.5		44.7
Total	$	387.0	$	404.6

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

(2) Primarily reflects allowed working capital, which is included in rate base and earns 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.

11

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 2009 consolidated federal income tax return during 2010. The U.S. federal statute of limitations remains open for the year 2008 and onward. Years 2010 and 2011 are currently being examined by the IRS under its Compliance Assurance Program. 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 2011. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2007 and forward.

During the second quarter of 2010, the company finalized the settlements of certain state items that were under appeal. As a result, the company recorded a $1.6 million after-tax benefit, excluding interest. During the nine months ended Sep. 30, 2010, the company recorded a total of $4.0 million after-tax benefit, excluding interest, for these state items.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense-Other” on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. For the nine months ended Sep. 30, 2011 and Sep. 30, 2010, the company recorded $0.2 million of interest charges and a net $1.2 million of interest income, respectively. No amounts were recorded for penalties for the nine month periods ended Sep. 30, 2011 or 2010.

The effective tax rate decreased to 36.18% for the three month period ended Sep. 30, 2011 from 56.17% for the same period in 2010. The three month period ended Sep. 30, 2010 included $24.9 million of U.S. deferred taxes recognized on DECA II undistributed earnings which were no longer considered indefinitely reinvested. The effective tax rate decreased to 36.02% for the nine months ended Sep. 30, 2011 from 42.63% for the same period in 2010. The nine month period ended Sep. 30, 2010 also included the $24.9 million mentioned above and a $5.9 million foreign tax credit valuation allowance.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company.

Pension Expense

		$000,000			$000,000			$000,000		$000,000
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sep. 30,	2011			2010			2011		2010
Components of net periodic benefit expense
Service cost	$	4.0		$	4.0		$	0.5	$	0.8
Interest cost on projected benefit obligations		7.7			8.2			2.8		2.8
Expected return on assets		(9.6	)		(9.0	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.5		0.5
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.2
Actuarial loss		2.8			3.2			0.1		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	4.8		$	6.3		$	4.1	$	4.3
Nine months ended Sep. 30,
Components of net periodic benefit expense
Service cost	$	12.0		$	12.1		$	1.6	$	2.4
Interest cost on projected benefit obligations		23.2			24.9			8.3		8.2
Expected return on assets		(28.8	)		(27.2	)		0.0		0.0
Amortization of:
Transition obligation		(0.3	)		0.0			1.7		1.7
Prior service (benefit) cost		8.4			(0.3	)		0.6		0.6
Actuarial loss		0.0			9.4			0.1		0.0
Pension expense		14.5			18.9			12.3		12.9
Settlement cost		0.0			1.6			0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	14.5		$	20.5		$	12.3	$	12.9

12

For the fiscal 2011 plan year, TECO Energy assumed an expected long-term return on plan assets of 7.75% and a discount rate of 5.30% for pension benefits under its qualified pension plan, and a discount rate of 5.25% for its other postretirement benefits as of their Jan. 1, 2011 measurement dates.

Effective Dec. 31, 2006, in accordance with the accounting standard for defined benefit plans and other postretirement benefits, 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 purposes prescribed by accounting standards for regulated operations, were recorded as regulatory assets for Tampa Electric Company. For the three and nine months ended Sep. 30, 2011, TECO Energy and its subsidiaries reclassed $0.6 million and $1.9 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from accumulated other comprehensive income to net income as part of periodic benefit expense. In addition, during the three and nine months ended Sep. 30, 2011, Tampa Electric Company reclassed $2.9 million and $8.6 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

In connection with the restructuring events that occurred in the third quarter of 2009 that changed the senior management structure, TECO Energy recognized settlement charges of $1.6 million, for the nine months ended Sep. 30, 2010 for payouts from its TECO Energy Group Supplemental Executive Retirement Program (SERP).

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, The Health Care and Education Reconciliation Act, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset by $6.4 million and recorded a corresponding charge of $1.1 million and a regulatory tax asset of $5.3 million.

6. Short-Term Debt

At Sep. 30, 2011 and Dec. 31, 2010, the following credit facilities and related borrowings existed:

Credit Facilities

	Sep. 30, 2011						Dec. 31, 2010
	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
(millions)
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	5.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		7.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		6.7
Total	$	675.0	$	0.0	$	0.7	$	675.0	$	12.0	$	7.4

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures May 9, 2012. See Note 16 for information on an amendment to this facility.

(3) 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 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2010 was 0.64%.

Tampa Electric Company Accounts Receivable Facility

On Feb. 18, 2011, Tampa Electric Company and TEC Receivables Corporation (TRC), a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Omnibus Amendment No. 9 to the Loan and Servicing Agreement with certain lenders named therein and Citicorp North America, Inc. as Program Agent. The amendment (i) extends the maturity date to Feb. 17, 2012, (ii) provides that TRC will pay program and liquidity fees, which will total 70 basis points, (iii) provides that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank offered rate (if available) plus a margin and (iv) makes other technical changes.

13

7. Long-Term Debt

Purchase in Lieu of Redemption of Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On Mar. 1, 2011, Tampa Electric Company purchased in lieu of redemption $75.0 million Polk County Industrial Development Authority (PCIDA) Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA had issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously had been in auction rate mode and had been held by Tampa Electric Company since Mar. 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to Mar. 1, 2011.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $20.0 million Hillsborough County Industrial Development Authority (HCIDA) Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the Mar. 1, 2011 purchase of the PCIDA Bonds, $95.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Sep. 30, 2011 (Held Bonds) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

Redemption of TECO Energy, Inc. 7.20% Notes due 2011

On Apr. 22, 2010, TECO Energy redeemed $100 million aggregate principal amount of its 7.2% Notes due 2011. The redemption price was equal to $1,066.38 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $6.6 million of premiums and fees were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Condensed Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sep. 30, 2010.

Redemption of TECO Energy, Inc. Floating Rate Notes due 2010

On Apr. 14, 2010, TECO Energy redeemed all of the outstanding $100 million aggregate principal amount of its Floating Rate Notes due 2010. The redemption price was equal to 100% of the principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date.

TECO Energy, Inc. and TECO Finance, Inc. Tender Offers

On Mar. 22, 2010, TECO Energy and TECO Finance completed debt tender offers which resulted in the purchase of approximately $70.0 million principal amount of TECO Energy notes for cash and approximately $230.0 million principal amount of TECO Finance notes for cash.

The tender offers resulted in the purchase and retirement of approximately:

• $43.0 million principal amount of TECO Energy 7.2% Notes due 2011

• $27.0 million principal amount of TECO Energy 7.0% Notes due 2012

• $156.9 million principal amount of TECO Finance 7.2% Notes due 2011

• $73.1 million principal amount of TECO Finance 7.0% Notes due 2012

In connection with these debt tender transactions, $25.5 million of premiums and fees were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Condensed Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sep. 30, 2010. “Loss on debt extinguishment” also includes remaining unamortized debt issue costs of $0.9 million.

Issuance of TECO Finance, Inc. 4.00% Notes due 2016 and 5.15% Notes due 2020

On Mar. 15, 2010, TECO Finance, Inc. (TECO Finance) issued $250.0 million aggregate principal amount of 4.00% Notes due Mar. 15, 2016 and $300.0 million aggregate principal amount of 5.15% Notes due Mar. 15, 2020. The 2016 Notes were priced at 99.594% of the principal amount to yield 4.077% to maturity, and the 2020 Notes were priced at 99.552% of the principal amount to yield 5.208% to maturity. TECO Finance is a wholly-owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy for its diversified activities. The TECO Finance notes are fully and unconditionally guaranteed by TECO Energy.

14

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $543.5 million. TECO Finance used these net proceeds to fund the cash purchase of the TECO Energy and TECO Finance notes tendered in March 2010 (see TECO Energy, Inc. and TECO Finance, Inc. Tender Offers below) and to fund the redemptions of the TECO Energy Floating Rate Notes due 2010 and 7.20% Notes due 2011 in April 2010. TECO Finance may redeem some or all 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 sum of 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 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

Reconsolidation of TCAE and CGESJ

Effective Jan. 1, 2010, new accounting standards for consolidations amended the determination of the primary beneficiaries for variable interest entities. As a result of adopting these standards, TECO Guatemala, Inc., a wholly-owned subsidiary of TECO Energy, was determined to be the primary beneficiary of, and therefore required to consolidate, both the Tampa Centro Americana de Electricidad (TCAE) and Central Generadora Eléctrica San José (CGESJ) projects in Guatemala. The consolidation resulted in a net $44.4 million increase of non-recourse debt.

8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (OCI) for the three and nine months ended Sep. 30, 2011 and 2010, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

Other Comprehensive Income

	Three months ended Sep. 30,									Nine months ended Sep. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2011
Unrealized (loss) gain on cash flow hedges	$	(2.1	)	$	0.8		$	(1.3	)	$	0.8		$	(0.3	)	$	0.5
Less: Gain reclassified to net income		(0.8	)		0.3			(0.5	)		(2.3	)		0.9			(1.4	)
Loss on cash flow hedges		(2.9	)		1.1			(1.8	)		(1.5	)		0.6			(0.9	)
Amortization of unrecognized benefit costs and other		0.7			(0.3	)		0.4			1.9			(0.7	)		1.2
Total other comprehensive (loss) income	$	(2.2	)	$	0.8		$	(1.4	)	$	0.4		$	(0.1	)	$	0.3
2010
Unrealized gain (loss) on cash flow hedges	$	0.9		$	(0.2	)	$	0.7		$	(0.5	)	$	0.2		$	(0.3	)
Plus: Loss reclassified to net income		1.2			(0.5	)		0.7			3.4			(1.3	)		2.1
Gain on cash flow hedges		2.1			(0.7	)		1.4			2.9			(1.1	)		1.8
Amortization of unrecognized benefit costs and other		0.6			(0.2	)		0.4			1.8			0.8			2.6
Recognized benefit costs due to settlement		0.0			0.0			0.0			1.6			(0.6	)		1.0
Total other comprehensive income	$	2.7		$	(0.9	)	$	1.8		$	6.3		$	(0.9	)	$	5.4

Accumulated Other Comprehensive Loss

(millions)	Sep. 30, 2011			Dec. 31, 2010
Unrecognized pension losses and prior service costs(1)	$	(25.5	)	$	(26.6	)
Unrecognized other benefit gains, prior service costs and transition obligations(2)		13.7			13.6
Net unrealized losses from cash flow hedges(3)		(5.1	)		(4.2	)
Total accumulated other comprehensive loss	$	(16.9	)	$	(17.2	)

(1) Net of tax benefit of $15.7 million and $16.2 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

(2) Net of tax expense of $5.9 million and $5.8 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

(3) Net of tax benefit of $3.3 million and $2.7 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

15

9. Earnings Per Share

Earnings Per Share

	Three months ended Sep. 30,						Nine months ended Sep. 30,
(millions, except per share amounts)	2011			2010			2011			2010
Basic earnings per share
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Less: Income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Less: Amount allocated to nonvested participating shareholders		(0.5	)		(0.4	)		(1.2	)		(1.3	)
Net income attributable to TECO Energy available to common shareholders—basic	$	89.7		$	50.6		$	218.2		$	181.0
Average shares outstanding-common		213.8			212.8			213.5			212.5
Basic earnings per share attributable to TECO Energy available to common shareholders	$	0.42		$	0.24		$	1.02		$	0.85
Diluted earnings per share
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Less: Income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Less: Amount allocated to nonvested participating shareholders		(0.5	)		(0.4	)		(1.2	)		(1.3	)
Net income attributable to TECO Energy available to common shareholders—diluted	$	89.7		$	50.6		$	218.2		$	181.0
Average shares outstanding-common		213.8			212.8			213.5			212.5
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		1.5			2.3			1.6			2.1
Adjusted average shares outstanding common—diluted		215.3			215.1			215.1			214.6
Diluted earnings per share attributable to TECO Energy available to common shareholders	$	0.42		$	0.24		$	1.02		$	0.85
Anti-dilutive shares		1.4			2.5			1.8			4.3

16

10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable 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, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

The second portion of a non-jury trial in this case was held in October 2011 in the Dade County, Florida Circuit Court. The first portion was held in June 2011. The trial is expected to resume and conclude in the first half of 2012. Merco Group at Aventura Landings I, II and III (Merco) alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, the court will consider PGS’s counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2011, Tampa Electric Company has estimated its ultimate financial liability to be $21.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in “Long-term regulatory liabilities” on the company’s Consolidated Condensed Balance Sheet. 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 clean-up costs attributable to Tampa Electric Company. The estimates to perform the work are based on 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.

In instances where other PRPs are involved, many of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, Tampa Electric Company could be liable for more than Tampa Electric Company’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Potentially Responsible Party Notification

In October 2010, the U.S. Environmental Protection Agency (EPA) notified Tampa Electric Company that it is a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, commonly known as Superfund, for the proposed conduct of a contaminated soil removal action and further clean up, if necessary, at a property owned by Tampa Electric Company in Tampa, Florida. The property owned by Tampa Electric Company is undeveloped except for location of transmission lines and poles, and is adjacent to an industrial site, not owned by Tampa Electric Company, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to Tampa Electric Company’s ownership of the property described above but, to the knowledge of Tampa Electric Company, this assertion is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company has responded to the EPA regarding such matter. The scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

Environmental Protection Agency Administrative Order

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal Corporation (TECO Coal), received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. TECO Coal responded to the EPA on Feb. 14, 2011. The scope and extent of TECO Coal’s potential liability, if any, and the costs of any required investigation and remediation related to these inactive mining operations in the area have not been determined.

17

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and Tampa Electric Company’s letters of credit and guarantees as of Sep. 30, 2011 is as follows:

Guarantees-TECO Energy

(millions)					After(1)				Liabilities Recognized
Guarantees for the Benefit of:	2011		2012-2015		2015		Total		at Sep. 30, 2011
TECO Coal
Guarantees: Fuel purchase related (2)		0.0		0.0		5.4		5.4		1.1
		0.0		0.0		5.4		5.4		1.1
Other subsidiaries
Guarantees:
Fuel purchase/energy management (2)		0.0		0.0		109.7		109.7		1.1
Total	$	0.0	$	0.0	$	115.1	$	115.1	$	2.2

Letters of Credit-Tampa Electric Company

(millions)					After(1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2011		2012-2015		2015		Total		at Sep. 30, 2011
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2015.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sep. 30, 2011. 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 facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2011, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets, as required by the accounting guidance for 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.

18

Segment Information ⁽¹⁾

		$1,570.6		$1,570.6		$1,570.6		$1,570.6			$1,570.6			$1,570.6
(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala			Other & Eliminations			TECO Energy, Inc.
2011
Revenues—external	$	591.6	$	93.9	$	190.5	$	33.6		$	1.8		$	911.4
Sales to affiliates		0.3		0.3		0.0		0.0			(0.6	)		0.0
Total revenues		591.9		94.2		190.5		33.6			1.2			911.4
Depreciation		56.2		12.2		11.8		1.8			0.4			82.4
Total interest charges(1)		30.3		4.4		1.7		1.9			12.4			50.7
Internally allocated interest (1)		0.0		0.0		1.7		1.5			(3.2	)		0.0
Provision (benefit) for taxes		47.4		3.0		4.1		2.4			(5.7	)		51.2
Net income (loss) attributable to TECO Energy	$	75.0	$	4.8	$	14.1	$	4.5		$	(8.2	)	$	90.2
2010
Revenues—external	$	593.3	$	114.1	$	165.3	$	29.0		$	0.1		$	901.8
Sales to affiliates		0.3		2.5		0.0		0.0			(2.8	)		0.0
Total revenues		593.6		116.6		165.3		29.0			(2.7	)		901.8
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		4.1			(0.5	)		3.6
Depreciation		54.4		11.5		11.0		1.8			0.1			78.8
Total interest charges(1)		30.7		4.6		1.6		4.0			16.5			57.4
Internally allocated interest (1)		0.0		0.0		1.5		3.0			(4.5	)		0.0
Provision (benefit) for taxes		36.8		2.4		2.2		29.1			(5.0	)		65.5
Net income (loss) attributable to TECO Energy	$	61.9	$	3.7	$	8.3	$	(12.6	)	$	(10.3	)	$	51.0

		$1,570.6		$1,570.6		$1,570.6		$1,570.6		$1,570.6			$1,570.6
(millions) Nine months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy, Inc.
2011
Revenues—external	$	1,570.6	$	358.5	$	555.5	$	103.3	$	5.3		$	2,593.2
Sales to affiliates		1.0		3.0		0.0		0.0		(4.0	)		0.0
Total revenues		1,571.6		361.5		555.5		103.3		1.3			2,593.2
Depreciation		166.4		36.0		34.4		5.5		1.1			243.4
Total interest charges(1)		91.6		13.3		5.1		5.7		38.8			154.5
Internally allocated interest (1)		0.0		0.0		5.0		4.6		(9.6	)		0.0
Provision (benefit) for taxes		104.3		16.0		10.7		8.5		(15.8	)		123.7
Net income (loss) attributable to TECO Energy	$	165.0	$	25.4	$	38.1	$	16.4	$	(25.5	)	$	219.4
2010
Revenues—external	$	1,670.9	$	408.2	$	537.9	$	95.7	$	0.2		$	2,712.9
Sales to affiliates		1.0		17.4		0.0		0.0		(18.4	)		0.0
Total revenues		1,671.9		425.6		537.9		95.7		(18.2	)		2,712.9
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		12.1		(1.6	)		10.5
Depreciation		161.0		34.3		32.8		5.4		0.2			233.7
Restructuring charges		0.0		0.0		0.0		0.0		1.5			1.5
Total interest charges(1)		91.8		13.8		5.2		13.0		51.1			174.9
Internally allocated interest (1)		0.0		0.0		5.0		9.5		(14.5	)		0.0
Provision (benefit) for taxes		98.4		16.9		9.1		35.9		(24.4	)		135.9
Net income (loss) attributable to TECO Energy	$	166.8	$	26.7	$	45.8	$	8.4	$	(65.4	)	$	182.3

19

(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy, Inc.
At Sep. 30, 2011
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,924.3	$	879.2	$	352.5	$	266.4	$	(126.5	)	$	7,295.9
At Dec. 31, 2010
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,833.3	$	918.4	$	332.2	$	292.7	$	(182.0	)	$	7,194.6

(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 January 2011 through September 2011 were at a pretax rate of 6.25%, for July 2010 through December 2010 were at a pretax rate of 6.50%, and for January 2010 through June 2010 were at a pretax rate of 7.15% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

20

12. 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 diesel fuel 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 accounting standards for derivative instruments and hedging activities. 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.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

The 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 Sep. 30, 2011, 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 Sep. 30, 2011 and Dec. 31, 2010:

Total Derivatives⁽¹⁾

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	1.3	$	2.7
Long-term assets		0.2		0.2
Total assets	$	1.5	$	2.9
Current liabilities	$	29.5	$	27.2
Long-term liabilities		6.0		2.6
Total liabilities	$	35.5	$	29.8

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

21

The following table presents the derivative hedges of diesel fuel swaps and option contracts at Sep. 30, 2011 and Dec. 31, 2010 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	1.3	$	1.6
Long-term assets		0.2		0.2
Total assets	$	1.5	$	1.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		1.5		0.0
Total liabilities	$	1.5	$	0.0

The following table presents the derivative hedges of natural gas contracts at Sep. 30, 2011 and Dec. 31, 2010 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	0.0	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.0	$	1.1
Current liabilities	$	29.5	$	27.2
Long-term liabilities		4.5		2.6
Total liabilities	$	34.0	$	29.8

The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Sep. 30, 2011 is a net loss of $5.1 million after tax and accumulated amortization. This compares to a net loss of $4.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2010.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at Sep. 30, 2011:

Derivatives Designated As Hedging Instruments

	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2011	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	1.3	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.2	Derivative liabilities		1.5
Natural gas derivatives:
Current	Derivative assets		0.0	Derivative liabilities		29.5
Long-term	Derivative assets		0.0	Derivative liabilities		4.5
Total derivatives designated as hedging instruments		$	1.5		$	35.5

22

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sep. 30, 2011:

Energy Related Derivatives

	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2011	Balance  Sheet Location(1)	Fair Value		Balance  Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.0	Regulatory assets	$	29.5
Long-term	Regulatory liabilities		0.0	Regulatory assets		4.5
Total		$	0.0		$	34.0

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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 Sep. 30, 2011, net pretax losses of $29.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The following tables present the effect of hedging instruments on OCI and income for the three months and nine months ended Sep. 30:

For the three months ended Sep. 30:

(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 Cash Flow Hedging Relationships	Effective Portion(1)				Effective Portion(1)
2011
Interest rate contracts:	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(1.3	)	Mining related costs		0.7
Total	$	(1.3	)		$	0.5
2010
Interest rate contracts:	$	0.0		Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		0.7		Mining related costs		(0.3	)
Total	$	0.7			$	(0.7	)

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

23

For the nine months ended Sep. 30:

(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 Cash Flow Hedging Relationships	Effective Portion(1)				Effective Portion(1)
2011
Interest rate contracts:	$	0.0		Interest expense	$	(0.5	)
Commodity contracts:
Diesel fuel derivatives		0.6		Mining related costs		2.0
Total	$	0.6			$	1.5
2010
Interest rate contracts:	$	(0.1	)	Interest expense	$	(1.2	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)	Mining related costs		(0.9	)
Total	$	(0.3	)		$	(2.1	)

(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 and nine months ended Sep. 30, 2011 and 2010, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sep. 30:

For the nine months ended Sep. 30:

(millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI(1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income(1)
2011
Interest rate swaps	$	0.0		$	0.0		$	(0.5	)
Diesel fuel derivatives		0.0			0.6			2.0
Total	$	0.0		$	0.6		$	1.5
2010
Interest rate swaps	$	(0.3	)	$	(0.1	)	$	(1.2	)
Diesel fuel derivatives		0.3			(0.2	)		(0.9	)
Total	$	0.0		$	(0.3	)	$	(2.1	)

(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, 2014 for both financial natural gas and financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of Sep. 30, 2011, are expected to settle during the 2011, 2012, 2013 and 2014 fiscal years:

24

(millions) Year	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
	Physical		Financial		Physical		Financial
2011		0.0		2.4		0.0		11.6
2012		0.0		2.6		0.0		35.0
2013		0.0		1.8		0.0		5.0
2014		0.0		1.0		0.0		0.0
Total		0.0		7.8		0.0		51.6

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 Sep. 30, 2011, all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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 its 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.

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 Sep. 30, 2011:

Contingent Features

(millions) At Sep. 30, 2011	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(35.1	)	$	(35.1	)	$	0.0

25

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2011 and Dec. 31, 2010. As required by accounting standards for fair value measurements, 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 diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures

	At fair value as of Sep. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Diesel fuel swaps		0.0		1.5		0.0		1.5
Total	$	0.0	$	1.5	$	0.0	$	1.5
Liabilities
Natural gas swaps	$	0.0	$	34.0	$	0.0	$	34.0
Diesel fuel swaps		0.0		1.5		0.0		1.5
Total	$	0.0	$	35.5	$	0.0	$	35.5

	At fair value as of Dec. 31, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.1	$	0.0	$	1.1
Diesel fuel swaps		0.0		1.8		0.0		1.8
Total	$	0.0	$	2.9	$	0.0	$	2.9
Liabilities
Natural gas swaps	$	0.0	$	29.8	$	0.0	$	29.8
Total	$	0.0	$	29.8	$	0.0	$	29.8

Natural gas and diesel fuel 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 company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2011, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were liability positions.

Fair Value of Debt

At Sep. 30, 2011, total long-term debt had a carrying amount of $3,076.1 million and an estimated fair market value of $3,450.7 million. At Dec. 31, 2010, total long-term debt had a carrying amount of $3,226.4 million and an estimated fair market value of $3,449.3 million.

14. Restructuring Charges

On Jul. 30, 2009, TECO Energy, Inc. announced organizational changes that resulted in severance and other benefits costs that were mostly expensed during the fourth quarter of 2009. For the nine months ended Sep. 30, 2010, the remaining $1.5 million was recognized on the Consolidated Condensed Statements of Income under “Restructuring charges”.

26

15. Variable Interest Entities

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE’s primary beneficiary. Under the amended standard, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric Company has entered into multiple power purchase agreements (PPAs) with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 mega-watts (MW) to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance; regulatory; credit; commodity/fuel; and energy market risk. Tampa Electric Company has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric Company is not required to consolidate any of these entities. Tampa Electric Company purchased $22.9 million and $64.9 million pursuant to PPAs for the three and nine months ended Sep. 30, 2011, respectively, and $29.7 million and $90.6 million for the three and nine months ended Sep. 30, 2010, respectively.

In one instance, Tampa Electric Company’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, the company is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, the company is unable to determine if this entity is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. The company has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for the company is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. Under this PPA, Tampa Electric Company purchased $12.0 million and $24.9 million for the three and nine months ended Sep. 30, 2011, respectively, and $14.7 million and $45.0 million for the three and nine months ended Sep. 30, 2010, respectively.

Tampa Electric Company does not provide any material financial or other support to any of the VIEs it is involved with, nor is it under any obligation to absorb losses associated with these VIEs. In the normal course of business, Tampa Electric Company’s involvement with the remaining VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

16. Subsequent Events

TECO Energy, Inc. $200 million bank credit facility amendment

On Oct. 25, 2011, TECO Energy, Inc. (TECO Energy) and its wholly-owned subsidiary, TECO Finance, Inc. (TECO Finance), amended their $200 million bank credit facility, entering into a Third Amended and Restated Credit Agreement with ten lenders. Under the amendment, TECO Finance continues to be the Borrower and TECO Energy continues to be the Guarantor. The amendment (i) extends the maturity date of the credit facility from May 9, 2012 to Oct. 25, 2016 (subject to further extension with the consent of each lender); (ii) continues to allow TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TECO Finance to borrow funds on a same-day basis under a new Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate (compared to $50 million in the aggregate under the previous agreement); (vi) continues to include a $200 million letter of credit facility and (vii) makes other technical changes.

Tampa Electric Company $325 million bank credit facility amendment

On Oct. 25, 2011, Tampa Electric Company (Tampa Electric) amended its $325 million bank credit facility, entering into a Third Amended and Restated Credit Agreement with ten lenders. The amendment (i) extends the maturity date of the credit facility from May 9, 2012 to Oct. 25, 2016 (subject to further extension with the consent of each lender); (ii) continues to allow Tampa Electric to borrow funds at a rate equal to the London interbank deposit rate plus a margin (iii) as an alternative to the above interest rate, allows Tampa Electric to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows Tampa Electric to borrow funds on a same-day basis under a new Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) continues to allow Tampa Electric to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility (compared to $50 million under the previous agreement); and (vii) makes other technical changes.

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 Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three months and nine months ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011. References should be made to the explanatory notes affecting the consolidated financial statements contained in Tampa Electric Company’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 and to the notes on pages 36 through 47 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2011 and Dec. 31, 2010		29-30
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and nine month periods ended Sep. 30, 2011 and 2010		31-32
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2011 and 2010		33
Notes to Consolidated Condensed Financial Statements		34-46

28

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Sep. 30, 2011			Dec. 31, 2010
Property, plant and equipment
Utility plant in service
Electric	$	6,481.6		$	6,343.4
Gas		1,089.9			1,060.6
Construction work in progress		185.6			206.8
Property, plant and equipment, at original costs		7,757.1			7,610.8
Accumulated depreciation		(2,202.7	)		(2,093.9	)
		5,554.4			5,516.9
Other property		5.7			4.7
Total property, plant and equipment, net		5,560.1			5,521.6
Current assets
Cash and cash equivalents		111.1			3.7
Receivables, less allowance for uncollectibles of $3.2 and $3.2 at Sep. 30, 2011 and Dec. 31, 2010, respectively		253.7			264.6
Inventories, at average cost
Fuel		84.2			119.0
Materials and supplies		63.8			59.1
Current regulatory assets		55.8			62.7
Current derivative assets		0.0			1.1
Taxes receivable		0.0			24.6
Deferred tax asset		28.7			1.5
Prepayments and other current assets		12.7			10.0
Total current assets		610.0			546.3
Deferred debits
Unamortized debt expense		15.0			17.8
Long-term regulatory assets		331.2			341.9
Other		9.9			10.9
Total deferred debits		356.1			370.6
Total assets	$	6,526.2		$	6,438.5

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)	Sep. 30, 2011			Dec. 31, 2010
Capital
Common stock	$	1,852.4		$	1,852.4
Accumulated other comprehensive loss		(4.8	)		(5.3	)
Retained earnings		342.1			311.1
Total capital		2,189.7			2,158.2
Long-term debt, less amount due within one year		1,616.3			2,066.1
Total capitalization		3,806.0			4,224.3
Current liabilities
Long-term debt due within one year		374.9			3.4
Notes payable		0.0			12.0
Accounts payable		184.2			219.0
Customer deposits		158.3			156.5
Current regulatory liabilities		95.5			110.0
Current derivative liabilities		29.5			27.2
Interest accrued		46.5			24.6
Taxes accrued		70.8			14.0
Other		12.2			12.2
Total current liabilities		971.9			578.9
Deferred credits
Non-current deferred income taxes, net		737.0			631.5
Investment tax credits		10.1			10.4
Long-term derivative liabilities		4.5			2.6
Long-term regulatory liabilities		637.5			630.8
Other		359.2			360.0
Total deferred credits		1,748.3			1,635.3
Commitments and Contingencies (see Note 8)
Total liabilities and capital	$	6,526.2		$	6,438.5

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

30

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Sep. 30,
(millions)	2011			2010
Revenues
Electric (includes franchise fees and gross receipts taxes of $24.7 in 2011 and $26.4 in 2010)	$	591.8		$	593.5
Gas (includes franchise fees and gross receipts taxes of $4.1 in 2011 and $4.6 in 2010)		93.8			114.1
Total revenues		685.6			707.6
Expenses
Operations
Fuel		226.3			224.5
Purchased power		32.1			45.2
Cost of natural gas sold		41.4			61.0
Other		82.0			96.0
Maintenance		25.6			28.7
Depreciation		68.4			65.9
Taxes, federal and state		50.1			38.9
Taxes, other than income		45.9			47.4
Total expenses		571.8			607.6
Income from operations		113.8			100.0
Other income (expense)
Allowance for other funds used during construction		0.2			0.3
Taxes, non-utility federal and state		(0.3	)		(0.3	)
Other income, net		0.8			0.9
Total other income		0.7			0.9
Interest charges
Interest on long-term debt		31.9			32.6
Other interest		2.9			2.8
Allowance for borrowed funds used during construction		(0.1	)		(0.1	)
Total interest charges		34.7			35.3
Net income		79.8			65.6
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges		0.2			0.2
Total other comprehensive income, net of tax		0.2			0.2
Comprehensive income	$	80.0		$	65.8

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

(millions)	Nine months ended Sep. 30,
	2011			2010
Revenues
Electric (includes franchise fees and gross receipts taxes of $65.3 in 2011 and $69.6 in 2010)	$	1,571.2		$	1,671.6
Gas (includes franchise fees and gross receipts taxes of $19.0 in 2011 and $20.4 in 2010)		358.5			408.2
Total revenues		1,929.7			2,079.8
Expenses
Operations
Fuel		565.4			573.9
Purchased power		103.2			151.5
Cost of natural gas sold		177.6			236.4
Other		242.2			280.2
Maintenance		88.7			90.3
Depreciation		202.4			195.3
Taxes, federal and state		119.6			114.7
Taxes, other than income		137.4			141.9
Total expenses		1,636.5			1,784.2
Income from operations		293.2			295.6
Other income (expense)
Allowance for other funds used during construction		0.8			1.6
Taxes, non-utility federal and state		(0.7	)		(0.6	)
Other income, net		2.0			2.5
Total other income		2.1			3.5
Interest charges
Interest on long-term debt		96.7			98.1
Other interest		8.6			8.4
Allowance for borrowed funds used during construction		(0.4	)		(0.9	)
Total interest charges		104.9			105.6
Net income		190.4			193.5
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges		0.5			0.6
Total other comprehensive income, net of tax		0.5			0.6
Comprehensive income	$	190.9		$	194.1

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

32

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sep. 30,
(millions)	2011			2010
Cash flows from operating activities
Net income	$	190.4		$	193.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		202.4			195.3
Deferred income taxes		79.0			27.7
Investment tax credits, net		(0.3	)		(0.3	)
Allowance for funds used during construction		(0.8	)		(1.6	)
Deferred recovery clause		3.6			44.6
Receivables, less allowance for uncollectibles		10.9			(69.9	)
Inventories		30.1			(31.8	)
Prepayments		(2.7	)		(1.8	)
Taxes accrued		81.4			65.9
Interest accrued		21.9			16.8
Accounts payable		(33.6	)		17.7
Gain on sale of assets, pretax		(0.2	)		(0.2	)
Other		20.1			5.0
Cash flows from operating activities		602.2			460.9
Cash flows from investing activities
Capital expenditures		(248.3	)		(295.2	)
Allowance for funds used during construction		0.8			1.6
Net proceeds from sale of assets		2.8			0.0
Cash flows used in investing activities		(244.7	)		(293.6	)
Cash flows from financing activities
Common stock		0.0			50.0
Repayment of long-term debt/Purchase in lieu of redemption		(78.8	)		(3.7	)
Net decrease in short-term debt		(12.0	)		(28.0	)
Dividends		(159.3	)		(174.9	)
Cash flows used in financing activities		(250.1	)		(156.6	)
Net increase in cash and cash equivalents		107.4			10.7
Cash and cash equivalents at beginning of period		3.7			5.5
Cash and cash equivalents at end of period	$	111.1		$	16.2

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

33

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies for Tampa Electric Company include:

Principles of Consolidation and Basis of Presentation

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, Tampa Electric Company is comprised of the Electric division, generally referred to as Tampa Electric, the Natural Gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. Tampa Electric Company is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. For the periods presented, no VIEs have been consolidated (see Note 13).

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 its subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011.

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

Revenues

As of Sep. 30, 2011 and Dec. 31, 2010, unbilled revenues of $58.1 million and $65.5 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

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 $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.0 million and $90.0 million for the three and nine months ended Sep. 30, 2010. 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 amounts totaled $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.1 million and $89.9 million for the three and nine months ended Sep. 30, 2010.

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 $32.1 million and $103.2 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $45.2 million and $151.5 million for the three and nine months ended Sep. 30, 2010. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through FPSC-approved cost recovery clauses.

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.

34

2. New Accounting Pronouncements

Presentation of Comprehensive Income

In June 2011, the FASB issued guidance requiring companies to present the total of comprehensive income, the components of net income and the components of other comprehensive income, in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. Tampa Electric Company will adopt the guidance as required. It will have no effect on Tampa Electric Company’s results of operations, financial position or cash flows.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS

In May 2011, the FASB issued guidance to more closely align its fair value measurement and disclosure requirements with IFRS. The guidance relates to: measuring the fair value of financial instruments that are managed in a portfolio; the application of premiums and discounts in fair value measurement; and disclosures for items required to be disclosed, but not reported on the statement of financial position, at fair value and Level 3 measures. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. Tampa Electric Company will adopt the guidance as required. It will have no effect on Tampa Electric Company’s results of operations, financial position or cash flows.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric also is subject to regulation by the FERC under PUHCA 2005. However, pursuant to a waiver granted in accordance with the FERC’s regulations, Tampa Electric is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to an FPSC-approved self-insured storm damage reserve. Tampa Electric’s storm reserve was $41.5 million and $37.4 million as of Sep. 30, 2011 and Dec. 31, 2010, 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 standards for regulated operations. 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.

35

Details of the regulatory assets and liabilities as of Sep. 30, 2011 and Dec. 31, 2010 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	64.4	$	66.6
Other:
Cost recovery clauses		38.0		41.9
Postretirement benefit asset		228.9		237.5
Deferred bond refinancing costs (2)		12.2		15.4
Environmental remediation		23.2		23.6
Competitive rate adjustment		3.2		3.3
Other		17.1		16.3
Total other regulatory assets		322.6		338.0
Total regulatory assets		387.0		404.6
Less: Current portion		55.8		62.7
Long-term regulatory assets	$	331.2	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	16.7	$	17.7
Other:
Cost recovery clauses		70.7		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.5		37.4
Deferred gain on property sales (3)		5.4		6.3
Provision for stipulation and other (4)		0.8		9.8
Accumulated reserve-cost of removal		576.7		572.2
Total other regulatory liabilities		716.3		723.1
Total regulatory liabilities		733.0		740.8
Less: Current portion		95.5		110.0
Long-term regulatory liabilities	$	637.5	$	630.8

(1) Primarily related to plant life and derivative positions.

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

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

(4) Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS’s 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.

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

	Sep. 30,		Dec 31,
(millions)	2011		2010
Clause recoverable (1)	$	41.2	$	45.2
Components of rate base (2)		240.9		248.1
Regulatory tax assets (3)		64.4		66.6
Capital structure and other (3)		40.5		44.7
Total	$	387.0	$	404.6

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

(2) Primarily reflects allowed working capital, which is included in rate base and earns 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.

36

4. Income Taxes

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Tampa Electric Company’s effective tax rates for the nine months ended Sep. 30, 2011 and Sep. 30, 2010 differ from the statutory rate principally due to state income taxes, domestic activity production deduction and the equity portion of Allowance for Funds Used During Construction.

The IRS concluded its examination of TECO Energy’s consolidated federal income tax return for the year 2009 during 2010. The U.S. federal statute of limitations remains open for the year 2008 and onward. Years 2010 and 2011 are currently under examination by the IRS under its Compliance Assurance Program. 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 2011. Florida’s statute of limitations is three 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 Florida’s tax authorities include 2008 and onward.

5. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. Tampa Electric Company’s portion of the net pension expense for the three months ended Sep. 30, 2011 and 2010, respectively, was $3.4 million and $4.7 million for pension benefits, and $3.4 million for other postretirement benefits. For the nine months ended Sep. 30, 2011 and 2010, respectively, net benefit expenses were $10.1 million and $14.0 million for pension benefits and $10.1 million and $10.3 million for other postretirement benefits.

For the fiscal 2011 plan year, TECO Energy assumed an expected long-term return on plan assets of 7.75% and a discount rate of 5.30% for pension benefits under its qualified pension plan, and a discount rate of 5.25% for its other postretirement benefits as of their Jan. 1, 2011 measurement dates.

Effective Dec. 31, 2006, in accordance with the accounting standard for defined benefit plans and other postretirement benefits, Tampa Electric Company adjusted its postretirement benefit obligations and recorded regulatory assets to reflect the unamortized transition obligation, prior service cost, and actuarial gains and losses of its postretirement benefit plans. Included in the benefit expenses discussed above, for the three months and nine months ended Sep. 30, 2011, Tampa Electric Company reclassed $2.9 million and $8.6 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income. For the three months and nine months ended Sep. 30, 2010, Tampa Electric Company reclassed $3.1 million and $9.5 million, respectively.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, The Health Care and Education Reconciliation Act, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, Tampa Electric Company reduced its deferred tax asset by $5.3 million and recorded a corresponding regulatory tax asset.

6. Short-Term Debt

At Sep. 30, 2011 and Dec. 31, 2010, the following credit facilities and related borrowings existed:

	Sep. 30, 2011						Dec. 31, 2010
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	5.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		7.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	12.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures May 9, 2012. See Note 14 for information on an amendment to this facility.

These credit facilities require commitment fees ranging from 7.0 to 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2010 was 0.64%.

37

Tampa Electric Company Accounts Receivable Facility

On Feb. 18, 2011, Tampa Electric Company and TRC, a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Omnibus Amendment No. 9 to the Loan and Servicing Agreement with certain lenders named therein and Citicorp North America, Inc. as Program Agent. The amendment (i) extends the maturity date to Feb. 17, 2012, (ii) provides that TRC will pay program and liquidity fees, which will total 70 basis points, (iii) provides that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank offered rate (if available) plus a margin and (iv) makes other technical changes.

7. Long-Term Debt

Purchase in Lieu of Redemption of Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On Mar. 1, 2011, Tampa Electric Company purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA had issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously had been in auction rate mode and had been held by Tampa Electric Company since Mar. 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to Mar. 1, 2011.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the Mar. 1, 2011 purchase of the PCIDA Bonds, $95.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Sep. 30, 2011 (Held Bonds) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

38

8. Commitments and Contingencies

Legal Contingencies

From time to time, Tampa Electric Company and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on Tampa Electric Company’s results of operations, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

The second portion of a non-jury trial in this case was held in October 2011 in the Dade County, Florida Circuit Court. The first portion was held in June 2011. The trial is expected to resume and conclude in the first half of 2012. Merco alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, the court will consider PGS’s counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2011, Tampa Electric Company has estimated its ultimate financial liability to be $21.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in “Long-term regulatory liabilities” on Tampa Electric Company’s Consolidated Condensed Balance Sheet. 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 clean-up costs attributable to Tampa Electric Company. The estimates to perform the work are based on 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.

In instances where other PRPs are involved, many of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, Tampa Electric Company could be liable for more than Tampa Electric Company’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Potentially Responsible Party Notification

In October 2010, the U.S. EPA notified Tampa Electric Company that it is a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, commonly known as Superfund, for the proposed conduct of a contaminated soil removal action and further clean up, if necessary, at a property owned by Tampa Electric Company in Tampa, Florida. The property owned by Tampa Electric Company is undeveloped except for location of transmission lines and poles, and is adjacent to an industrial site, not owned by Tampa Electric Company, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to Tampa Electric Company’s ownership of the property described above but, to the knowledge of Tampa Electric Company, this assertion is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company has responded to the EPA regarding such matter. The scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

39

Letters of Credit

A summary of the face amount or maximum theoretical obligation under Tampa Electric Company’s letters of credit as of Sep. 30, 2011 are as follows:

Letters of Credit -Tampa Electric Company

(millions)
									Liabilities Recognized
Letters of Credit for the Benefit of:	2011		2012- 2015		After (1) 2015		Total		at Sep. 30, 2011
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2015.

Financial Covenants

In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2011, Tampa Electric Company was in compliance with all applicable financial covenants.

40

9. Segment Information

(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa  Electric Company
2011
Revenues—external	$	591.8	$	93.8	$	0.0		$	685.6
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Total revenues		591.9		94.2		(0.5	)		685.6
Depreciation		56.2		12.2		0.0			68.4
Total interest charges		30.3		4.4		0.0			34.7
Provision for taxes		47.4		3.0		0.0			50.4
Net income		75.0		4.8		0.0			79.8
2010
Revenues—external	$	593.3	$	114.1	$	0.0		$	707.4
Sales to affiliates		0.3		2.5		(2.6	)		0.2
Total revenues		593.6		116.6		(2.6	)		707.6
Depreciation		54.4		11.5		0.0			65.9
Total interest charges		30.7		4.6		0.0			35.3
Provision for taxes		36.8		2.4		0.0			39.2
Net income		61.9		3.7		0.0			65.6
Nine months ended Sep. 30,
2011
Revenues—external	$	1,571.2	$	358.5	$	0.0		$	1,929.7
Sales to affiliates		0.4		3.0		(3.4	)		0.0
Total revenues		1,571.6		361.5		(3.4	)		1,929.7
Depreciation		166.4		36.0		0.0			202.4
Total interest charges		91.6		13.3		0.0			104.9
Provision for taxes		104.3		16.0		0.0			120.3
Net income		165.0		25.4		0.0			190.4
Total assets at Sep. 30, 2011	$	5,691.7	$	840.4	($	5.9	)	$	6,526.2
2010
Revenues—external	$	1,670.9	$	408.2	$	0.0		$	2,079.1
Sales to affiliates		1.0		17.4		(17.7	)		0.7
Total revenues		1,671.9		425.6		(17.7	)		2,079.8
Depreciation		161.0		34.3		0.0			195.3
Total interest charges		91.8		13.8		0.0			105.6
Provision for taxes		98.4		16.9		0.0			115.3
Net income		166.8		26.7		0.0			193.5
Total assets at Dec. 31, 2010	$	5,580.6	$	872.7	($	14.8	)	$	6,438.5

41

10. 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.

Tampa Electric Company applies the accounting standards for derivatives and hedging. 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.

Tampa Electric Company applies accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for the regulated companies. These standards, 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 (see Note 3).

Tampa Electric Company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if Tampa Electric Company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if Tampa Electric Company intends to receive physical delivery and if the transaction is reasonable in relation to Tampa Electric Company’s business needs. As of Sep. 30, 2011, 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 Sep. 30, 2011 and Dec. 31, 2010 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)	Sep.  30, 2011		Dec.  31, 2010
Current assets	$	0.0	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.0	$	1.1
Current liabilities(1)	$	29.5	$	27.2
Long-term liabilities		4.5		2.6
Total liabilities	$	34.0	$	29.8

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The ending balance in AOCI related to previously settled interest rate swaps at Sep. 30, 2011 is a net loss of $4.8 million after tax and accumulated amortization. This compares to a net loss of $5.3 million in AOCI after tax and accumulated amortization at Dec. 31, 2010.

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sep. 30, 2011:

42

Energy Related Derivatives

	Asset Derivatives				Liability Derivatives
(millions) at Sep. 30, 2011	Balance Sheet Location(1)		Fair              Value		Balance Sheet Location(1)		Fair              Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	0.0		Regulatory assets	$	29.5
Long-term		Regulatory liabilities		0.0		Regulatory assets		4.5
Total			$	0.0			$	34.0

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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 Sep. 30, 2011, net pretax losses of $29.5 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 three and nine months ended Sep. 30:

(millions)	Location of Loss Reclassified From AOCI Into Income	Amount of Loss Reclassified From AOCI Into Income(1)
Derivatives in Cash Flow Hedging Relationships	Effective Portion(1)	Three months ended Sep. 30:			Nine months ended Sep. 30:
2011
Interest rate contracts:	Interest expense	($	0.2	)	($	0.5	)
Total		($	0.2	)	($	0.5	)
2010
Interest rate contracts:	Interest expense	($	0.2	)	($	0.6	)
Total		($	0.2	)	($	0.6	)

(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 and nine months ended Sep. 30, 2011 and 2010, 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, 2013 for the financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Sep. 30, 2011, are expected to settle during the 2011, 2012 and 2013 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2011		0.0		11.6
2012		0.0		35.0
2013		0.0		5.0
Total		0.0		51.6

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. Tampa Electric Company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

43

It is possible that volatility in commodity prices could cause Tampa Electric 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, Tampa Electric Company could suffer a material financial loss. However, as of Sep. 30, 2011, substantially all of the counterparties with transaction amounts outstanding in Tampa Electric Company’s energy portfolio are rated investment grade by the major 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. Tampa Electric Company generally enters into the following master arrangements: (1) EEI agreements — standardized power sales contracts in the electric industry; (2) ISDA agreements — standardized financial gas and electric contracts; and (3) NAESB agreements — 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 its 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.

Certain of Tampa Electric Company 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 Sep. 30, 2011:

Contingent Features

(millions) At Sep. 30, 2011	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(34.0	)	$	(34.0	)	$	0.0

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth, by level within the fair value hierarchy, Tampa Electric Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2011 and Dec. 31, 2010. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Tampa Electric 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.

44

Recurring Derivative Fair Value Measures

	At fair value as of Sep. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Total	$	0.0	$	0.0	$	0.0	$	0.0
Liabilities
Natural gas swaps	$	0.0	$	34.0	$	0.0	$	34.0
Total	$	0.0	$	34.0	$	0.0	$	34.0

	At fair value as of Dec. 31, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.1	$	0.0	$	1.1
Total	$	0.0	$	1.1	$	0.0	$	1.1
Liabilities
Natural gas swaps	$	0.0	$	29.8	$	0.0	$	29.8
Total	$	0.0	$	29.8	$	0.0	$	29.8

Natural gas swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the 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.

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 Sep. 30, 2011, 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.

Fair Value of Long-Term Debt

At Sep. 30, 2011, Tampa Electric Company’s total long-term debt had a carrying amount of $1,991.2 million and an estimated fair market value of $2,291.4 million. At Dec. 31, 2010, total long-term debt had a carrying amount of $2,069.5 million and an estimated fair market value of $2,217.0 million.

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Sep. 30,							Nine months ended Sep. 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2011
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.9	$	(0.4	)	$	0.5
2010
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.9	$	(0.3	)	$	0.6

Accumulated Other Comprehensive Loss

(millions)	Sep. 30, 2011			Dec. 31, 2010
Net unrealized losses from cash flow hedges (1)	$	(4.8	)	$	(5.3	)
Total accumulated other comprehensive loss	$	(4.8	)	$	(5.3	)

(1) Net of tax benefit of $3.0 million and $3.4 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

45

13. Variable Interest Entities

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE’s primary beneficiary. Under the amended standard, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric Company has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance; regulatory; credit; commodity/fuel; and energy market risk. Tampa Electric Company has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric Company is not required to consolidate any of these entities. Tampa Electric Company purchased $22.9 million and $64.9 million pursuant to PPAs for the three and nine months ended Sep. 30, 2011, respectively, and $29.7 million and $90.6 million for the three and nine months ended Sep. 30, 2010, respectively.

In one instance, Tampa Electric Company’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, the company is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, Tampa Electric Company is unable to determine if this entity is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. Tampa Electric Company has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for Tampa Electric Company is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. Under this PPA, Tampa Electric Company purchased $12.0 million and $24.9 million for the three and nine months ended Sep. 30, 2011, respectively, and $14.7 million and $45.0 million for the three and nine months ended Sep. 30, 2010, respectively.

Tampa Electric Company does not provide any material financial or other support to any of the VIEs it is involved with, nor is it under any obligation to absorb losses associated with these VIEs. In the normal course of business, Tampa Electric Company’s involvement with the remaining VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

14. Subsequent Events

Tampa Electric Company $325 million bank credit facility amendment

On Oct. 25, 2011, Tampa Electric Company (Tampa Electric) amended its $325 million bank credit facility, entering into a Third Amended and Restated Credit Agreement with ten lenders. The amendment (i) extends the maturity date of the credit facility from May 9, 2012 to Oct. 25, 2016 (subject to further extension with the consent of each lender); (ii) continues to allow Tampa Electric to borrow funds at a rate equal to the London interbank deposit rate plus a margin (iii) as an alternative to the above interest rate, allows Tampa Electric to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows Tampa Electric to borrow funds on a same-day basis under a new Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) continues to allow Tampa Electric to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility (compared to $50 million under the previous agreement); and (vii) makes other technical changes.

46

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Management’s Discussion & 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 the 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; the effect of extreme weather conditions or hurricanes; operating conditions, commodity prices, operating cost and environmental or safety rule changes affecting the production levels and margins at TECO Coal; conditions affecting TECO Coal’s ability to permit and develop additional specialty coal reserves and /or increase specialty coal sales; fuel cost recoveries and related cash at Tampa Electric; natural gas demand at Peoples Gas; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2010 and in Part II, Item 1A. of this Quarterly Report on Form 10-Q.

Earnings Summary - Unaudited

	Three months ended Sep. 30,				Nine months ended Sep. 30,
(millions, except per share amounts)	2011		2010		2011		2010
Consolidated revenues	$	911.4	$	901.8	$	2,593.2	$	2,712.9
Net income attributable to TECO Energy	$	90.2	$	51.0	$	219.4	$	182.3
Average common shares outstanding
Basic		213.8		212.8		213.5		212.5
Diluted		215.3		215.1		215.1		214.6
Earnings per share — basic	$	0.42	$	0.24	$	1.02	$	0.85
Earnings per share — diluted	$	0.42	$	0.24	$	1.02	$	0.85

Operating Results

Three Months Ended September 30, 2011

TECO Energy, Inc. reported third quarter net income of $90.2 million, or $0.42 per share, compared to $51.0 million, or $0.24 per share, in the third quarter of 2010. Net income in the 2010 third quarter reflected the one-time $24.0 million reduction in base revenue ($14.7 million after-tax, or $0.07 per share) at Tampa Electric under its regulatory agreement approved by the FPSC in August 2010. Results in the third quarter of 2010 also included $23.1 million of net charges and gains primarily related to taxes on undistributed earnings at DECA II (see TECO Guatemala discussion).

Nine months Ended September 30, 2011

Year-to-date net income and earnings per share were $219.4 million, or $1.02 per share, in 2011, compared to $182.3 million, or $0.85 per share, in the same period in 2010. Year-to-date results in 2010 were reduced by net charges and gains of $44.3 million that included the third quarter charges and gains.

Operating Company Results

All amounts included in the operating company and Parent & other results discussions below are after tax, unless otherwise noted.

Tampa Electric Company – Electric Division

Tampa Electric reported net income for the third quarter of $75.0 million, compared with $61.9 million for the same period in 2010. Results for the quarter reflect a 0.8% higher average number of customers, and lower operations and maintenance expenses. Net income for the 2010 quarter reflected the one-time $24.0 million reduction in base revenues ($14.7 million after tax) associated with the regulatory agreement approved by the FPSC in August 2010 that resolved all outstanding issues from the 2008 base rate case.

Total degree days in Tampa Electric’s service area were 7% above normal, but essentially in line with the third quarter of 2010.

Rainfall in the quarter was 14% above normal, which did not affect degree days but did lower energy sales to residential customers. Base revenues in the 2011 third quarter were $4 million to $6 million lower than in the 2010 period due to the effects of weather. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 1.3% in the third quarter of 2011, compared to the same period in 2010. Lower retail energy sales were driven primarily by lower sales to industrial-phosphate customers due to increased self-generation capacity by one large industrial-phosphate customer. The quarterly energy sales shown on the statistical summary that follows reflect the energy sales based on the timing of billing cycles, which can vary period to period.

47

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, decreased $6.2 million due to lower accruals for performance-based incentive compensation for all employees and other benefit costs. Depreciation and amortization expense increased $1.1 million due to additions to facilities to serve customers.

Year-to-date net income was $165.0 million, compared with $166.8 million in the 2010 period, driven primarily by lower energy sales due to milder winter weather than in the record-cold 2010 winter season, partially offset by 0.7% higher average number of customers, lower operations and maintenance expenses, and higher earnings on NOx control projects.

Year-to-date total degree days in Tampa Electric’s service area were 8% above normal, but 5% below the prior year-to-date period. Pretax base revenue was $30 million to $35 million lower than in 2010, primarily reflecting the milder weather and the voluntary conservation that occurred during the mild winter and spring periods without extreme weather.

In the 2011 year-to-date period, total net energy for load declined 4.6% compared to the same period in 2010. Lower retail energy sales were driven primarily by milder winter weather and lower sales to industrial-phosphate customers, due to the factors described above. Sales to commercial and industrial-other customers reflect the modest improvements in the Florida economy experienced by certain customers, primarily medical facilities and certain manufacturers. The year-to-date energy sales shown on the statistical summary that follows reflect the higher sales associated with the late December 2010 cold weather that are included in 2011 billed sales.

Year-to-date operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, decreased $13.9 million. Higher spending on operating and maintaining the transmission and distribution systems were more than offset by lower accruals of performance-based incentive compensation for all employees and other benefit costs, and lower bad debt expense.

Compared to the 2010 year-to-date period, depreciation and amortization expense increased $3.3 million, reflecting the additions to facilities to serve customers discussed above.

48

A summary of Tampa Electric’s operating statistics for the three and nine months ended Sep. 30, 2011 and 2010 follows:

	Operating Revenues									Kilowatt-hour sales
(millions, except average customers)	2011			2010			% Change			2011		2010		% Change
Three months ended Sep. 30,
By Customer Type
Residential	$	313.2		$	339.2			(7.7	)		2,746.9		2,830.0		(2.9	)
Commercial		172.2			183.3			(6.1	)		1,777.6		1,792.9		(0.9	)
Industrial – Phosphate		15.4			19.0			(18.9	)		182.0		210.4		(13.5	)
Industrial – Other		26.0			27.8			(6.5	)		282.6		285.9		(1.2	)
Other sales of electricity		49.7			50.7			(2.0	)		503.3		482.8		4.2
Deferred and other revenues (1)					(28.7	)		(100.0	)
		576.5			591.3			(2.5	)		5,492.4		5,602.0		(2.0	)
Provision for revenue stipulation		(4.0	)		(24.0	)		(83.3	)
Sales for resale		5.8			13.1			(55.7	)		89.8		173.2		(48.2	)
Other operating revenue		13.6			13.2			3.0
	$	591.9		$	593.6			(0.3	)		5,582.2		5,775.2		(3.3	)
Average customers (thousands)		676.2			671.0			0.8
Retail net energy for load (kilowatt hours)											5,740.0		5,820.4		(1.4	)
Nine months ended Sep. 30,
By Customer Type
Residential	$	788.4		$	862.1			(8.5	)		6,913.9		7,193.7		(3.9	)
Commercial		465.9			491.7			(5.2	)		4,738.6		4,727.4		0.2
Industrial – Phosphate		46.5			64.1			(27.5	)		548.5		725.4		(24.4	)
Industrial – Other		74.7			78.6			(5.0	)		808.5		804.1		0.5
Other sales of electricity		139.4			143.9			(3.1	)		1,386.2		1,352.3		2.5
Deferred and other revenues (1)		(1.9	)		(15.5	)		(87.7	)
		1,513.0			1,624.9			(6.9	)		14,395.7		14,802.9		(2.8	)
Provision for revenue stipulation		0.0			(24.0	)		(100.0	)
Sales for resale		18.3			33.0			(44.5	)		279.8		400.2		(30.1	)
Other operating revenue		40.3			37.8			6.6
NOx Allowance sales		0.0			0.2			(100.0	)
	$	1,571.6		$	1,671.9			(6.0	)		14,675.5		15,203.1		(3.5	)
Average customers (thousands)		675.3			670.6			0.7
Retail net energy for load (kilowatt hours)											15,044.1		15,770.0		(4.6	)

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

Tampa Electric Company – Natural Gas Division (Peoples Gas)

Peoples Gas reported net income of $4.8 million for the third quarter, compared to $3.7 million in the same period in 2010. Quarterly results reflect a 0.9% higher average number of customers. Sales to residential customers increased due to customer growth, and sales volumes to commercial customers increased due to improvements in the Florida economy. Off-system sales decreased due to increased capacity available on an intrastate pipeline operating in Florida. Results in the 2010 quarter included a $3.1 million provision related to potential earnings above the top of the allowed return on equity (ROE) range as a result of the unprecedented cold winter weather in 2010 and Peoples Gas’ expectation that it would earn above the top of its allowed ROE range of 9.75% to 11.75%. Excluding this $3.1 million provision affecting expense in 2010, non-fuel operations and maintenance expense increased $0.9 million in 2011 due to generally higher spending on pipeline maintenance, partially offset by lower accruals of performance-based incentive compensation for all employees. Results also reflect increased depreciation expense due to routine plant additions.

Peoples Gas reported net income of $25.4 million for the year-to-date period, compared to $26.7 million in the same period in 2010. Results reflect a 0.7% higher average number of customers, but lower usage by residential and commercial customers due to milder weather in the first quarter compared to the unusually cold winter weather in 2010. Increased sales volumes to industrial customers reflect the operation of several higher-usage customers that were idle in the 2010 period. Excluding the $5.5 million year-to-date impact of the provision related to potential earnings above the top of the allowed ROE range in 2010, non-fuel operations and maintenance expense was higher in 2011, including $2.2 million of expenses related to the defense of environmental contamination claims.

49

A summary of PGS’s regulated operating statistics for the three and nine months ended Sep. 30, 2011 and 2010 follows:

	Operating Revenues							Therms
(millions, except average customers)	2011		2010		% Change			2011		2010		% Change
Three months ended Sep. 30,
By Customer Type
Residential	$	24.7	$	24.0		2.9			10.1		9.9		2.0
Commercial		28.3		27.0		4.8			87.8		85.5		2.7
Industrial		2.0		2.2		(9.1	)		46.2		46.5		(0.6	)
Off system sales		26.6		49.2		(45.9	)		55.9		94.1		(40.6	)
Power generation		2.7		3.0		(10.0	)		177.0		180.0		(1.7	)
Other revenues		7.7		8.9		(13.5	)
	$	92.0	$	114.3		(19.5	)		377.0		416.0		(9.4	)
By Sales Type
System supply	$	61.7	$	83.4		(26.0	)		75.0		115.0		(34.8	)
Transportation		22.6		22.0		2.7			302.0		301.0		0.3
Other revenues		7.7		8.9		(13.5	)
	$	92.0	$	114.3		(19.5	)		377.0		416.0		(9.4	)
Average customers (thousands)		338.2		335.2		0.9
Nine months ended Sep. 30,
By Customer Type
Residential	$	109.4	$	124.6		(12.2	)		59.9		69.7		(14.1	)
Commercial		105.7		111.7		(5.4	)		305.3		307.0		(0.6	)
Industrial		6.5		7.0		(7.1	)		151.2		149.6		1.1
Off system sales		93.7		136.5		(31.4	)		198.4		249.3		(20.4	)
Power generation		8.2		7.5		9.3			472.9		452.8		4.4
Other revenues		30.5		31.3		(2.6	)
	$	354.0	$	418.6		(15.4	)		1,187.7		1,228.4		(3.3	)
By Sales Type
System supply	$	247.8	$	313.3		(20.9	)		292.8		359.2		(18.5	)
Transportation		75.7		74.0		2.3			894.9		869.2		3.0
Other revenues		30.5		31.3		(2.6	)
	$	354.0	$	418.6		(15.4	)		1,187.7		1,228.4		(3.3	)
Average customers (thousands)		338.7		336.2		0.7

TECO Coal

TECO Coal achieved third quarter net income of $14.1 million on sales of 2.1 million tons, compared to $8.3 million on sales of 2.2 million tons in the same period in 2010.

In 2011, results reflect an average net per-ton selling price, excluding transportation allowances, of almost $90 per ton, almost 19% higher than in 2010 due to a sales mix that was more heavily weighted to specialty coal, including metallurgical and PCI coal. In the third quarter of 2011, the all-in total per-ton cost of production increased to more than $81 per ton. Cost of production in the third quarter was driven by higher contract miner costs, higher costs related to new roof control requirements, higher costs of all supplies that are oil-related such as conveyor belts and tires, and lower productivity due to continued high levels of safety inspections. TECO Coal estimates that increased safety inspections have reduced production more than 10% compared to prior years. TECO Coal's effective income tax rate in the third quarter of 2011 was 22%, compared to 24% in the 2010 period.

TECO Coal recorded year-to-date net income of $38.1 million on sales of 6.2 million tons in 2011, compared to $45.8 million on sales of 6.8 million tons in the 2010 period. In 2010, year-to-date net income included a $5.3 million benefit from the settlement of state income tax issues recorded in prior years. The year-to-date sales mix was driven by the same factors as in the third quarter. The 2011 year-to-date average net per-ton selling price was almost $87 per ton and the all-in total per-ton cost of production was $79 per ton. TECO Coal’s effective income tax rate was 22% in the year-to-date period, compared to 23%, excluding the effect of the state income tax settlements discussed above, in the 2010 year-to-date period.

50

Exploration and Drilling Program Results

TECO Coal has made a new discovery of an additional estimated 65 million tons of true metallurgical coal on properties it controls at its Premier Elkhorn mine that are classified as proven and probable reserves, and an additional estimated 9 million tons of metallurgical coal classified as resource (non-reserve coal deposits). TECO Coal is evaluating mining plans and potential markets for this high-vol metallurgical coal, and estimates that, development of these reserves would take at least two years. These new tons can be deep mined and efficiently transported by conveyor belts at our Premier Elkhorn mine, which has a prep plant with capacity to handle higher production. These new reserves dramatically increase the percentage of high-value true metallurgical coal in TECO Coal’s reserve base. TECO Coal has applied to the State of Kentucky for the necessary permit amendments related to surface development activities to access these reserves.

TECO Guatemala

TECO Guatemala reported third quarter net income of $4.5 million in 2011, compared to a loss of $12.6 million in the 2010 period. TECO Guatemala’s third quarter 2010 results included a $24.9 million tax charge related to undistributed earnings as a result of the sale of its ownership interest in DECA II, which included EEGSA and affiliated companies, on Oct. 21, 2010. Year-to-date 2011 net income was $16.4 million, compared to $8.4 million in the 2010 period. Results in the 2011 quarter reflect no earnings from DECA II, sold in October 2010, which were $4.1 million and $12.1 million in the 2010 quarter and year-to-date periods, respectively, and $1.5 million and $5.2 million lower capacity payments in the 2010 quarter and year-to-date periods, respectively, related to the Alborada Power Station contract extension, which became effective September 2010. Results at the San José Power Station reflect higher contract and spot energy sales and prices, and lower interest expense due to lower rates on the non-recourse debt. In the 2010 third quarter, results included a $3.6 million benefit from insurance recoveries related to the unplanned outages at the San José Power Station in 2009.

Parent & other

The cost for Parent & other in the third quarter of 2011 was $8.2 million, compared to a cost of $10.3 million in the same period in 2010. Results in 2011 reflect $3.2 million lower interest expense as a result of the 2011 debt retirements and 2010 debt restructuring and retirement actions. In the 2010 quarter, the cost for Parent & other included a $1.8 million benefit from the recovery of fees related to the previously sold McAdams Power Station.

The year-to-date Parent & other cost was $25.5 million in 2011, compared to $65.4 million in the 2010 period. Results in 2011 reflect $10.6 million lower interest expense as a result of 2011 debt retirement and the 2010 debt restructuring and retirement actions. The 2010 year-to-date cost included the third-quarter benefit related to the McAdams Power station, $20.3 million of debt retirement charges and $0.9 million of final restructuring charges. In 2010, the year-to-date cost for Parent & other also included negative valuation adjustments to foreign tax credits totaling $5.9 million based on estimated foreign source income and projected timing of the utilization of the net operating loss carry forwards, and a $1.1 million charge to adjust deferred tax balances related to the Medicare Part D subsidies as a result of the Patient Protection and Affordable Care Act enacted in 2010.

2011 Guidance and Business Drivers

Based on strong year-to-date actual results, generally milder than normal weather, which affects sales at Tampa Electric, and year-to-date-cost pressures at TECO Coal, TECO Energy is revising its 2011 earnings per share guidance to a range of $1.25 to $1.35, excluding charges and gains.

Tampa Electric and Peoples Gas expect to earn their respective allowed returns on equity authorized in their 2009 base rate proceedings. Tampa Electric expects customer growth to continue to be in line with the trends experienced in the 2011 year-to-date period. Weather in the fourth quarter to date period has been milder than normal, and the mild weather pattern is forecast to continue in November. In 2010, weather added between $30 million and $40 million to pretax base revenue at Tampa Electric. Also in 2010, Tampa Electric reduced base revenue $24 million as a one-time item under its regulatory agreement approved by the FPSC.

TECO Coal expects 2011 sales of between 8.2 million and 8.5 million tons at an average selling price across all products of more than $88 per ton. The 2011 product mix is expected to be about 45% specialty coal, which includes stoker, metallurgical and PCI coals, and the remainder utility steam coal. The full-year cost of production is now expected to be about $79 per ton which is above the previously provided cost range of $74 and $78 per ton.

The guidance assumes normal operations for the Alborada and San José power stations in Guatemala. TECO Guatemala extended the power sales contract for the Alborada Power Station for five years at rates approximately 55%, or $7.0 million after tax on an annual basis, below the previous contract level effective Sept. 14, 2010. TECO Guatemala’s 2011 results reflect the absence of earnings from DECA II, which was sold in October 2010. Prior to the sale, DECA II contributed $13.1 million to 2010 net income at TECO Guatemala.

Parent & other interest cost in 2011 reflects the December 2010 early retirement of $236 million of TECO Energy and TECO Finance notes due in 2012, and the repayment of $64 million of notes at maturity on May 1, 2011.

This guidance is provided in the form of a range to allow for varying outcomes with respect to important variables, such as weather and customer usage at the Florida utilities, and volumes and margins at TECO Coal.

51

2012 Preliminary Outlook

The operating companies are in the process of developing detailed 2012 business plans, and formal 2012 guidance will be provided at the time of TECO Energy’s fourth-quarter earnings release in early February. Major business drivers that are expected to impact 2012 results include:

For 2012, both Florida utilities expect to continue to earn within their allowed ROE ranges of 10.25% to 12.25% for Tampa Electric and 9.75% to 11.75% for Peoples Gas. The economy in Florida continues to improve slowly and Tampa Electric and Peoples Gas expect customer growth to continue in line with the trends experienced in 2011. The utilities expect to manage operations and maintenance costs to levels that will allow them to earn the allowed ROEs. Tampa Electric is in the process of reviewing its generating capacity expansion plans, and expects to include in its 2012 capital expenditure forecast the initial expenditures for preliminary engineering and for transmission system enhancements needed to support its preferred generating capacity addition of converting the peaking units at the Polk Power Station to combined cycle units, which are expected to enter service in early 2017.

TECO Coal expects sales to be at levels similar to 2011 in a range between 8.2 million and 8.5 million tons. The contracting cycle for North American metallurgical coal sales is in progress, but final commitments remain open. The product mix is expected to be 45% to 50% specialty coal, which includes stoker, metallurgical and PCI coals, and the remainder utility steam coal. The coal tons related to the below-market contract that expires at the end of 2011 were already contracted at then current market prices in the second quarter, which is expected to add $24 million to revenue in 2012. In the current market environment, TECO Coal expects to contract for 2012 metallurgical coal sales at prices similar to 2011 levels. In the fall of 2010, when TECO Coal contracted the majority of its 2011 domestic metallurgical coal sales, the benchmark price for hard-coking coal was $209 per metric tonne, compared to the current benchmark price of $285 per metric tonne. The cost of production is expected to increase in 2012 due to a continuation of the factors that have driven costs in 2011. By modifying the mining plan to eliminate valley fills, TECO Coal has received a surface mine permit that it had sought for several years.

TECO Guatemala expects normal operations for the Alborada Power Station. The San José Power Station has a scheduled major outage, which will reduce energy sales and financial results from that plant.

Income Taxes

The provisions for income taxes from continuing operations for the nine month periods ended Sep. 30, 2011 and 2010 were $123.7 million and $135.9 million, respectively. The nine months ended Sep. 30, 2010 includes the $24.9 million of U.S. deferred taxes recognized on undistributed earnings of certain foreign subsidiaries which are no longer considered indefinitely reinvested and a $5.9 million foreign tax credit valuation allowance.

Liquidity and Capital Resources

The table below sets forth the Sep. 30, 2011 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 Sep. 30, 2011

(millions)	Consolidated		Tampa Electric Company		Other		Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts / LCs		0.7		0.7		0.0		0.0
Available credit facilities		674.3		474.3		0.0		200.0
Cash and short-term investments		165.8		111.1		29.2		25.5
Total liquidity	$	840.1	$	585.4	$	29.2	$	225.5

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 the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2011, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Sep. 30, 2011. Reference is made to the specific agreements and instruments for more details.

52

Significant Financial Covenants

(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Sep. 30, 2011
Tampa Electric Company
Credit facility(2)	Debt/capital	Cannot exceed 65%	47.6%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%	47.6%
6.25% senior notes	Debt/capital	Cannot exceed 60%	47.6%
	Limit on liens(3)	Cannot exceed $700	$0 liens outstanding
Insurance agreement relating to certain pollution bonds	Limit on liens(3)	Cannot exceed $445 (7.5% of net assets)	$0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	EBITDA/interest(4)	Minimum of 2.6 times	5.0 times
TECO Energy 6.75% notes and TECO Finance 6.75% notes	Restrictions on secured debt(5)	(6)	(6)

(1) As defined in each applicable instrument.

(2) See Note 6 to the TECO Energy Consolidated Financial Statements for a description of the credit facilities.

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

(4) EBITDA generally represents EBIT before depreciation and amortization. However, the term is subject to the definition prescribed under the relevant agreement.

(5) These restrictions would not apply to first mortgage bonds of Tampa Electric Company if any were outstanding.

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

Credit Ratings of Senior Unsecured Debt at Sep. 30, 2011

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

On May 27, 2011, Standard & Poor’s upgraded Tampa Electric Company, TECO Finance and TECO Energy to BBB+, BBB and BBB, respectively, all with stable outlooks.

On Mar. 24, 2011, Fitch Ratings upgraded Tampa Electric Company, TECO Finance and TECO Energy to A-, BBB and BBB, respectively, all with stable outlooks

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. Fitch describes credit ratings in the A category as representing strong capacity for payment of financial obligations. The lowest investment grade credit ratings for Standard & Poor’s is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign TECO Energy, TECO Finance and Tampa Electric Company’s senior unsecured debt investment grade ratings.

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. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of Tampa Electric Company’s derivative instruments contain provisions that require Tampa Electric Company’s debt to maintain an investment grade credit rating. See Note 12 to the TECO Energy, Inc., Consolidated Condensed Financial Statements. The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings. These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Fair Value Measurements

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 accounting standards for regulated operations, 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.

Diesel fuel 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.

53

The valuation methods we used to determine fair value are described in Note 13 to the TECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2011 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 TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2010.

54

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.

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 2011 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 average fixed price component of the company’s outstanding natural gas swaps of approximately 15% from Dec. 31, 2010 to Sep. 30, 2011. For natural gas, the company maintains a similar volume hedged as of Sep. 30, 2011 from Dec. 31, 2010.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine months ended Sep. 30, 2011:

Changes in Fair Value of Derivatives (millions)

Net fair value of derivatives as of Dec. 31, 2010	$	(26.9	)
Additions and net changes in unrealized fair value of derivatives		(34.2	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		27.1
Net fair value of derivatives as of Sep. 30, 2011	$	(34.0	)
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2010	$	(26.9	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(34.2	)
Recorded in earnings		0.0
Realized net settlement of derivatives		27.1
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Sep. 30, 2011	$	(34.0	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sep. 30, 2011:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Sep. 30, 2011 (millions)

Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	0.0		$	0.0		$	0.0
Other external sources (1)		(28.2	)		(5.8	)		(34.0	)
Model prices (2)		0.0			0.0			0.0
Total	$	(28.2	)	$	(5.8	)	$	(34.0	)

(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.

55

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 control over financial reporting that occurred during TECO Energy’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Tampa Electric Company

(a) Evaluation of Disclosure Controls and Procedures. Tampa Electric Company’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of Tampa Electric Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the Evaluation Date. Based on such evaluation, Tampa Electric Company’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, Tampa Electric Company’s disclosure controls and procedures are effective.

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

Item 5. OTHER INFORMATION

TECO Coal is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (the Mine Act). Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and proposed Item 106 of Regulation S-K (17 CFR 229.106) is included in Exhibit 99.1 to this quarterly report.

56

PART II. OTHER INFORMATION

Item 1A. RISK FACTORS

Our computer systems and Tampa Electric’s infrastructure may be subject to cyber (primarily electronic or internet based) attack, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems.

There have been an increasing number of cyber-attacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the internet, through malware, viruses, or attachments to e-mails or through persons inside of the organization or with persons with access to systems inside of the organization.

We have security systems and infrastructure in place to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, we cannot be assured that a cyber-attack will not cause electric or gas system operational problems, disruptions of service to customers, or compromise important data or systems.

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

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

	(a)		(b)		(c)		(d)
	Total Number of Shares (or Units) Purchased (1)		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Jul. 1, 2011—Jul. 31, 2011		380	$	18.74		0.0	$	0.0
Aug. 1, 2011—Aug. 31, 2011		8,547	$	17.48		0.0		0.0
Sep. 1, 2011—Sep. 30, 2011		494	$	17.28		0.0		0.0
Total 3rd Quarter 2011		9,421	$	17.52		0.0	$	0.0

(1) These shares were not repurchased through a publicly announced plan or program, but rather relate to compensation or retirement plans of the company. Specifically, these shares represent shares delivered in satisfaction of the exercise price and/or tax withholding obligations by holders of stock options who exercised options (granted under TECO Energy’s incentive compensation plans), shares delivered or withheld (under the terms of grants under TECO Energy’s incentive compensation plans) to offset tax withholding obligations associated with the vesting of restricted shares and shares purchased by the TECO Energy Group Retirement Savings Plan pursuant to directions from plan participants or dividend reinvestment.

Item 6. EXHIBITS

Exhibits—See index on page 60.

57

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: November 4, 2011	By:	/s/    S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer) (Principal Financial and Accounting Officer)

	TAMPA ELECTRIC COMPANY (Registrant)
Date: November 4, 2011	By:	/s/    S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer) (Principal Financial and Accounting Officer)

58

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 May 4, 2011 (Exhibit 3.1, Form 8-K dated May 4,2011 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 Feb. 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
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)
99.1	Mine Safety Disclosure
101.INS	XBRL Instance Document	*	*
101.SCH	XBRL Taxonomy Extension Schema Document	*	*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	*	*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*	*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document	*	*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	*	*

(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.

** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

59

EX-12.1

Exhibit 12.1

TECO ENERGY, INC.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth TECO Energy’s ratio of earnings to fixed charges for the periods indicated.

	9-months ended Sep. 30, 2011		12-months ended Sep. 30, 2011			Year Ended Dec. 31,
(millions)						2010			2009		2008		2007		2006
Income from continuing operations, before income taxes	$	343.1	$	433.9		$	409.0		$	312.5	$	256.8	$	613.1	$	363.1
Add:
Interest expense		158.3		216.2			237.4			236.5		234.6		270.1		289.1
Deduct:
Income from equity investments, net		0.0		(0.2	)		(6.9	)		4.3		22.8		18.0		3.4
Earnings before taxes and without fixed charges	$	501.4	$	650.3		$	653.3		$	544.7	$	468.6	$	865.2	$	648.8
Interest expense	$	158.3	$	216.2		$	237.4		$	236.5	$	234.6	$	270.1	$	289.1
Total fixed charges	$	158.3	$	216.2		$	237.4		$	236.5	$	234.6	$	270.1	$	289.1
Ratio of earnings to fixed charges		3.17x		3.01x			2.75x			2.30x		2.00x		3.20x		2.24x

For the purposes of calculating these ratios, earnings consist of income from continuing operations before income taxes, income or loss from equity investments (net of distributions) and fixed charges. Fixed charges consist of interest expense on indebtedness, amortization of debt premium and an estimate of the interest component of rentals. Interest expense includes total interest expense, excluding AFUDC, and an estimate of the interest component of rentals. TECO Energy, Inc. does not have any preferred stock outstanding, and there were no preferred stock dividends paid or accrued during the periods presented.

EX-12.2

Exhibit 12.2

TAMPA ELECTRIC COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth Tampa Electric Company’s ratio of earnings to fixed charges for the periods indicated.

	9-months ended Sep. 30, 2011		12-months ended Sep. 30, 2011		Year Ended Dec. 31,
(millions)					2010		2009		2008		2007		2006
Income from continuing operations, before income tax	$	310.6	$	388.5	$	386.6	$	303.7	$	261.9	$	278.4	$	264.7
Interest expense		106.7		142.7		143.9		141.2		135.8		131.4		124.9
Earnings before taxes and without fixed charges	$	417.3	$	531.2	$	530.5	$	444.9	$	397.7	$	409.8	$	389.6
Interest expense	$	106.7	$	142.7	$	143.9	$	141.2	$	135.8	$	131.4	$	124.9
Total fixed charges	$	106.7	$	142.7	$	143.9	$	141.2	$	135.8	$	131.4	$	124.9
Ratio of earnings to fixed charges		3.91x		3.72x		3.69x		3.15x		2.93x		3.12x		3.12x

For the purposes of calculating these ratios, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges consist of interest expense on indebtedness, amortization of debt premium and an estimate of the interest component of rentals. Interest expense includes total interest expense, excluding AFUDC, and an estimate of the interest component of rentals.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, John B. Ramil, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TECO Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2011	/s/    J. B. RAMIL
		J. B. RAMIL
		President and Chief Executive Officer     (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TECO Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2011	/s/    S.W. CALLAHAN
		S.W. CALLAHAN
		Senior Vice President-Finance and Accounting     and Chief Financial Officer     (Chief Accounting Officer)     (Principal Financial and Accounting Officer)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, John B. Ramil, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2011	/s/    J. B. RAMIL
		J. B. RAMIL
		Chief Executive Officer     (Principal Executive Officer)

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 4, 2011	/s/    S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting     and Chief Financial Officer     (Chief Accounting Officer)     (Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

TECO ENERGY, INC

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of TECO Energy, Inc. (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended September 30, 2011 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 4, 2011	/s/    J. B. RAMIL
		J. B. RAMIL
		President and Chief Executive Officer     (Principal Executive Officer)
Date: November 4, 2011	/s/    S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and     Accounting and Chief Financial Officer     (Chief Accounting Officer)     (Principal Financial and Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-Q and shall not be considered filed as part of the Form 10-Q.

EX-32.2

Exhibit 32.2

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended September 30, 2011 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 4, 2011	/s/    J. B. RAMIL
		J. B. RAMIL
		Chief Executive Officer     (Principal Executive Officer)
Date: November 4, 2011	/s/    S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting     and Chief Financial Officer     (Chief Accounting Officer)     (Principal Financial and Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-Q and shall not be considered filed as part of the Form 10-Q.

EX-99.1

Exhibit 99.1

MINE SAFETY DISCLOSURE

The following disclosures are provided pursuant to the Dodd-Frank Act, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate coal mines regulated under the U.S. Federal Mine Safety and Health Act of 1977 (the Mine Act). Under the Dodd-Frank Act, the SEC is authorized to issue rules and regulations to carry out the purposes of these provisions and has issued its proposed rules on the scope and application of the disclosure requirements. While the company believes the following disclosures meet the requirements of the Dodd-Frank Act, it is possible that any final rules by the SEC will require disclosures to be presented in a form that differs from the following.

Mine Safety Information. Whenever the Mine Safety and Health Administration (MSHA) believes that a violation of the Mine Act, any health or safety standard, or any regulation has occurred, it may issue a citation which describes the violation and fixes a time within which the operator must abate the violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until hazards are corrected. Whenever MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the violation, that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, are often reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned to that mine.

Additional information follows about MSHA references used in the table below.

• Section 104(a) Significant and Substantial Citations: The total number of citations received from MSHA under section 104(a) of the Mine Act, for violations of health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard if left unabated.

• Section 104(b) Orders: The total number of orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.

• Section 104(d) Citations and Orders: The total number of citations and orders issued by MSHA under section 104(d) of the Mine Act for unwarrantable failure to comply with mandatory health or safety standards.

• Section 110(b)(2) Violations: The total number of flagrant violations issued by MSHA under section 110 (b)(2) of the Mine Act.

• Section 107(a) Orders: The total number of orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an imminent danger existed and resulted in orders of immediate withdrawal from the area of the mine affected by the condition.

Pattern or Potential Pattern of Violations. During the nine months ended Sep. 30, 2011, none of the mines operated by TECO Coal received written notice from MSHA of (a) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or (b) the potential to have such a pattern.

Pending Legal Actions. The Federal Mine Safety and Health Review Commission (the Commission) is an independent adjudicative agency that provides administrative trial and appellate review of legal disputes arising under the Mine Act. These cases may involve, among other questions, challenges by operators to citations, orders and penalties they have received from MSHA, or complaints of discrimination by miners under Section 105 of the Mine Act. Each legal action is assigned a docket number by the Commission and may have as its subject matter one or more citations, orders, penalties or complaints.

The following is a brief description of the types of legal actions that may be brought before the Commission.

Exhibit 99.1

• Contests of Citations and Orders – A contest proceeding may be filed with the Commission by operators, miners or miners’ representatives to challenge the issuance of a citation or order issued by MSHA.

• Contests of Proposed Penalties (Petitions for Assessment of Penalties) – A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the violation contained in a citation or order.

• Complaints for Compensation – A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders.

• Complaints of Discharge, Discrimination or Interference – A discrimination proceeding is a case that involves a miner’s allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint.

• Temporary Reinstatement Proceedings – Temporary reinstatement proceedings involve cases in which a miner has filed a complaint with MSHA stating he or she has suffered discrimination and the miner has lost his or her position.

• Emergency Response Plan (ERP) Dispute Proceedings – ERP dispute proceedings are cases brought before the Commission when an operator is issued a citation because it has not agreed to include a certain provision in its ERP.

Exhibit 99.1

	For the three months ended Sep. 30, 2011(1)
Mine ID #	Section 104(a) Citations (2)		Section 104(b) Orders		Section 104(d) Citations and Orders		Section 110(b)(2) Violations		Section 107(a) Orders		Proposed MSHA Assessments (in thousands) (3)		Fatalities
Clintwood Elkhorn
15-16734		0		0		0		0		0	$	0.0		0
15-18524		0		0		0		0		0		0.0		0
15-19111		0		0		0		0		0		0.0		0
15-19396		0		0		0		0		0		0.0		0
40-07199		4		0		0		0		0		0.0		0
44-03010		6		0		0		0		0		3.0		0
44-07108		0		0		0		0		0		0.0		0
Mine Complex Totals		10		0		0		0		0	$	3.0		0
Perry County
15-05485		12		0		0		0		0	$	14.0		0
15-18565		8		0		0		0		0		6.0		0
15-18662		47		0		0		0		0		85.0		0
15-19015		29		0		0		0		0		30.0		0
15-19364		0		0		0		0		0		0.0		0
Mine Complex Totals		96		0		0		0		0	$	135.0		0
Premier Elkhorn
15-16470		1		0		0		0		0	$	0.0		0
15-17360		0		0		0		0		0		0.0		0
15-18784		3		0		0		0		0		0.0		0
15-18823		2		0		0		0		0		0.0		0
15-18946		3		0		0		0		0		1.0		0
15-19411		0		0		0		0		0		0.0		0
15-19590		0		0		0		0		0		0.0		0
15-19622		0		0		0		0		0		0.0		0
Mine Complex Totals		9		0		0		0		0	$	1.0		0
Grand Totals		115		0		0		0		0	$	139.0		0

Exhibit 99.1

	For the nine months ended Sep. 30, 2011(1)
Mine ID #	Section 104(a) Citations (4)		Section 104(b) Orders		Section 104(d) Citations and Orders		Section 110(b)(2) Violations		Section 107(a) Orders		Proposed MSHA Assessments (in thousands) (3)		Fatalities		Pending Legal Actions (6)
Clintwood Elkhorn
15-16734		6		0		3		0		0	$	174.0		0		39
15-18524		0		0		0		0		0		0.0		0		0
15-19111		0		0		0		0		0		0.0		0		0
15-19396		3		0		0		0		0		3.0		0		0
40-07199		8		0		0		0		0		14.0		0		12
44-03010		20		0		0		0		0		10.0		0		16
44-07108		11		0		0		0		0		8.0		0		6
Mine Complex Totals		48		0		3		0		0		$209.0		0		73
Perry County
15-05485		58		0		0		0		0	$	44.0		0		32
15-18565		48		0		2		0		0		76.0		0		28
15-18662		123		0		2		0		0		265.0		0		141
15-19015		98		1		3		0		0		172.0		0		116
15-19364		1		0		0		0		0		1.0		0		3
Mine Complex Totals		328		1		7		0		0		$558.0		0		320
Premier Elkhorn
15-16470		3		0		0		0		0	$	4.0		0		19
15-17360		0		0		0		0		0		1.0		0		0
15-18370 (5)		0		0		0		0		0		0.0		0		0
15-18784		4		0		0		0		0		2.0		0		24
15-18823		7		0		0		0		0		4.0		0		6
15-18946		4		0		0		0		0		2.0		0		11
15-19411		1		0		0		0		0		1.0		0		0
15-19590		0		0		0		0		0		0.0		0		0
15-19622		0		0		0		0		0		0.0		0		0
Mine Complex Totals		19		0		0		0		0		$14.0		0		60
Grand Totals		395		1		10		0		0	$	781.0		0		453

Exhibit 99.1

1) Based on data taken from the MSHA Data Retrieval System as of Oct. 12, 2011.

2) 16 of the Section 104(a) Significant and Substantial Citations were issued to third-party service providers at TECO Coal sites. A number of the remaining Citations are in the process of being contested.

3) The proposed assessment figures reported herein include amounts assessed to third-party service providers receiving Section 104(a) citations at TECO Coal sites.

4) 48 of the Section 104(a) Significant and Substantial Citations were issued to third-party service providers at TECO Coal sites. A number of the remaining Citations are in the process of being contested.

5) Mine I.D. #15-18370 was closed in the ordinary course on Aug. 15, 2008.

6) Any pending legal action before the Federal Mine Safety and Health Review Commission involving such mine, including actions that were initiated prior to the nine month period ended Sep. 30, 2011. All such actions were initiated by a TECO Coal mine to contest citations, orders or proposed assessments issued by MSHA involving such mines.

XML

Segment Information (Narrative) (Details)	6 Months Ended		9 Months Ended
	Dec. 31, 2010	Jun. 30, 2010	Sep. 30, 2011
Segment Information [Abstract]
Internally allocated interest costs, pre tax rate	6.50%	7.15%	6.25%
Capital structure assumption, debt portion			50
Capital structure assumption, equity portion			50

XML

Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Millions, except Per Share data	Sep. 30, 2011	Dec. 31, 2010
Receivables, allowance for uncollectibles	$ 4.5	$ 4.5
Common equity, shares authorized	400.0	400.0
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	215.8	214.9
Tampa Electric Co [Member]
Receivables, allowance for uncollectibles	$ 3.2	$ 3.2

XML

Consolidated Condensed Statements Of Income (USD $) In Millions, except Per Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Revenues
Regulated electric and gas	$ 685.5		$ 707.4		$ 1,929.1		$ 2,079.1
Unregulated	225.9		194.4		664.1		633.8
Total revenues	911.4		901.8		2,593.2		2,712.9
Expenses
Fuel	226.3		224.5		565.4		573.9
Purchased power	32.1		45.2		103.2		151.5
Cost of natural gas sold	41.5		61.0		177.6		236.4
Other	82.2		96.1		242.6		280.5
Operation other expense
Mining related costs	132.3		119.9		387.0		375.1
Guatemalan power generation	22.1		15.6		64.9		48.5
Other	2.1		1.9		5.2		5.0
Maintenance	44.0		44.6		141.3		137.1
Depreciation and amortization	82.4		78.8		243.4		233.7
Recoveries from previously impaired assets	0.0		(2.9)		0		(2.9)
Restructuring charges					0		1.5
Taxes, other than income	57.0		57.4		171.2		174.1
Total expenses	722.0		742.1		2,101.8		2,214.4
Income from operations	189.4		159.7		491.4		498.5
Other income (expense)
Allowance for other funds used during construction	0.2		0.3		0.8		1.6
Other income	2.6		10.4		5.6		16.0
(Loss) on debt extinguishment					0		(33.0)
Income from equity investments	0		3.6		0		10.5
Total other income (expense)	2.8		14.3		6.4		(4.9)
Interest charges
Interest expense	50.8		57.5		154.9		175.8
Allowance for borrowed funds used during construction	(0.1)		(0.1)		(0.4)		(0.9)
Total interest charges	50.7	[1]	57.4	[1]	154.5	[1]	174.9	[1]
Income before provision for income taxes	141.5		116.6		343.3		318.7
Provision for income taxes	51.2		65.5		123.7		135.9
Net income	90.3		51.1		219.6		182.8
Less: Net income attributable to noncontrolling interest	(0.1)		(0.1)		(0.2)		(0.5)
Net income	$ 90.2		$ 51.0		$ 219.4		$ 182.3
Average common shares outstanding - Basic	213.8		212.8		213.5		212.5
Average common shares outstanding - Diluted	215.3		215.1		215.1		214.6
Earnings per share - Basic	$ 0.42		$ 0.24		$ 1.02		$ 0.85
Earnings per share - Diluted	$ 0.42		$ 0.24		$ 1.02		$ 0.85
Dividends paid per common share outstanding	$ 0.215		$ 0.205		$ 0.635		$ 0.610

[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 January 2011 through September 2011 were at a pretax rate of 6.25%, for July 2010 through December 2010 were at a pretax rate of 6.50%, and for January 2010 through June 2010 were at a pretax rate of 7.15% based on an average of each subsidiary's equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

XML

Accounting For Derivative Instruments And Hedging Activities (Derivatives Designated As Cash Flow Hedges) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Current assets	$ 1.3	[1]	$ 2.7	[1]
Long-term assets	0.2	[1]	0.2	[1]
Total assets	1.5	[1]	2.9	[1]
Current liabilities	29.5	[1]	27.2	[1]
Long-term liabilities	6.0	[1]	2.6	[1]
Total liabilities	35.5	[1]	29.8	[1]
Tampa Electric Co [Member] | Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0		1.1
Long-term assets	0		0
Total assets	0		1.1
Current liabilities	29.5		27.2
Long-term liabilities	4.5		2.6
Total liabilities	34.0		29.8
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0		1.1
Long-term assets	0		0
Total assets	0		1.1
Current liabilities	29.5		27.2
Long-term liabilities	4.5		2.6
Total liabilities	34.0		29.8
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	1.3		1.6
Long-term assets	0.2		0.2
Total assets	1.5		1.8
Current liabilities	0		0
Long-term liabilities	1.5		0
Total liabilities	1.5		0
Tampa Electric Co [Member]
Derivatives, Fair Value [Line Items]
Current assets	0		1.1
Current liabilities	29.5		27.2
Long-term liabilities	$ 4.5		$ 2.6

[1] Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

XML

Variable Interest Entities

9 Months Ended

Sep. 30, 2011

Variable Interest Entities

15. Variable Interest Entities

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE's primary beneficiary. Under the amended standard, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric Company has entered into multiple power purchase agreements (PPAs) with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 mega-watts (MW) to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance; regulatory; credit; commodity/fuel; and energy market risk. Tampa Electric Company has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric Company is not required to consolidate any of these entities. Tampa Electric Company purchased $22.9 million and $64.9 million pursuant to PPAs for the three and nine months ended Sep. 30, 2011, respectively, and $29.7 million and $90.6 million for the three and nine months ended Sep. 30, 2010, respectively.

In one instance, Tampa Electric Company's agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, the company is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, the company is unable to determine if this entity is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. The company has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for the company is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. Under this PPA, Tampa Electric Company purchased $12.0 million and $24.9 million for the three and nine months ended Sep. 30, 2011, respectively, and $14.7 million and $45.0 million for the three and nine months ended Sep. 30, 2010, respectively.

Tampa Electric Company does not provide any material financial or other support to any of the VIEs it is involved with, nor is it under any obligation to absorb losses associated with these VIEs. In the normal course of business, Tampa Electric Company's involvement with the remaining VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

Tampa Electric Co [Member]

Variable Interest Entities

13. Variable Interest Entities

Effective Jan. 1, 2010, the accounting standards for consolidation of VIEs were amended. The most significant amendment was the determination of a VIE's primary beneficiary. Under the amended standard, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric Company has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 121 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance; regulatory; credit; commodity/fuel; and energy market risk. Tampa Electric Company has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric Company is not required to consolidate any of these entities. Tampa Electric Company purchased $22.9 million and $64.9 million pursuant to PPAs for the three and nine months ended Sep. 30, 2011, respectively, and $29.7 million and $90.6 million for the three and nine months ended Sep. 30, 2010, respectively.

In one instance, Tampa Electric Company's agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, the company is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, Tampa Electric Company is unable to determine if this entity is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. Tampa Electric Company has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for Tampa Electric Company is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. Under this PPA, Tampa Electric Company purchased $12.0 million and $24.9 million for the three and nine months ended Sep. 30, 2011, respectively, and $14.7 million and $45.0 million for the three and nine months ended Sep. 30, 2010, respectively.

Tampa Electric Company does not provide any material financial or other support to any of the VIEs it is involved with, nor is it under any obligation to absorb losses associated with these VIEs. In the normal course of business, Tampa Electric Company's involvement with the remaining VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 31, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	0000350563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Teco Energy Inc [Member]
Entity Common Stock, Shares Outstanding		215,766,935
Tampa Electric Co [Member]
Entity Registrant Name	TAMPA ELECTRIC CO
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

XML

Commitments And Contingencies (Narrative) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Payments for removal costs	$ 3.9
Loss contingency, damages sought, value	110.0
Tampa Electric Co [Member]
Payments for removal costs	3.9
Loss contingency, damages sought, value	110.0
Ultimate financial liability related to superfund sites and former MGP sites	$ 21.3

XML

Regulatory (Tables)

9 Months Ended

Sep. 30, 2011

Schedule Of Regulatory Assets And Regulatory Liabilities

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	64.4	$	66.6
Other:
Cost recovery clauses		38.0		41.9
Postretirement benefit asset		228.9		237.5
Deferred bond refinancing costs (2)		12.2		15.4
Environmental remediation		23.2		23.6
Competitive rate adjustment		3.2		3.3
Other		17.1		16.3
Total other regulatory assets		322.6		338.0
Total regulatory assets		387.0		404.6
Less: Current portion		55.8		62.7
Long-term regulatory assets	$	331.2	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	16.7	$	17.7
Other:
Cost recovery clauses		70.7		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.5		37.4
Deferred gain on property sales (3)		5.4		6.3
Provision for stipulation and other (4)		0.8		9.8
Accumulated reserve-cost of removal		576.7		572.2
Total other regulatory liabilities		716.3		723.1
Total regulatory liabilities		733.0		740.8
Less: Current portion		95.5		110.0
Long-term regulatory liabilities	$	637.5	$	630.8

(1) Primarily related to plant life and derivative positions.

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

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

(4) Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS's 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.

Regulatory Assets And Related Recovery Periods

Regulatory assets

(millions)	Sep. 30, 2011		Dec 31, 2010
Clause recoverable (1)	$	41.2	$	45.2
Components of rate base (2)		240.9		248.1
Regulatory tax assets (3)		64.4		66.6
Capital structure and other (3)		40.5		44.7
Total	$	387.0	$	404.6

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

(2) Primarily reflects allowed working capital, which is included in rate base and earns 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.

Tampa Electric Co [Member]

Schedule Of Regulatory Assets And Regulatory Liabilities

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	64.4	$	66.6
Other:
Cost recovery clauses		38.0		41.9
Postretirement benefit asset		228.9		237.5
Deferred bond refinancing costs (2)		12.2		15.4
Environmental remediation		23.2		23.6
Competitive rate adjustment		3.2		3.3
Other		17.1		16.3
Total other regulatory assets		322.6		338.0
Total regulatory assets		387.0		404.6
Less: Current portion		55.8		62.7
Long-term regulatory assets	$	331.2	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	16.7	$	17.7
Other:
Cost recovery clauses		70.7		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.5		37.4
Deferred gain on property sales (3)		5.4		6.3
Provision for stipulation and other (4)		0.8		9.8
Accumulated reserve-cost of removal		576.7		572.2
Total other regulatory liabilities		716.3		723.1
Total regulatory liabilities		733.0		740.8
Less: Current portion		95.5		110.0
Long-term regulatory liabilities	$	637.5	$	630.8

(1) Primarily related to plant life and derivative positions.

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

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

(4) Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS's 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.

Regulatory Assets And Related Recovery Periods

Regulatory assets

	Sep. 30,		Dec 31,
(millions)	2011		2010
Clause recoverable (1)	$	41.2	$	45.2
Components of rate base (2)		240.9		248.1
Regulatory tax assets (3)		64.4		66.6
Capital structure and other (3)		40.5		44.7
Total	$	387.0	$	404.6

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

(2) Primarily reflects allowed working capital, which is included in rate base and earns 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.

XML

Earnings Per Share (Details) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Earnings Per Share [Abstract]
Net income	$ 90.3	$ 51.1	$ 219.6	$ 182.8
Less: Income attributable to noncontrolling interest	(0.1)	(0.1)	(0.2)	(0.5)
Less: Amount allocated to nonvested participating shareholders	(0.5)	(0.4)	(1.2)	(1.3)
Net income attributable to TECO Energy available to common shareholders - basic	89.7	50.6	218.2	181.0
Average shares outstanding common	213.8	212.8	213.5	212.5
Basic earnings per share attributable to TECO Energy available to common shareholders	$ 0.42	$ 0.24	$ 1.02	$ 0.85
Net income attributable to TECO Energy available to common shareholders - diluted	89.7	50.6	218.2	181.0
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net	$ 1.5	$ 2.3	$ 1.6	$ 2.1
Adjusted average shares outstanding common - diluted	215.3	215.1	215.1	214.6
Earnings per share - Diluted	$ 0.42	$ 0.24	$ 1.02	$ 0.85
Anti-dilutive shares	1.4	2.5	1.8	4.3

XML

Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes

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 2009 consolidated federal income tax return during 2010. The U.S. federal statute of limitations remains open for the year 2008 and onward. Years 2010 and 2011 are currently being examined by the IRS under its Compliance Assurance Program. 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 2011. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2007 and forward.

During the second quarter of 2010, the company finalized the settlements of certain state items that were under appeal. As a result, the company recorded a $1.6 million after-tax benefit, excluding interest. During the nine months ended Sep. 30, 2010, the company recorded a total of $4.0 million after-tax benefit, excluding interest, for these state items.

The company recognizes interest and penalties associated with uncertain tax positions in "Operation other expense-Other" on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. For the nine months ended Sep. 30, 2011 and Sep. 30, 2010, the company recorded $0.2 million of interest charges and a net $1.2 million of interest income, respectively. No amounts were recorded for penalties for the nine month periods ended Sep. 30, 2011 or 2010.

The effective tax rate decreased to 36.18% for the three month period ended Sep. 30, 2011 from 56.17% for the same period in 2010. The three month period ended Sep. 30, 2010 included $24.9 million of U.S. deferred taxes recognized on DECA II undistributed earnings which were no longer considered indefinitely reinvested. The effective tax rate decreased to 36.02% for the nine months ended Sep. 30, 2011 from 42.63% for the same period in 2010. The nine month period ended Sep. 30, 2010 also included the $24.9 million mentioned above and a $5.9 million foreign tax credit valuation allowance.

Tampa Electric Co [Member]

Income Taxes

4. Income Taxes

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company's income tax expense is based upon a separate return computation. Tampa Electric Company's effective tax rates for the nine months ended Sep. 30, 2011 and Sep. 30, 2010 differ from the statutory rate principally due to state income taxes, domestic activity production deduction and the equity portion of Allowance for Funds Used During Construction.

The IRS concluded its examination of TECO Energy's consolidated federal income tax return for the year 2009 during 2010. The U.S. federal statute of limitations remains open for the year 2008 and onward. Years 2010 and 2011 are currently under examination by the IRS under its Compliance Assurance Program. 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 2011. Florida's statute of limitations is three 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 Florida's tax authorities include 2008 and onward.

XML

Employee Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Employee Postretirement Benefits [Abstract]

Schedule Of Periodic Expense For Pension And Other Postretirement Benefits

		$000,000			$000,000			$000,000		$000,000
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sep. 30,	2011			2010			2011		2010
Components of net periodic benefit expense
Service cost	$	4.0		$	4.0		$	0.5	$	0.8
Interest cost on projected benefit obligations		7.7			8.2			2.8		2.8
Expected return on assets		(9.6	)		(9.0	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.5		0.5
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.2
Actuarial loss		2.8			3.2			0.1		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	4.8		$	6.3		$	4.1	$	4.3
Nine months ended Sep. 30,
Components of net periodic benefit expense
Service cost	$	12.0		$	12.1		$	1.6	$	2.4
Interest cost on projected benefit obligations		23.2			24.9			8.3		8.2
Expected return on assets		(28.8	)		(27.2	)		0.0		0.0
Amortization of:
Transition obligation		(0.3	)		0.0			1.7		1.7
Prior service (benefit) cost		8.4			(0.3	)		0.6		0.6
Actuarial loss		0.0			9.4			0.1		0.0
Pension expense		14.5			18.9			12.3		12.9
Settlement cost		0.0			1.6			0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	14.5		$	20.5		$	12.3	$	12.9

XML

Short-Term Debt (Credit Facilities) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Short-term Debt [Line Items]
Credit Facilities	$ 675.0		$ 675.0
Borrowings Outstanding	0	[1]	12.0
Letters of Credit Outstanding	0.7		7.4
Credit facility maturity date	May 9, 2012
Teco Energy Inc [Member] | 5 Year Facility [Member]
Short-term Debt [Line Items]
Credit Facilities	200.0	[2],[3]	200.0	[2],[3]
Borrowings Outstanding	0	[1],[2],[3]	0	[2],[3]
Letters of Credit Outstanding	0	[2],[3]	6.7	[2],[3]
Tampa Electric Co [Member] | 5 Year Facility [Member]
Short-term Debt [Line Items]
Credit Facilities	325.0	[3],[4]	325.0	[3],[4]
Borrowings Outstanding	0	[1],[3],[4]	5.0	[3],[4]
Letters of Credit Outstanding	0.7	[3],[4]	0.7	[3],[4]
Tampa Electric Co [Member] | 1 Year Accounts Receivable Facility [Member]
Short-term Debt [Line Items]
Credit Facilities	150.0		150.0
Borrowings Outstanding	0	[1]	7.0
Letters of Credit Outstanding	0		0
Tampa Electric Co [Member]
Short-term Debt [Line Items]
Credit Facilities	475.0		475.0
Borrowings Outstanding	0	[1]	12.0
Letters of Credit Outstanding	$ 0.7		$ 0.7
Credit facility maturity date	May 9, 2012

[1] Borrowings outstanding are reported as notes payable.

[2] TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

[3] This 5-year facility matures May 9, 2012. See Note 16 for information on an amendment to this facility.

[4] This 5-year facility matures May 9, 2012. See Note 14 for information on an amendment to this facility.

XML

Regulatory (Regulatory Assets And Related Recovery Periods) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	$ 387.0		$ 404.6
Clause Recoverable [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	41.2	[1]	45.2	[1]
Tampa Electric Co [Member] | Clause Recoverable [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	41.2	[1]	45.2	[1]
Components Of Rate Base [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	240.9	[2]	248.1	[2]
Tampa Electric Co [Member] | Components Of Rate Base [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	240.9	[2]	248.1	[2]
Regulatory Tax Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	64.4	[3]	66.6	[3]
Tampa Electric Co [Member] | Regulatory Tax Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	64.4	[4]	66.6	[4]
Capital Structure And Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	40.5	[3]	44.7	[3]
Tampa Electric Co [Member] | Capital Structure And Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	40.5	[4]	44.7	[4]
Tampa Electric Co [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	$ 387.0		$ 404.6

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

[2] Primarily reflects allowed working capital, which is included in rate base and earns 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.

[4] "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.

XML

Summary Of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2011

Principles Of Consolidation And Basis Of Presentation

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 (VIEs) for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Effective Jan. 1, 2010, amended accounting standards on consolidation resulted in the reconsolidation of two projects in Guatemala.

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 its subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011.

Use Of Estimates

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

Revenues

As of Sep. 30, 2011 and Dec. 31, 2010, unbilled revenues of $58.1 million and $65.5 million, respectively, are included in the "Receivables" line item on the Consolidated Condensed Balance Sheets.

Accounting For Franchise Fees And Gross Receipts

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 Florida Public Service Commission (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 $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.0 million and $90.0 million for the three and nine months ended Sep. 30, 2010. 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 amounts totaled $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.1 million and $89.9 million for the three and nine months ended Sep. 30, 2010.

Purchased Power

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 $32.1 million and $103.2 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $45.2 million and $151.5 million for the three and nine months ended Sep. 30, 2010. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through FPSC-approved cost recovery clauses.

Cash Flows Related To Derivatives And Hedging Activities

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 which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas swaps, the cash inflows and outflows are also 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.

Tampa Electric Co [Member]

Principles Of Consolidation And Basis Of Presentation

Principles of Consolidation and Basis of Presentation

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, Tampa Electric Company is comprised of the Electric division, generally referred to as Tampa Electric, the Natural Gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. Tampa Electric Company is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. For the periods presented, no VIEs have been consolidated (see Note 13).

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 its subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011.

Use Of Estimates

The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates. The year-end consolidated 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

Revenues

As of Sep. 30, 2011 and Dec. 31, 2010, unbilled revenues of $58.1 million and $65.5 million, respectively, are included in the "Receivables" line item on the Consolidated Condensed Balance Sheets.

Accounting For Franchise Fees And Gross Receipts

Accounting for Franchise Fees and Gross Receipts

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 $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.0 million and $90.0 million for the three and nine months ended Sep. 30, 2010. 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 amounts totaled $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.1 million and $89.9 million for the three and nine months ended Sep. 30, 2010.

Purchased Power

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 $32.1 million and $103.2 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $45.2 million and $151.5 million for the three and nine months ended Sep. 30, 2010. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through FPSC-approved cost recovery clauses.

Cash Flows Related To Derivatives And Hedging Activities

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.

XML

Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

9. Earnings Per Share

Earnings Per Share

	Three months ended Sep. 30,						Nine months ended Sep. 30,
(millions, except per share amounts)	2011			2010			2011			2010
Basic earnings per share
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Less: Income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Less: Amount allocated to nonvested participating shareholders		(0.5	)		(0.4	)		(1.2	)		(1.3	)
Net income attributable to TECO Energy available to common shareholders—basic	$	89.7		$	50.6		$	218.2		$	181.0
Average shares outstanding-common		213.8			212.8			213.5			212.5
Basic earnings per share attributable to TECO Energy available to common shareholders	$	0.42		$	0.24		$	1.02		$	0.85
Diluted earnings per share
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Less: Income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Less: Amount allocated to nonvested participating shareholders		(0.5	)		(0.4	)		(1.2	)		(1.3	)
Net income attributable to TECO Energy available to common shareholders—diluted	$	89.7		$	50.6		$	218.2		$	181.0
Average shares outstanding-common		213.8			212.8			213.5			212.5
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		1.5			2.3			1.6			2.1
Adjusted average shares outstanding common—diluted		215.3			215.1			215.1			214.6
Diluted earnings per share attributable to TECO Energy available to common shareholders	$	0.42		$	0.24		$	1.02		$	0.85
Anti-dilutive shares		1.4			2.5			1.8			4.3

XML

Consolidated Condensed Statements Of Income And Comprehensive Income (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Revenues
Total revenues	$ 911.4		$ 901.8		$ 2,593.2		$ 2,712.9
Operations
Fuel	226.3		224.5		565.4		573.9
Purchased power	32.1		45.2		103.2		151.5
Cost of natural gas sold	41.5		61.0		177.6		236.4
Other	82.2		96.1		242.6		280.5
Maintenance	44.0		44.6		141.3		137.1
Depreciation	82.4		78.8		243.4		233.7
Taxes, other than income	57.0		57.4		171.2		174.1
Total expenses	722.0		742.1		2,101.8		2,214.4
Income from operations	189.4		159.7		491.4		498.5
Other income (expense)
Allowance for other funds used during construction	0.2		0.3		0.8		1.6
Total other income (expense)	2.8		14.3		6.4		(4.9)
Interest charges
Interest on long-term debt	50.8		57.5		154.9		175.8
Allowance for borrowed funds used during construction	(0.1)		(0.1)		(0.4)		(0.9)
Total interest charges	50.7	[1]	57.4	[1]	154.5	[1]	174.9	[1]
Net income	90.2		51.0		219.4		182.3
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges	(1.8)		1.4		(0.9)		1.8
Total other comprehensive income, Net	(1.4)		1.8		0.3		5.4
Comprehensive income	88.8		52.8		219.7		187.7
Tampa Electric Co [Member]
Revenues
Electric	591.8		593.5		1,571.2		1,671.6
Gas	93.8		114.1		358.5		408.2
Total revenues	685.6		707.6		1,929.7		2,079.8
Operations
Fuel	226.3		224.5		565.4		573.9
Purchased power	32.1		45.2		103.2		151.5
Cost of natural gas sold	41.4		61.0		177.6		236.4
Other	82.0		96.0		242.2		280.2
Maintenance	25.6		28.7		88.7		90.3
Depreciation	68.4		65.9		202.4		195.3
Taxes, federal and state	50.1		38.9		119.6		114.7
Taxes, other than income	45.9		47.4		137.4		141.9
Total expenses	571.8		607.6		1,636.5		1,784.2
Income from operations	113.8		100.0		293.2		295.6
Other income (expense)
Allowance for other funds used during construction	0.2		0.3		0.8		1.6
Taxes, non-utility federal and state	(0.3)		(0.3)		(0.7)		(0.6)
Other income, net	0.8		0.9		2.0		2.5
Total other income (expense)	0.7		0.9		2.1		3.5
Interest charges
Interest on long-term debt	31.9		32.6		96.7		98.1
Other interest	2.9		2.8		8.6		8.4
Allowance for borrowed funds used during construction	(0.1)		(0.1)		(0.4)		(0.9)
Total interest charges	34.7		35.3		104.9		105.6
Net income	79.8		65.6		190.4		193.5
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges	0.2		0.2		0.5		0.6
Total other comprehensive income, Net	0.2		0.2		0.5		0.6
Comprehensive income	$ 80.0		$ 65.8		$ 190.9		$ 194.1

[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 January 2011 through September 2011 were at a pretax rate of 6.25%, for July 2010 through December 2010 were at a pretax rate of 6.50%, and for January 2010 through June 2010 were at a pretax rate of 7.15% based on an average of each subsidiary's equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

XML

Summary Of Significant Accounting Policies (Details) (USD $) In Millions	3 Months Ended		9 Months Ended						3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Unbilled Revenues [Member]	Dec. 31, 2010 Unbilled Revenues [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Unbilled Revenues [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Unbilled Revenues [Member]	Sep. 30, 2011 Franchise Fees And Gross Receipts [Member]	Sep. 30, 2010 Franchise Fees And Gross Receipts [Member]	Sep. 30, 2011 Franchise Fees And Gross Receipts [Member]	Sep. 30, 2010 Franchise Fees And Gross Receipts [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Franchise Fees And Gross Receipts [Member]	Sep. 30, 2010 Tampa Electric Co [Member] Franchise Fees And Gross Receipts [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Franchise Fees And Gross Receipts [Member]	Sep. 30, 2010 Tampa Electric Co [Member] Franchise Fees And Gross Receipts [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Sep. 30, 2010 Tampa Electric Co [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Sep. 30, 2010 Tampa Electric Co [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues					$ 58.1	$ 65.5	$ 58.1	$ 65.5
Franchise fees and gross receipts taxes	28.8	31.0	84.3	90.0													28.8	31.0	84.3	90.0
Taxes, other than income	57.0	57.4	171.2	174.1					28.8	31.1	84.3	89.9	28.8	31.1	84.3	89.9	45.9	47.4	137.4	141.9
Purchased power	$ 32.1	$ 45.2	$ 103.2	$ 151.5													$ 32.1	$ 45.2	$ 103.2	$ 151.5

XML

Short-Term Debt

9 Months Ended

Sep. 30, 2011

Short-Term Debt

6. Short-Term Debt

At Sep. 30, 2011 and Dec. 31, 2010, the following credit facilities and related borrowings existed:

Credit Facilities

	Sep. 30, 2011						Dec. 31, 2010
	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
(millions)
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	5.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		7.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		6.7
Total	$	675.0	$	0.0	$	0.7	$	675.0	$	12.0	$	7.4

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures May 9, 2012. See Note 16 for information on an amendment to this facility.

(3) 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 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2010 was 0.64%.

Tampa Electric Company Accounts Receivable Facility

On Feb. 18, 2011, Tampa Electric Company and TEC Receivables Corporation (TRC), a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Omnibus Amendment No. 9 to the Loan and Servicing Agreement with certain lenders named therein and Citicorp North America, Inc. as Program Agent. The amendment (i) extends the maturity date to Feb. 17, 2012, (ii) provides that TRC will pay program and liquidity fees, which will total 70 basis points, (iii) provides that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company's option, either Citibank's prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank offered rate (if available) plus a margin and (iv) makes other technical changes.

Tampa Electric Co [Member]

Short-Term Debt

6. Short-Term Debt

At Sep. 30, 2011 and Dec. 31, 2010, the following credit facilities and related borrowings existed:

	Sep. 30, 2011						Dec. 31, 2010
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	5.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		7.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	12.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures May 9, 2012. See Note 14 for information on an amendment to this facility.

These credit facilities require commitment fees ranging from 7.0 to 35.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2010 was 0.64%.

Tampa Electric Company Accounts Receivable Facility

On Feb. 18, 2011, Tampa Electric Company and TRC, a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Omnibus Amendment No. 9 to the Loan and Servicing Agreement with certain lenders named therein and Citicorp North America, Inc. as Program Agent. The amendment (i) extends the maturity date to Feb. 17, 2012, (ii) provides that TRC will pay program and liquidity fees, which will total 70 basis points, (iii) provides that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at Tampa Electric Company's option, either Citibank's prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank offered rate (if available) plus a margin and (iv) makes other technical changes.

XML

Segment Information

9 Months Ended

Sep. 30, 2011

Segment Information

11. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary's contribution of revenues, net income and total assets, as required by the accounting guidance for 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.

Segment Information ⁽¹⁾

		$1,570.6		$1,570.6		$1,570.6		$1,570.6			$1,570.6			$1,570.6
(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala			Other & Eliminations			TECO Energy, Inc.
2011
Revenues—external	$	591.6	$	93.9	$	190.5	$	33.6		$	1.8		$	911.4
Sales to affiliates		0.3		0.3		0.0		0.0			(0.6	)		0.0
Total revenues		591.9		94.2		190.5		33.6			1.2			911.4
Depreciation		56.2		12.2		11.8		1.8			0.4			82.4
Total interest charges(1)		30.3		4.4		1.7		1.9			12.4			50.7
Internally allocated interest (1)		0.0		0.0		1.7		1.5			(3.2	)		0.0
Provision (benefit) for taxes		47.4		3.0		4.1		2.4			(5.7	)		51.2
Net income (loss) attributable to TECO Energy	$	75.0	$	4.8	$	14.1	$	4.5		$	(8.2	)	$	90.2
2010
Revenues—external	$	593.3	$	114.1	$	165.3	$	29.0		$	0.1		$	901.8
Sales to affiliates		0.3		2.5		0.0		0.0			(2.8	)		0.0
Total revenues		593.6		116.6		165.3		29.0			(2.7	)		901.8
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		4.1			(0.5	)		3.6
Depreciation		54.4		11.5		11.0		1.8			0.1			78.8
Total interest charges(1)		30.7		4.6		1.6		4.0			16.5			57.4
Internally allocated interest (1)		0.0		0.0		1.5		3.0			(4.5	)		0.0
Provision (benefit) for taxes		36.8		2.4		2.2		29.1			(5.0	)		65.5
Net income (loss) attributable to TECO Energy	$	61.9	$	3.7	$	8.3	$	(12.6	)	$	(10.3	)	$	51.0
		$1,570.6		$1,570.6		$1,570.6		$1,570.6			$1,570.6			$1,570.6
(millions) Nine months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala			Other & Eliminations			TECO Energy, Inc.
2011
Revenues—external	$	1,570.6	$	358.5	$	555.5	$	103.3		$	5.3		$	2,593.2
Sales to affiliates		1.0		3.0		0.0		0.0			(4.0	)		0.0
Total revenues		1,571.6		361.5		555.5		103.3			1.3			2,593.2
Depreciation		166.4		36.0		34.4		5.5			1.1			243.4
Total interest charges(1)		91.6		13.3		5.1		5.7			38.8			154.5
Internally allocated interest (1)		0.0		0.0		5.0		4.6			(9.6	)		0.0
Provision (benefit) for taxes		104.3		16.0		10.7		8.5			(15.8	)		123.7
Net income (loss) attributable to TECO Energy	$	165.0	$	25.4	$	38.1	$	16.4		$	(25.5	)	$	219.4
2010
Revenues—external	$	1,670.9	$	408.2	$	537.9	$	95.7		$	0.2		$	2,712.9
Sales to affiliates		1.0		17.4		0.0		0.0			(18.4	)		0.0
Total revenues		1,671.9		425.6		537.9		95.7			(18.2	)		2,712.9
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		12.1			(1.6	)		10.5
Depreciation		161.0		34.3		32.8		5.4			0.2			233.7
Restructuring charges		0.0		0.0		0.0		0.0			1.5			1.5
Total interest charges(1)		91.8		13.8		5.2		13.0			51.1			174.9
Internally allocated interest (1)		0.0		0.0		5.0		9.5			(14.5	)		0.0
Provision (benefit) for taxes		98.4		16.9		9.1		35.9			(24.4	)		135.9
Net income (loss) attributable to TECO Energy	$	166.8	$	26.7	$	45.8	$	8.4		$	(65.4	)	$	182.3

(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy, Inc.
At Sep. 30, 2011
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,924.3	$	879.2	$	352.5	$	266.4	$	(126.5	)	$	7,295.9
At Dec. 31, 2010
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,833.3	$	918.4	$	332.2	$	292.7	$	(182.0	)	$	7,194.6

(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 January 2011 through September 2011 were at a pretax rate of 6.25%, for July 2010 through December 2010 were at a pretax rate of 6.50%, and for January 2010 through June 2010 were at a pretax rate of 7.15% based on an average of each subsidiary's equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

Tampa Electric Co [Member]

Segment Information

9. Segment Information

(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa  Electric Company
2011
Revenues—external	$	591.8	$	93.8	$	0.0		$	685.6
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Total revenues		591.9		94.2		(0.5	)		685.6
Depreciation		56.2		12.2		0.0			68.4
Total interest charges		30.3		4.4		0.0			34.7
Provision for taxes		47.4		3.0		0.0			50.4
Net income		75.0		4.8		0.0			79.8
2010
Revenues—external	$	593.3	$	114.1	$	0.0		$	707.4
Sales to affiliates		0.3		2.5		(2.6	)		0.2
Total revenues		593.6		116.6		(2.6	)		707.6
Depreciation		54.4		11.5		0.0			65.9
Total interest charges		30.7		4.6		0.0			35.3
Provision for taxes		36.8		2.4		0.0			39.2
Net income		61.9		3.7		0.0			65.6
Nine months ended Sep. 30,
2011
Revenues—external	$	1,571.2	$	358.5	$	0.0		$	1,929.7
Sales to affiliates		0.4		3.0		(3.4	)		0.0
Total revenues		1,571.6		361.5		(3.4	)		1,929.7
Depreciation		166.4		36.0		0.0			202.4
Total interest charges		91.6		13.3		0.0			104.9
Provision for taxes		104.3		16.0		0.0			120.3
Net income		165.0		25.4		0.0			190.4
Total assets at Sep. 30, 2011	$	5,691.7	$	840.4	($	5.9	)	$	6,526.2
2010
Revenues—external	$	1,670.9	$	408.2	$	0.0		$	2,079.1
Sales to affiliates		1.0		17.4		(17.7	)		0.7
Total revenues		1,671.9		425.6		(17.7	)		2,079.8
Depreciation		161.0		34.3		0.0			195.3
Total interest charges		91.8		13.8		0.0			105.6
Provision for taxes		98.4		16.9		0.0			115.3
Net income		166.8		26.7		0.0			193.5
Total assets at Dec. 31, 2010	$	5,580.6	$	872.7	($	14.8	)	$	6,438.5

XML

Long-Term Debt

9 Months Ended

Sep. 30, 2011

Long-Term Debt

7. Long-Term Debt

Purchase in Lieu of Redemption of Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On Mar. 1, 2011, Tampa Electric Company purchased in lieu of redemption $75.0 million Polk County Industrial Development Authority (PCIDA) Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA had issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously had been in auction rate mode and had been held by Tampa Electric Company since Mar. 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to Mar. 1, 2011.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $20.0 million Hillsborough County Industrial Development Authority (HCIDA) Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the Mar. 1, 2011 purchase of the PCIDA Bonds, $95.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Sep. 30, 2011 (Held Bonds) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

Redemption of TECO Energy, Inc. 7.20% Notes due 2011

On Apr. 22, 2010, TECO Energy redeemed $100 million aggregate principal amount of its 7.2% Notes due 2011. The redemption price was equal to $1,066.38 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $6.6 million of premiums and fees were expensed, and are included in "Loss on debt extinguishment" on the Consolidated Condensed Statements of Income and as part of the "Cash flows from operating activities" in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sep. 30, 2010.

Redemption of TECO Energy, Inc. Floating Rate Notes due 2010

On Apr. 14, 2010, TECO Energy redeemed all of the outstanding $100 million aggregate principal amount of its Floating Rate Notes due 2010. The redemption price was equal to 100% of the principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date.

TECO Energy, Inc. and TECO Finance, Inc. Tender Offers

On Mar. 22, 2010, TECO Energy and TECO Finance completed debt tender offers which resulted in the purchase of approximately $70.0 million principal amount of TECO Energy notes for cash and approximately $230.0 million principal amount of TECO Finance notes for cash.

The tender offers resulted in the purchase and retirement of approximately:

• $43.0 million principal amount of TECO Energy 7.2% Notes due 2011

• $27.0 million principal amount of TECO Energy 7.0% Notes due 2012

• $156.9 million principal amount of TECO Finance 7.2% Notes due 2011

• $73.1 million principal amount of TECO Finance 7.0% Notes due 2012

In connection with these debt tender transactions, $25.5 million of premiums and fees were expensed, and are included in "Loss on debt extinguishment" on the Consolidated Condensed Statements of Income and as part of the "Cash flows from operating activities" in the Consolidated Condensed Statements of Cash Flows for the nine months ended Sep. 30, 2010. "Loss on debt extinguishment" also includes remaining unamortized debt issue costs of $0.9 million.

Issuance of TECO Finance, Inc. 4.00% Notes due 2016 and 5.15% Notes due 2020

On Mar. 15, 2010, TECO Finance, Inc. (TECO Finance) issued $250.0 million aggregate principal amount of 4.00% Notes due Mar. 15, 2016 and $300.0 million aggregate principal amount of 5.15% Notes due Mar. 15, 2020. The 2016 Notes were priced at 99.594% of the principal amount to yield 4.077% to maturity, and the 2020 Notes were priced at 99.552% of the principal amount to yield 5.208% to maturity. TECO Finance is a wholly-owned subsidiary of TECO Energy whose business activities consist solely of providing funds to TECO Energy for its diversified activities. The TECO Finance notes are fully and unconditionally guaranteed by TECO Energy.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $543.5 million. TECO Finance used these net proceeds to fund the cash purchase of the TECO Energy and TECO Finance notes tendered in March 2010 (see TECO Energy, Inc. and TECO Finance, Inc. Tender Offers below) and to fund the redemptions of the TECO Energy Floating Rate Notes due 2010 and 7.20% Notes due 2011 in April 2010. TECO Finance may redeem some or all 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 sum of 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 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

Reconsolidation of TCAE and CGESJ

Effective Jan. 1, 2010, new accounting standards for consolidations amended the determination of the primary beneficiaries for variable interest entities. As a result of adopting these standards, TECO Guatemala, Inc., a wholly-owned subsidiary of TECO Energy, was determined to be the primary beneficiary of, and therefore required to consolidate, both the Tampa Centro Americana de Electricidad (TCAE) and Central Generadora Eléctrica San José (CGESJ) projects in Guatemala. The consolidation resulted in a net $44.4 million increase of non-recourse debt.

Tampa Electric Co [Member]

Long-Term Debt

7. Long-Term Debt

Purchase in Lieu of Redemption of Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On Mar. 1, 2011, Tampa Electric Company purchased in lieu of redemption $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010 (the PCIDA Bonds). On Nov. 23, 2010, the PCIDA had issued the PCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. Proceeds of the PCIDA Bonds were used to redeem $75.0 million PCIDA Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007, which previously had been in auction rate mode and had been held by Tampa Electric Company since Mar. 26, 2008. The PCIDA Bonds bore interest at the initial term rate of 1.50% per annum from Nov. 23, 2010 to Mar. 1, 2011.

On Mar. 26, 2008, Tampa Electric Company purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the Mar. 1, 2011 purchase of the PCIDA Bonds, $95.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of Tampa Electric Company as of Sep. 30, 2011 (Held Bonds) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

XML

Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Segment Information

Segment Information ⁽¹⁾

		$1,570.6		$1,570.6		$1,570.6		$1,570.6			$1,570.6			$1,570.6
(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala			Other & Eliminations			TECO Energy, Inc.
2011
Revenues—external	$	591.6	$	93.9	$	190.5	$	33.6		$	1.8		$	911.4
Sales to affiliates		0.3		0.3		0.0		0.0			(0.6	)		0.0
Total revenues		591.9		94.2		190.5		33.6			1.2			911.4
Depreciation		56.2		12.2		11.8		1.8			0.4			82.4
Total interest charges(1)		30.3		4.4		1.7		1.9			12.4			50.7
Internally allocated interest (1)		0.0		0.0		1.7		1.5			(3.2	)		0.0
Provision (benefit) for taxes		47.4		3.0		4.1		2.4			(5.7	)		51.2
Net income (loss) attributable to TECO Energy	$	75.0	$	4.8	$	14.1	$	4.5		$	(8.2	)	$	90.2
2010
Revenues—external	$	593.3	$	114.1	$	165.3	$	29.0		$	0.1		$	901.8
Sales to affiliates		0.3		2.5		0.0		0.0			(2.8	)		0.0
Total revenues		593.6		116.6		165.3		29.0			(2.7	)		901.8
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		4.1			(0.5	)		3.6
Depreciation		54.4		11.5		11.0		1.8			0.1			78.8
Total interest charges(1)		30.7		4.6		1.6		4.0			16.5			57.4
Internally allocated interest (1)		0.0		0.0		1.5		3.0			(4.5	)		0.0
Provision (benefit) for taxes		36.8		2.4		2.2		29.1			(5.0	)		65.5
Net income (loss) attributable to TECO Energy	$	61.9	$	3.7	$	8.3	$	(12.6	)	$	(10.3	)	$	51.0
		$1,570.6		$1,570.6		$1,570.6		$1,570.6			$1,570.6			$1,570.6
(millions) Nine months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala			Other & Eliminations			TECO Energy, Inc.
2011
Revenues—external	$	1,570.6	$	358.5	$	555.5	$	103.3		$	5.3		$	2,593.2
Sales to affiliates		1.0		3.0		0.0		0.0			(4.0	)		0.0
Total revenues		1,571.6		361.5		555.5		103.3			1.3			2,593.2
Depreciation		166.4		36.0		34.4		5.5			1.1			243.4
Total interest charges(1)		91.6		13.3		5.1		5.7			38.8			154.5
Internally allocated interest (1)		0.0		0.0		5.0		4.6			(9.6	)		0.0
Provision (benefit) for taxes		104.3		16.0		10.7		8.5			(15.8	)		123.7
Net income (loss) attributable to TECO Energy	$	165.0	$	25.4	$	38.1	$	16.4		$	(25.5	)	$	219.4
2010
Revenues—external	$	1,670.9	$	408.2	$	537.9	$	95.7		$	0.2		$	2,712.9
Sales to affiliates		1.0		17.4		0.0		0.0			(18.4	)		0.0
Total revenues		1,671.9		425.6		537.9		95.7			(18.2	)		2,712.9
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		12.1			(1.6	)		10.5
Depreciation		161.0		34.3		32.8		5.4			0.2			233.7
Restructuring charges		0.0		0.0		0.0		0.0			1.5			1.5
Total interest charges(1)		91.8		13.8		5.2		13.0			51.1			174.9
Internally allocated interest (1)		0.0		0.0		5.0		9.5			(14.5	)		0.0
Provision (benefit) for taxes		98.4		16.9		9.1		35.9			(24.4	)		135.9
Net income (loss) attributable to TECO Energy	$	166.8	$	26.7	$	45.8	$	8.4		$	(65.4	)	$	182.3

(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy, Inc.
At Sep. 30, 2011
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,924.3	$	879.2	$	352.5	$	266.4	$	(126.5	)	$	7,295.9
At Dec. 31, 2010
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0		$	55.4
Total assets	$	5,833.3	$	918.4	$	332.2	$	292.7	$	(182.0	)	$	7,194.6

(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 January 2011 through September 2011 were at a pretax rate of 6.25%, for July 2010 through December 2010 were at a pretax rate of 6.50%, and for January 2010 through June 2010 were at a pretax rate of 7.15% based on an average of each subsidiary's equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

Tampa Electric Co [Member]

Segment Information

(millions) Three months ended Sep. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa  Electric Company
2011
Revenues—external	$	591.8	$	93.8	$	0.0		$	685.6
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Total revenues		591.9		94.2		(0.5	)		685.6
Depreciation		56.2		12.2		0.0			68.4
Total interest charges		30.3		4.4		0.0			34.7
Provision for taxes		47.4		3.0		0.0			50.4
Net income		75.0		4.8		0.0			79.8
2010
Revenues—external	$	593.3	$	114.1	$	0.0		$	707.4
Sales to affiliates		0.3		2.5		(2.6	)		0.2
Total revenues		593.6		116.6		(2.6	)		707.6
Depreciation		54.4		11.5		0.0			65.9
Total interest charges		30.7		4.6		0.0			35.3
Provision for taxes		36.8		2.4		0.0			39.2
Net income		61.9		3.7		0.0			65.6
Nine months ended Sep. 30,
2011
Revenues—external	$	1,571.2	$	358.5	$	0.0		$	1,929.7
Sales to affiliates		0.4		3.0		(3.4	)		0.0
Total revenues		1,571.6		361.5		(3.4	)		1,929.7
Depreciation		166.4		36.0		0.0			202.4
Total interest charges		91.6		13.3		0.0			104.9
Provision for taxes		104.3		16.0		0.0			120.3
Net income		165.0		25.4		0.0			190.4
Total assets at Sep. 30, 2011	$	5,691.7	$	840.4	($	5.9	)	$	6,526.2
2010
Revenues—external	$	1,670.9	$	408.2	$	0.0		$	2,079.1
Sales to affiliates		1.0		17.4		(17.7	)		0.7
Total revenues		1,671.9		425.6		(17.7	)		2,079.8
Depreciation		161.0		34.3		0.0			195.3
Total interest charges		91.8		13.8		0.0			105.6
Provision for taxes		98.4		16.9		0.0			115.3
Net income		166.8		26.7		0.0			193.5
Total assets at Dec. 31, 2010	$	5,580.6	$	872.7	($	14.8	)	$	6,438.5

XML

Employee Postretirement Benefits

9 Months Ended

Sep. 30, 2011

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company.

Pension Expense

		$000,000			$000,000			$000,000		$000,000
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sep. 30,	2011			2010			2011		2010
Components of net periodic benefit expense
Service cost	$	4.0		$	4.0		$	0.5	$	0.8
Interest cost on projected benefit obligations		7.7			8.2			2.8		2.8
Expected return on assets		(9.6	)		(9.0	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.5		0.5
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.2
Actuarial loss		2.8			3.2			0.1		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	4.8		$	6.3		$	4.1	$	4.3
Nine months ended Sep. 30,
Components of net periodic benefit expense
Service cost	$	12.0		$	12.1		$	1.6	$	2.4
Interest cost on projected benefit obligations		23.2			24.9			8.3		8.2
Expected return on assets		(28.8	)		(27.2	)		0.0		0.0
Amortization of:
Transition obligation		(0.3	)		0.0			1.7		1.7
Prior service (benefit) cost		8.4			(0.3	)		0.6		0.6
Actuarial loss		0.0			9.4			0.1		0.0
Pension expense		14.5			18.9			12.3		12.9
Settlement cost		0.0			1.6			0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	14.5		$	20.5		$	12.3	$	12.9

For the fiscal 2011 plan year, TECO Energy assumed an expected long-term return on plan assets of 7.75% and a discount rate of 5.30% for pension benefits under its qualified pension plan, and a discount rate of 5.25% for its other postretirement benefits as of their Jan. 1, 2011 measurement dates.

Effective Dec. 31, 2006, in accordance with the accounting standard for defined benefit plans and other postretirement benefits, 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 purposes prescribed by accounting standards for regulated operations, were recorded as regulatory assets for Tampa Electric Company. For the three and nine months ended Sep. 30, 2011, TECO Energy and its subsidiaries reclassed $0.6 million and $1.9 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from accumulated other comprehensive income to net income as part of periodic benefit expense. In addition, during the three and nine months ended Sep. 30, 2011, Tampa Electric Company reclassed $2.9 million and $8.6 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

In connection with the restructuring events that occurred in the third quarter of 2009 that changed the senior management structure, TECO Energy recognized settlement charges of $1.6 million, for the nine months ended Sep. 30, 2010 for payouts from its TECO Energy Group Supplemental Executive Retirement Program (SERP).

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, The Health Care and Education Reconciliation Act, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset by $6.4 million and recorded a corresponding charge of $1.1 million and a regulatory tax asset of $5.3 million.

Tampa Electric Co [Member]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. Tampa Electric Company's portion of the net pension expense for the three months ended Sep. 30, 2011 and 2010, respectively, was $3.4 million and $4.7 million for pension benefits, and $3.4 million for other postretirement benefits. For the nine months ended Sep. 30, 2011 and 2010, respectively, net benefit expenses were $10.1 million and $14.0 million for pension benefits and $10.1 million and $10.3 million for other postretirement benefits.

For the fiscal 2011 plan year, TECO Energy assumed an expected long-term return on plan assets of 7.75% and a discount rate of 5.30% for pension benefits under its qualified pension plan, and a discount rate of 5.25% for its other postretirement benefits as of their Jan. 1, 2011 measurement dates.

Effective Dec. 31, 2006, in accordance with the accounting standard for defined benefit plans and other postretirement benefits, Tampa Electric Company adjusted its postretirement benefit obligations and recorded regulatory assets to reflect the unamortized transition obligation, prior service cost, and actuarial gains and losses of its postretirement benefit plans. Included in the benefit expenses discussed above, for the three months and nine months ended Sep. 30, 2011, Tampa Electric Company reclassed $2.9 million and $8.6 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income. For the three months and nine months ended Sep. 30, 2010, Tampa Electric Company reclassed $3.1 million and $9.5 million, respectively.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, The Health Care and Education Reconciliation Act, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, Tampa Electric Company reduced its deferred tax asset by $5.3 million and recorded a corresponding regulatory tax asset.

XML

Accounting For Derivative Instruments And Hedging Activities (Narrative) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	$ (5.1)	[1]	$ (4.2)	[1]
Net pretax losses expected to be reclassified from regulatory assets or liabilities	29.5
Tampa Electric Co [Member]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	(4.8)	[2]	(5.3)	[2]
Net pretax losses expected to be reclassified from regulatory assets or liabilities	$ 29.5

[1] Net of tax benefit of $3.3 million and $2.7 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

[2] Net of tax benefit of $3.0 million and $3.4 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

XML

Consolidated Condensed Statements Of Comprehensive Income (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Consolidated Condensed Statements Of Comprehensive Income [Abstract]
Net income	$ 90.3	$ 51.1	$ 219.6	$ 182.8
Other comprehensive (loss) income, net of tax
Net unrealized (losses) gains on cash flow hedges	(1.8)	1.4	(0.9)	1.8
Amortization of unrecognized benefit costs and other	0.4	0.4	1.2	2.6
Recognized benefit costs due to settlement	0	0	0	1.0
Total other comprehensive income, Net	(1.4)	1.8	0.3	5.4
Comprehensive income	88.9	52.9	219.9	188.2
Comprehensive loss attributable to noncontrolling interests	(0.1)	(0.1)	(0.2)	(0.5)
Comprehensive income	$ 88.8	$ 52.8	$ 219.7	$ 187.7

XML

Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Significant Accounting Policies

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 (VIEs) for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. Effective Jan. 1, 2010, amended accounting standards on consolidation resulted in the reconsolidation of two projects in Guatemala.

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 its subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011.

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

Revenues

As of Sep. 30, 2011 and Dec. 31, 2010, unbilled revenues of $58.1 million and $65.5 million, respectively, are included in the "Receivables" line item on the Consolidated Condensed Balance Sheets.

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 Florida Public Service Commission (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 $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.0 million and $90.0 million for the three and nine months ended Sep. 30, 2010. 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 amounts totaled $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.1 million and $89.9 million for the three and nine months ended Sep. 30, 2010.

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 $32.1 million and $103.2 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $45.2 million and $151.5 million for the three and nine months ended Sep. 30, 2010. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through FPSC-approved cost recovery clauses.

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 which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas swaps, the cash inflows and outflows are also 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.

Tampa Electric Co [Member]

Significant Accounting Policies

1. Summary of Significant Accounting Policies

The significant accounting policies for Tampa Electric Company include:

Principles of Consolidation and Basis of Presentation

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, Tampa Electric Company is comprised of the Electric division, generally referred to as Tampa Electric, the Natural Gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. Tampa Electric Company is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. For the periods presented, no VIEs have been consolidated (see Note 13).

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 its subsidiaries as of Sep. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Sep. 30, 2011 and 2010. The results of operations for the three month and nine month periods ended Sep. 30, 2011 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2011.

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

Revenues

As of Sep. 30, 2011 and Dec. 31, 2010, unbilled revenues of $58.1 million and $65.5 million, respectively, are included in the "Receivables" line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

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 $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.0 million and $90.0 million for the three and nine months ended Sep. 30, 2010. 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 amounts totaled $28.8 million and $84.3 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $31.1 million and $89.9 million for the three and nine months ended Sep. 30, 2010.

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 $32.1 million and $103.2 million, respectively, for the three and nine months ended Sep. 30, 2011, compared to $45.2 million and $151.5 million for the three and nine months ended Sep. 30, 2010. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through FPSC-approved cost recovery clauses.

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.

XML

Employee Postretirement Benefits (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended		12 Months Ended				3 Months Ended		9 Months Ended		12 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended	3 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2011	Mar. 31, 2010	Mar. 31, 2010 Regulatory Tax Asset [Member]	Mar. 31, 2010 Corresponding Charge [Member]	Sep. 30, 2011 Pension Benefits [Member]	Sep. 30, 2010 Pension Benefits [Member]	Sep. 30, 2011 Pension Benefits [Member]	Sep. 30, 2010 Pension Benefits [Member]	Dec. 31, 2011 Pension Benefits [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Pension Benefits [Member]	Sep. 30, 2010 Tampa Electric Co [Member] Pension Benefits [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Pension Benefits [Member]	Sep. 30, 2010 Tampa Electric Co [Member] Pension Benefits [Member]	Sep. 30, 2011 Other Postretirement Benefits [Member]	Sep. 30, 2010 Other Postretirement Benefits [Member]	Sep. 30, 2011 Other Postretirement Benefits [Member]	Sep. 30, 2010 Other Postretirement Benefits [Member]	Dec. 31, 2011 Other Postretirement Benefits [Member]	Sep. 30, 2010 Tampa Electric Co [Member] Other Postretirement Benefits [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Other Postretirement Benefits [Member]	Sep. 30, 2010 Tampa Electric Co [Member] Other Postretirement Benefits [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Sep. 30, 2010 Tampa Electric Co [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Sep. 30, 2010 Tampa Electric Co [Member]	Mar. 31, 2010 Tampa Electric Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Net pension expense								$ 4.8	$ 6.3	$ 14.5	$ 20.5		$ 3.4	$ 4.7	$ 10.1	$ 14.0	$ 4.1	$ 4.3	$ 12.3	$ 12.9		$ 3.4	$ 10.1	$ 10.3
Expected long-term return on plan assets				7.75%
Discount rate												5.30%									5.25%
Reclassification from accumulated other comprehensive income, regulatory assets	2.9	8.6																							2.9	3.1	8.6	9.5
Reclassification from accumulated other comprehensive income	0.6	1.9
Settlement cost			1.6							0	1.6								0	0
Medicare Part D Subsidy, reduction of related deferred tax assets					$ 6.4	$ 5.3	$ 1.1																						$ 5.3

XML

Commitments And Contingencies (Tables)

9 Months Ended

Sep. 30, 2011

Letters Of Credit And Guarantees

Guarantees-TECO Energy

(millions)					After(1)				Liabilities Recognized
Guarantees for the Benefit of:	2011		2012-2015		2015		Total		at Sep. 30, 2011
TECO Coal
Guarantees: Fuel purchase related (2)		0.0		0.0		5.4		5.4		1.1
		0.0		0.0		5.4		5.4		1.1
Other subsidiaries
Guarantees:
Fuel purchase/energy management (2)		0.0		0.0		109.7		109.7		1.1
Total	$	0.0	$	0.0	$	115.1	$	115.1	$	2.2
Letters of Credit-Tampa Electric Company
(millions)					After(1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2011		2012-2015		2015		Total		at Sep. 30, 2011
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2015.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sep. 30, 2011. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Tampa Electric Co [Member]

Letters Of Credit And Guarantees

Letters of Credit -Tampa Electric Company

(millions)
									Liabilities Recognized
Letters of Credit for the Benefit of:	2011		2012- 2015		After (1) 2015		Total		at Sep. 30, 2011
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2015.

XML

Accounting For Derivative Instruments And Hedging Activities (Derivative Volumes Expected To Settle) (Details)	Dec. 31, 2011 2011 [Member] Diesel Fuel Derivatives [Member] Physical [Member]	Dec. 31, 2011 2011 [Member] Diesel Fuel Derivatives [Member] Financial [Member]	Dec. 31, 2011 2011 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2011 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2011 2011 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2011 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2012 2012 [Member] Diesel Fuel Derivatives [Member] Physical [Member]	Dec. 31, 2012 2012 [Member] Diesel Fuel Derivatives [Member] Financial [Member]	Dec. 31, 2012 2012 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2012 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2012 2012 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2012 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2013 2013 [Member] Diesel Fuel Derivatives [Member] Physical [Member]	Dec. 31, 2013 2013 [Member] Diesel Fuel Derivatives [Member] Financial [Member]	Dec. 31, 2013 2013 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2013 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2013 2013 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2013 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2014 2014 [Member] Diesel Fuel Derivatives [Member] Physical [Member]	Dec. 31, 2014 2014 [Member] Diesel Fuel Derivatives [Member] Financial [Member]	Dec. 31, 2014 2014 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2014 [Member] Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Dec. 31, 2014 2014 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 2014 [Member] Financial [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 Diesel Fuel Derivatives [Member] Physical [Member]	Sep. 30, 2011 Physical [Member] Natural Gas Contracts (MMBTUs) [Member]	Sep. 30, 2011 Diesel Fuel Derivatives [Member] Financial [Member]	Sep. 30, 2011 Financial [Member] Natural Gas Contracts (MMBTUs) [Member]
Derivatives, Fair Value [Line Items]
Derivative volumes	0	2,400,000	0	0.0	11,600,000	11.6	0	2,600,000	0	0.0	35,000,000	35.0	0	1,800,000	0	0.0	5,000,000	5.0	0	1,000,000	0	0.0	0	51.6	0	0	7,800,000	51,600,000

XML

Fair Value Measurements (Narrative) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Long-term debt, carrying amount	$ 3,076.1	$ 3,226.4
Long-term debt, estimated fair value	3,450.7	3,449.3
Tampa Electric Co [Member]
Long-term debt, carrying amount	1,991.2	2,069.5
Long-term debt, estimated fair value	$ 2,291.4	$ 2,217.0

XML

Segment Information (Schedule Of Revenues By Segment) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Segment Reporting Information [Line Items]
Revenues - external	$ 911.4		$ 901.8		$ 2,593.2		$ 2,712.9
Sales to affiliates	0		0		0		0
Total revenues	911.4		901.8		2,593.2		2,712.9
Equity earnings of unconsolidated affiliates	0		3.6		0		10.5
Depreciation	82.4		78.8		243.4		233.7
Restructuring charges					0		1.5
Total interest charges	50.7	[1]	57.4	[1]	154.5	[1]	174.9	[1]
Internally allocated interest	0	[1]	0	[1]	0	[1]	0	[1]
Provision (benefit) for taxes	51.2		65.5		123.7		135.9
Net income (loss)	90.2		51.0		219.4		182.3
Goodwill	55.4				55.4				55.4
Total assets	7,295.9				7,295.9				7,194.6
Tampa Electric Co [Member] | Tampa Electric [Member]
Segment Reporting Information [Line Items]
Revenues - external	591.8		593.3		1,571.2		1,670.9
Sales to affiliates	0.1		0.3		0.4		1.0
Total revenues	591.9		593.6		1,571.6		1,671.9
Depreciation	56.2		54.4		166.4		161.0
Total interest charges	30.3		30.7		91.6		91.8
Provision (benefit) for taxes	47.4		36.8		104.3		98.4
Net income (loss)	75.0		61.9		165.0		166.8
Total assets	5,691.7				5,691.7				5,580.6
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Revenues - external	591.6		593.3		1,570.6		1,670.9
Sales to affiliates	0.3		0.3		1.0		1.0
Total revenues	591.9		593.6		1,571.6		1,671.9
Equity earnings of unconsolidated affiliates			0				0
Depreciation	56.2		54.4		166.4		161.0
Restructuring charges							0
Total interest charges	30.3	[1]	30.7	[1]	91.6	[1]	91.8	[1]
Internally allocated interest	0	[1]	0	[1]	0	[1]	0	[1]
Provision (benefit) for taxes	47.4		36.8		104.3		98.4
Net income (loss)	75.0		61.9		165.0		166.8
Goodwill	0				0				0
Total assets	5,924.3				5,924.3				5,833.3
Tampa Electric Co [Member] | Peoples Gas [Member]
Segment Reporting Information [Line Items]
Revenues - external	93.8		114.1		358.5		408.2
Sales to affiliates	0.4		2.5		3.0		17.4
Total revenues	94.2		116.6		361.5		425.6
Depreciation	12.2		11.5		36.0		34.3
Total interest charges	4.4		4.6		13.3		13.8
Provision (benefit) for taxes	3.0		2.4		16.0		16.9
Net income (loss)	4.8		3.7		25.4		26.7
Total assets	840.4				840.4				872.7
Peoples Gas [Member]
Segment Reporting Information [Line Items]
Revenues - external	93.9		114.1		358.5		408.2
Sales to affiliates	0.3		2.5		3.0		17.4
Total revenues	94.2		116.6		361.5		425.6
Equity earnings of unconsolidated affiliates			0				0
Depreciation	12.2		11.5		36.0		34.3
Restructuring charges							0
Total interest charges	4.4	[1]	4.6	[1]	13.3	[1]	13.8	[1]
Internally allocated interest	0	[1]	0	[1]	0	[1]	0	[1]
Provision (benefit) for taxes	3.0		2.4		16.0		16.9
Net income (loss)	4.8		3.7		25.4		26.7
Goodwill	0				0				0
Total assets	879.2				879.2				918.4
Teco Coal [Member]
Segment Reporting Information [Line Items]
Revenues - external	190.5		165.3		555.5		537.9
Sales to affiliates	0		0		0		0
Total revenues	190.5		165.3		555.5		537.9
Equity earnings of unconsolidated affiliates			0				0
Depreciation	11.8		11.0		34.4		32.8
Restructuring charges							0
Total interest charges	1.7	[1]	1.6	[1]	5.1	[1]	5.2	[1]
Internally allocated interest	1.7	[1]	1.5	[1]	5.0	[1]	5.0	[1]
Provision (benefit) for taxes	4.1		2.2		10.7		9.1
Net income (loss)	14.1		8.3		38.1		45.8
Goodwill	0				0				0
Total assets	352.5				352.5				332.2
Teco Guatemala [Member]
Segment Reporting Information [Line Items]
Revenues - external	33.6		29.0		103.3		95.7
Sales to affiliates	0		0		0		0
Total revenues	33.6		29.0		103.3		95.7
Equity earnings of unconsolidated affiliates			4.1				12.1
Depreciation	1.8		1.8		5.5		5.4
Restructuring charges							0
Total interest charges	1.9	[1]	4.0	[1]	5.7	[1]	13.0	[1]
Internally allocated interest	1.5	[1]	3.0	[1]	4.6	[1]	9.5	[1]
Provision (benefit) for taxes	2.4		29.1		8.5		35.9
Net income (loss)	4.5		(12.6)		16.4		8.4
Goodwill	55.4				55.4				55.4
Total assets	266.4				266.4				292.7
Tampa Electric Co [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues - external	0		0		0		0
Sales to affiliates	(0.5)		(2.6)		(3.4)		(17.7)
Total revenues	(0.5)		(2.6)		(3.4)		(17.7)
Depreciation	0		0		0		0
Total interest charges	0		0		0		0
Provision (benefit) for taxes	0		0		0		0
Net income (loss)	0		0		0		0
Total assets	(5.9)				(5.9)				(14.8)
Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues - external	1.8		0.1		5.3		0.2
Sales to affiliates	(0.6)		(2.8)		(4.0)		(18.4)
Total revenues	1.2		(2.7)		1.3		(18.2)
Equity earnings of unconsolidated affiliates			(0.5)				(1.6)
Depreciation	0.4		0.1		1.1		0.2
Restructuring charges							1.5
Total interest charges	12.4	[1]	16.5	[1]	38.8	[1]	51.1	[1]
Internally allocated interest	(3.2)	[1]	(4.5)	[1]	(9.6)	[1]	(14.5)	[1]
Provision (benefit) for taxes	(5.7)		(5.0)		(15.8)		(24.4)
Net income (loss)	(8.2)		(10.3)		(25.5)		(65.4)
Goodwill	0				0				0
Total assets	(126.5)				(126.5)				(182.0)
Tampa Electric Co [Member]
Segment Reporting Information [Line Items]
Revenues - external	685.6		707.4		1,929.7		2,079.1
Sales to affiliates	0		0.2		0		0.7
Total revenues	685.6		707.6		1,929.7		2,079.8
Depreciation	68.4		65.9		202.4		195.3
Total interest charges	34.7		35.3		104.9		105.6
Provision (benefit) for taxes	50.4		39.2		120.3		115.3
Net income (loss)	79.8		65.6		190.4		193.5
Total assets	$ 6,526.2				$ 6,526.2				$ 6,438.5

[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 January 2011 through September 2011 were at a pretax rate of 6.25%, for July 2010 through December 2010 were at a pretax rate of 6.50%, and for January 2010 through June 2010 were at a pretax rate of 7.15% based on an average of each subsidiary's equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

XML

Subsequent Events (Details) (USD $) In Millions	9 Months Ended		9 Months Ended		9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 $200 Million Bank Credit Facility Amendment [Member]	Oct. 25, 2011 $200 Million Bank Credit Facility Amendment [Member]	Sep. 30, 2011 Tampa Electric Co [Member] $325 Million Bank Credit Facility Amendment [Member]	Oct. 25, 2011 Tampa Electric Co [Member] $325 Million Bank Credit Facility Amendment [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Dec. 31, 2010 Tampa Electric Co [Member]
Subsequent Event [Line Items]
Outstanding credit facilities	$ 0.7	$ 7.4		$ 200.0		$ 325.0	$ 0.7	$ 0.7
Credit facility initial maturity date			May 9, 2012		May 9, 2012
Credit facility amended maturity date			Oct. 25, 2016		Oct. 25, 2016
Amended credit facility interest rate			equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%		equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%
Increase to commitments on credit facility	50		100		175
Letter of credit facility			$ 200		$ 200		$ 50

XML

New Accounting Pronouncements

9 Months Ended

Sep. 30, 2011

New Accounting Pronouncements

2. New Accounting Pronouncements

Intangibles – Goodwill and Other

In September 2011, the Financial Accounting Standards Board (FASB) issued guidance that allows companies to perform a qualitative analysis as the first step in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If it is determined that it is not more likely than not that the fair value of the reporting unit is less than its carrying amount, then a quantitative analysis for impairment is not required. The guidance is effective for interim and annual impairment tests for fiscal periods beginning after Dec. 15, 2011. The company will adopt the guidance as required. It will have no effect on the company's results of operations, financial position or cash flows.

Presentation of Comprehensive Income

In June 2011, the FASB issued guidance requiring companies to present the total of comprehensive income, the components of net income and the components of other comprehensive income, in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. The company will adopt the guidance as required. It will have no effect on the company's results of operations, financial position or cash flows.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS)

In May 2011, the FASB issued guidance to more closely align its fair value measurement and disclosure requirements with IFRS. The guidance relates to: measuring the fair value of financial instruments that are managed in a portfolio; the application of premiums and discounts in fair value measurement; and disclosures for items required to be disclosed, but not reported on the statement of financial position, at fair value and Level 3 measures. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. The company will adopt the guidance as required. It will have no effect on the company's results of operations, financial position or cash flows.

Tampa Electric Co [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Presentation of Comprehensive Income

In June 2011, the FASB issued guidance requiring companies to present the total of comprehensive income, the components of net income and the components of other comprehensive income, in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. Tampa Electric Company will adopt the guidance as required. It will have no effect on Tampa Electric Company's results of operations, financial position or cash flows.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS

In May 2011, the FASB issued guidance to more closely align its fair value measurement and disclosure requirements with IFRS. The guidance relates to: measuring the fair value of financial instruments that are managed in a portfolio; the application of premiums and discounts in fair value measurement; and disclosures for items required to be disclosed, but not reported on the statement of financial position, at fair value and Level 3 measures. The guidance is effective for interim and annual periods beginning after Dec. 15, 2011. Tampa Electric Company will adopt the guidance as required. It will have no effect on Tampa Electric Company's results of operations, financial position or cash flows

XML

Short-Term Debt (Narrative) (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	9 Months Ended
	Feb. 18, 2011	Sep. 30, 2011	Dec. 31, 2010
Commitment fees, basis points	70
Weighted-average interest rate			0.64%
Federal funds rate plus basis points	50
Tampa Electric Co [Member]
Borrowing facility, accounts receivable	$ 150
Commitment fees, basis points	70	These credit facilities require commitment fees ranging from 7.0 to 35.0 basis points
Weighted-average interest rate			0.64%
Federal funds rate plus basis points	50

XML

Short-Term Debt (Tables)

9 Months Ended

Sep. 30, 2011

Credit Facilities

Credit Facilities

	Sep. 30, 2011						Dec. 31, 2010
	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
(millions)
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	5.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		7.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		6.7
Total	$	675.0	$	0.0	$	0.7	$	675.0	$	12.0	$	7.4

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures May 9, 2012. See Note 16 for information on an amendment to this facility.

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

Tampa Electric Co [Member]

Credit Facilities

	Sep. 30, 2011						Dec. 31, 2010
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	5.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		7.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	12.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures May 9, 2012. See Note 14 for information on an amendment to this facility.

XML

Restructuring Charges (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Restructuring Charges [Abstract]
Restructuring charges	$ 0	$ 1.5

XML

Accounting For Derivative Instruments And Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2011

Fair Values And Locations Of Derivative Instruments Recorded On The Balance Sheet

Total Derivatives⁽¹⁾

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	1.3	$	2.7
Long-term assets		0.2		0.2
Total assets	$	1.5	$	2.9
Current liabilities	$	29.5	$	27.2
Long-term liabilities		6.0		2.6
Total liabilities	$	35.5	$	29.8

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

Effect Of Hedging Instruments On OCI And Income

For the three months ended Sep. 30:

(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 Cash Flow Hedging Relationships	Effective Portion(1)				Effective Portion(1)
2011
Interest rate contracts:	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(1.3	)	Mining related costs		0.7
Total	$	(1.3	)		$	0.5
2010
Interest rate contracts:	$	0.0		Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		0.7		Mining related costs		(0.3	)
Total	$	0.7			$	(0.7	)

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

For the nine months ended Sep. 30:

(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 Cash Flow Hedging Relationships	Effective Portion(1)				Effective Portion(1)
2011
Interest rate contracts:	$	0.0		Interest expense	$	(0.5	)
Commodity contracts:
Diesel fuel derivatives		0.6		Mining related costs		2.0
Total	$	0.6			$	1.5
2010
Interest rate contracts:	$	(0.1	)	Interest expense	$	(1.2	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)	Mining related costs		(0.9	)
Total	$	(0.3	)		$	(2.1	)

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

Schedule Of Cash Flow Hedges Included In Accumulated Other Comprehensive Income (Loss)

For the nine months ended Sep. 30:

(millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI(1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income(1)
2011
Interest rate swaps	$	0.0		$	0.0		$	(0.5	)
Diesel fuel derivatives		0.0			0.6			2.0
Total	$	0.0		$	0.6		$	1.5
2010
Interest rate swaps	$	(0.3	)	$	(0.1	)	$	(1.2	)
Diesel fuel derivatives		0.3			(0.2	)		(0.9	)
Total	$	0.0		$	(0.3	)	$	(2.1	)

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

Schedule Of Notional Amounts Of Outstanding Derivative Positions

(millions) Year	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
	Physical		Financial		Physical		Financial
2011		0.0		2.4		0.0		11.6
2012		0.0		2.6		0.0		35.0
2013		0.0		1.8		0.0		5.0
2014		0.0		1.0		0.0		0.0
Total		0.0		7.8		0.0		51.6

Fair Value Of The Overall Contractual Contingent Liability Positions

(millions) At Sep. 30, 2011	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(35.1	)	$	(35.1	)	$	0.0

Designated As Hedging Instrument [Member]

Fair Values And Locations Of Derivative Instruments Recorded On The Balance Sheet

	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2011	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	1.3	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.2	Derivative liabilities		1.5
Natural gas derivatives:
Current	Derivative assets		0.0	Derivative liabilities		29.5
Long-term	Derivative assets		0.0	Derivative liabilities		4.5
Total derivatives designated as hedging instruments		$	1.5		$	35.5

Natural Gas Derivatives [Member]

Fair Values And Locations Of Derivative Instruments Recorded On The Balance Sheet

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	0.0	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.0	$	1.1
Current liabilities	$	29.5	$	27.2
Long-term liabilities		4.5		2.6
Total liabilities	$	34.0	$	29.8

Diesel Fuel Derivatives [Member]

Fair Values And Locations Of Derivative Instruments Recorded On The Balance Sheet

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	1.3	$	1.6
Long-term assets		0.2		0.2
Total assets	$	1.5	$	1.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		1.5		0.0
Total liabilities	$	1.5	$	0.0

Tampa Electric Co [Member] | Energy Related Derivatives [Member]

Fair Values And Locations Of Derivative Instruments Recorded On The Balance Sheet

Energy Related Derivatives

	Asset Derivatives				Liability Derivatives
(millions) at Sep. 30, 2011	Balance Sheet Location(1)		Fair              Value		Balance Sheet Location(1)		Fair              Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	0.0		Regulatory assets	$	29.5
Long-term		Regulatory liabilities		0.0		Regulatory assets		4.5
Total			$	0.0			$	34.0

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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.

Energy Related Derivatives [Member]

Fair Values And Locations Of Derivative Instruments Recorded On The Balance Sheet

Energy Related Derivatives

	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2011	Balance  Sheet Location(1)	Fair Value		Balance  Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.0	Regulatory assets	$	29.5
Long-term	Regulatory liabilities		0.0	Regulatory assets		4.5
Total		$	0.0		$	34.0

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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.

Tampa Electric Co [Member]

Effect Of Hedging Instruments On OCI And Income

(millions)	Location of Loss Reclassified From AOCI Into Income	Amount of Loss Reclassified From AOCI Into Income(1)
Derivatives in Cash Flow Hedging Relationships	Effective Portion(1)	Three months ended Sep. 30:			Nine months ended Sep. 30:
2011
Interest rate contracts:	Interest expense	($	0.2	)	($	0.5	)
Total		($	0.2	)	($	0.5	)
2010
Interest rate contracts:	Interest expense	($	0.2	)	($	0.6	)
Total		($	0.2	)	($	0.6	)

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

Derivative Activity For Instruments Classified As Qualifying Cash Flow Hedges

Natural Gas Derivatives

(millions)	Sep.  30, 2011		Dec.  31, 2010
Current assets	$	0.0	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.0	$	1.1
Current liabilities(1)	$	29.5	$	27.2
Long-term liabilities		4.5		2.6
Total liabilities	$	34.0	$	29.8

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

Schedule Of Notional Amounts Of Outstanding Derivative Positions

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2011		0.0		11.6
2012		0.0		35.0
2013		0.0		5.0
Total		0.0		51.6

Fair Value Of The Overall Contractual Contingent Liability Positions

(millions) At Sep. 30, 2011	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(34.0	)	$	(34.0	)	$	0.0

XML

Employee Postretirement Benefits (Periodic Expense For Pension And Other Postretirement Benefits) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Defined Benefit Plan Disclosure [Line Items]
Settlement cost				$ 1.6
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	4.0	4.0	12.0	12.1
Interest cost on projected benefit obligations	7.7	8.2	23.2	24.9
Expected return on assets	(9.6)	(9.0)	(28.8)	(27.2)
Amortization of transition obligation	0	0	(0.3)	0
Amortization of prior service (benefit) cost	(0.1)	(0.1)	8.4	(0.3)
Amortization of actuarial loss	2.8	3.2	0	9.4
Pension expense			14.5	18.9
Settlement cost			0	1.6
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	4.8	6.3	14.5	20.5
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.5	0.8	1.6	2.4
Interest cost on projected benefit obligations	2.8	2.8	8.3	8.2
Expected return on assets	0	0	0	0
Amortization of transition obligation	0.5	0.5	1.7	1.7
Amortization of prior service (benefit) cost	0.2	0.2	0.6	0.6
Amortization of actuarial loss	0.1	0	0.1	0
Pension expense			12.3	12.9
Settlement cost			0	0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 4.1	$ 4.3	$ 12.3	$ 12.9

XML

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Schedule Of Earnings Per Share

	Three months ended Sep. 30,						Nine months ended Sep. 30,
(millions, except per share amounts)	2011			2010			2011			2010
Basic earnings per share
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Less: Income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Less: Amount allocated to nonvested participating shareholders		(0.5	)		(0.4	)		(1.2	)		(1.3	)
Net income attributable to TECO Energy available to common shareholders—basic	$	89.7		$	50.6		$	218.2		$	181.0
Average shares outstanding-common		213.8			212.8			213.5			212.5
Basic earnings per share attributable to TECO Energy available to common shareholders	$	0.42		$	0.24		$	1.02		$	0.85
Diluted earnings per share
Net income	$	90.3		$	51.1		$	219.6		$	182.8
Less: Income attributable to noncontrolling interest		(0.1	)		(0.1	)		(0.2	)		(0.5	)
Less: Amount allocated to nonvested participating shareholders		(0.5	)		(0.4	)		(1.2	)		(1.3	)
Net income attributable to TECO Energy available to common shareholders—diluted	$	89.7		$	50.6		$	218.2		$	181.0
Average shares outstanding-common		213.8			212.8			213.5			212.5
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		1.5			2.3			1.6			2.1
Adjusted average shares outstanding common—diluted		215.3			215.1			215.1			214.6
Diluted earnings per share attributable to TECO Energy available to common shareholders	$	0.42		$	0.24		$	1.02		$	0.85
Anti-dilutive shares		1.4			2.5			1.8			4.3

XML

Commitments And Contingencies

9 Months Ended

Sep. 30, 2011

Commitments And Contingencies

10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable 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, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

The second portion of a non-jury trial in this case was held in October 2011 in the Dade County, Florida Circuit Court. The first portion was held in June 2011. The trial is expected to resume and conclude in the first half of 2012. Merco Group at Aventura Landings I, II and III (Merco) alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco's property. In addition, the court will consider PGS's counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2011, Tampa Electric Company has estimated its ultimate financial liability to be $21.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in "Long-term regulatory liabilities" on the company's Consolidated Condensed Balance Sheet. 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 clean-up costs attributable to Tampa Electric Company. The estimates to perform the work are based on 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.

In instances where other PRPs are involved, many of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, Tampa Electric Company could be liable for more than Tampa Electric Company's actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Potentially Responsible Party Notification

In October 2010, the U.S. Environmental Protection Agency (EPA) notified Tampa Electric Company that it is a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, commonly known as Superfund, for the proposed conduct of a contaminated soil removal action and further clean up, if necessary, at a property owned by Tampa Electric Company in Tampa, Florida. The property owned by Tampa Electric Company is undeveloped except for location of transmission lines and poles, and is adjacent to an industrial site, not owned by Tampa Electric Company, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to Tampa Electric Company's ownership of the property described above but, to the knowledge of Tampa Electric Company, this assertion is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company has responded to the EPA regarding such matter. The scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

Environmental Protection Agency Administrative Order

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal Corporation (TECO Coal), received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. TECO Coal responded to the EPA on Feb. 14, 2011. The scope and extent of TECO Coal's potential liability, if any, and the costs of any required investigation and remediation related to these inactive mining operations in the area have not been determined.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy's and Tampa Electric Company's letters of credit and guarantees as of Sep. 30, 2011 is as follows:

Guarantees-TECO Energy

(millions)					After(1)				Liabilities Recognized
Guarantees for the Benefit of:	2011		2012-2015		2015		Total		at Sep. 30, 2011
TECO Coal
Guarantees: Fuel purchase related (2)		0.0		0.0		5.4		5.4		1.1
		0.0		0.0		5.4		5.4		1.1
Other subsidiaries
Guarantees:
Fuel purchase/energy management (2)		0.0		0.0		109.7		109.7		1.1
Total	$	0.0	$	0.0	$	115.1	$	115.1	$	2.2
Letters of Credit-Tampa Electric Company
(millions)					After(1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2011		2012-2015		2015		Total		at Sep. 30, 2011
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2015.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sep. 30, 2011. 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 facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2011, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants.

Tampa Electric Co [Member]

Commitments And Contingencies

8. Commitments and Contingencies

Legal Contingencies

From time to time, Tampa Electric Company and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on Tampa Electric Company's results of operations, financial condition or cash flows.

Merco Group at Aventura Landings v. Peoples Gas System

The second portion of a non-jury trial in this case was held in October 2011 in the Dade County, Florida Circuit Court. The first portion was held in June 2011. The trial is expected to resume and conclude in the first half of 2012. Merco alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco's property. In addition, the court will consider PGS's counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2011, Tampa Electric Company has estimated its ultimate financial liability to be $21.3 million, primarily at PGS. This amount has been accrued and is primarily reflected in "Long-term regulatory liabilities" on Tampa Electric Company's Consolidated Condensed Balance Sheet. 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 clean-up costs attributable to Tampa Electric Company. The estimates to perform the work are based on 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.

In instances where other PRPs are involved, many of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, Tampa Electric Company could be liable for more than Tampa Electric Company's actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.

Potentially Responsible Party Notification

In October 2010, the U.S. EPA notified Tampa Electric Company that it is a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, commonly known as Superfund, for the proposed conduct of a contaminated soil removal action and further clean up, if necessary, at a property owned by Tampa Electric Company in Tampa, Florida. The property owned by Tampa Electric Company is undeveloped except for location of transmission lines and poles, and is adjacent to an industrial site, not owned by Tampa Electric Company, which the EPA has studied since 1992 or earlier. The EPA has asserted this potential liability due to Tampa Electric Company's ownership of the property described above but, to the knowledge of Tampa Electric Company, this assertion is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company has responded to the EPA regarding such matter. The scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

Letters of Credit

A summary of the face amount or maximum theoretical obligation under Tampa Electric Company's letters of credit as of Sep. 30, 2011 are as follows:

Letters of Credit -Tampa Electric Company

(millions)
									Liabilities Recognized
Letters of Credit for the Benefit of:	2011		2012- 2015		After (1) 2015		Total		at Sep. 30, 2011
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2015.

Financial Covenants

In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2011, Tampa Electric Company was in compliance with all applicable financial covenants.

XML

Accounting For Derivative Instruments And Hedging Activities (Effect of Hedging Instruments On OCI and Income) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Derivatives, Fair Value [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ (1.3)	[1]	$ 0.7	[1]	$ 0.6	[1]	$ (0.3)	[1]
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	0.5	[1]	(0.7)	[1]	1.5	[1]	(2.1)	[1]
Tampa Electric Co [Member] | Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense		Interest expense		Interest expense		Interest expense
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	(0.2)		(0.2)		(0.5)		(0.6)
Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	[1]	0	[1]	0	[1]	(0.1)	[1]
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense		Interest expense		Interest expense		Interest expense
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	(0.2)	[1]	(0.4)	[1]	(0.5)	[1]	(1.2)	[1]
Tampa Electric Co [Member]
Derivatives, Fair Value [Line Items]
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	(0.2)		(0.2)		(0.5)		(0.6)
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(1.3)	[1]	0.7	[1]	0.6	[1]	(0.2)	[1]
Location of Gain/(Loss) Reclassified From AOCI Into Income	Mining related costs		Mining related costs		Mining related costs		Mining related costs
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	$ 0.7	[1]	$ (0.3)	[1]	$ 2.0	[1]	$ (0.9)	[1]

[1] Changes in OCI and AOCI are reported in after-tax dollars.

XML

Fair Value Measurements (Recurring Fair Value Measures) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	$ 1.5	$ 2.9
Fair Value, Liabilities	35.5	29.8
Diesel Fuel Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	1.5	1.8
Fair Value, Liabilities	1.5
Diesel Fuel Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0
Diesel Fuel Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	1.5	1.8
Fair Value, Liabilities	1.5
Diesel Fuel Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0
Tampa Electric Co [Member] | Natural Gas Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	1.1
Fair Value, Liabilities	34.0	29.8
Tampa Electric Co [Member] | Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Tampa Electric Co [Member] | Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	1.1
Fair Value, Liabilities	34.0	29.8
Tampa Electric Co [Member] | Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Natural Gas Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	1.1
Fair Value, Liabilities	34.0	29.8
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	1.1
Fair Value, Liabilities	34.0	29.8
Natural Gas Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Tampa Electric Co [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Tampa Electric Co [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	1.1
Fair Value, Liabilities	34.0	29.8
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	1.5	2.9
Fair Value, Liabilities	35.5	29.8
Tampa Electric Co [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	0
Fair Value, Liabilities	0	0
Tampa Electric Co [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Assets	0	1.1
Fair Value, Liabilities	$ 34.0	$ 29.8

XML

Regulatory

9 Months Ended

Sep. 30, 2011

Regulatory

3. Regulatory

Tampa Electric's and PGS's retail businesses are regulated by the FPSC. Tampa Electric also 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 the FERC's regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC's regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to an FPSC-approved self-insured storm damage reserve. Tampa Electric's storm reserve was $41.5 million and $37.4 million as of Sep. 30, 2011 and Dec. 31, 2010, 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 standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year.

Details of the regulatory assets and liabilities as of Sep. 30, 2011 and Dec. 31, 2010 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	64.4	$	66.6
Other:
Cost recovery clauses		38.0		41.9
Postretirement benefit asset		228.9		237.5
Deferred bond refinancing costs (2)		12.2		15.4
Environmental remediation		23.2		23.6
Competitive rate adjustment		3.2		3.3
Other		17.1		16.3
Total other regulatory assets		322.6		338.0
Total regulatory assets		387.0		404.6
Less: Current portion		55.8		62.7
Long-term regulatory assets	$	331.2	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	16.7	$	17.7
Other:
Cost recovery clauses		70.7		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.5		37.4
Deferred gain on property sales (3)		5.4		6.3
Provision for stipulation and other (4)		0.8		9.8
Accumulated reserve-cost of removal		576.7		572.2
Total other regulatory liabilities		716.3		723.1
Total regulatory liabilities		733.0		740.8
Less: Current portion		95.5		110.0
Long-term regulatory liabilities	$	637.5	$	630.8

(1) Primarily related to plant life and derivative positions.

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

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

(4) Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS's 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.

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)	Sep. 30, 2011		Dec 31, 2010
Clause recoverable (1)	$	41.2	$	45.2
Components of rate base (2)		240.9		248.1
Regulatory tax assets (3)		64.4		66.6
Capital structure and other (3)		40.5		44.7
Total	$	387.0	$	404.6

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

(2) Primarily reflects allowed working capital, which is included in rate base and earns 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.

Tampa Electric Co [Member]

Regulatory

3. Regulatory

Tampa Electric's and PGS's retail businesses are regulated by the FPSC. Tampa Electric also is subject to regulation by the FERC under PUHCA 2005. However, pursuant to a waiver granted in accordance with the FERC's regulations, Tampa Electric is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC's regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to an FPSC-approved self-insured storm damage reserve. Tampa Electric's storm reserve was $41.5 million and $37.4 million as of Sep. 30, 2011 and Dec. 31, 2010, 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 standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year.

Details of the regulatory assets and liabilities as of Sep. 30, 2011 and Dec. 31, 2010 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Sep. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	64.4	$	66.6
Other:
Cost recovery clauses		38.0		41.9
Postretirement benefit asset		228.9		237.5
Deferred bond refinancing costs (2)		12.2		15.4
Environmental remediation		23.2		23.6
Competitive rate adjustment		3.2		3.3
Other		17.1		16.3
Total other regulatory assets		322.6		338.0
Total regulatory assets		387.0		404.6
Less: Current portion		55.8		62.7
Long-term regulatory assets	$	331.2	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	16.7	$	17.7
Other:
Cost recovery clauses		70.7		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.5		37.4
Deferred gain on property sales (3)		5.4		6.3
Provision for stipulation and other (4)		0.8		9.8
Accumulated reserve-cost of removal		576.7		572.2
Total other regulatory liabilities		716.3		723.1
Total regulatory liabilities		733.0		740.8
Less: Current portion		95.5		110.0
Long-term regulatory liabilities	$	637.5	$	630.8

(1) Primarily related to plant life and derivative positions.

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

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

(4) Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS's 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.

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

	Sep. 30,		Dec 31,
(millions)	2011		2010
Clause recoverable (1)	$	41.2	$	45.2
Components of rate base (2)		240.9		248.1
Regulatory tax assets (3)		64.4		66.6
Capital structure and other (3)		40.5		44.7
Total	$	387.0	$	404.6

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

(2) Primarily reflects allowed working capital, which is included in rate base and earns 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.

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2011 and Dec. 31, 2010. As required by accounting standards for fair value measurements, 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 diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures

	At fair value as of Sep. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Diesel fuel swaps		0.0		1.5		0.0		1.5
Total	$	0.0	$	1.5	$	0.0	$	1.5
Liabilities
Natural gas swaps	$	0.0	$	34.0	$	0.0	$	34.0
Diesel fuel swaps		0.0		1.5		0.0		1.5
Total	$	0.0	$	35.5	$	0.0	$	35.5
	At fair value as of Dec. 31, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.1	$	0.0	$	1.1
Diesel fuel swaps		0.0		1.8		0.0		1.8
Total	$	0.0	$	2.9	$	0.0	$	2.9
Liabilities
Natural gas swaps	$	0.0	$	29.8	$	0.0	$	29.8
Total	$	0.0	$	29.8	$	0.0	$	29.8

Natural gas and diesel fuel 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 company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2011, the fair value of derivatives was not materially affected by nonperformance risk. The company's net positions with substantially all counterparties were liability positions.

Fair Value of Debt

At Sep. 30, 2011, total long-term debt had a carrying amount of $3,076.1 million and an estimated fair market value of $3,450.7 million. At Dec. 31, 2010, total long-term debt had a carrying amount of $3,226.4 million and an estimated fair market value of $3,449.3 million.

Tampa Electric Co [Member]

Fair Value Measurements

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth, by level within the fair value hierarchy, Tampa Electric Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2011 and Dec. 31, 2010. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Tampa Electric Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures

	At fair value as of Sep. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Total	$	0.0	$	0.0	$	0.0	$	0.0
Liabilities
Natural gas swaps	$	0.0	$	34.0	$	0.0	$	34.0
Total	$	0.0	$	34.0	$	0.0	$	34.0

	At fair value as of Dec. 31, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.1	$	0.0	$	1.1
Total	$	0.0	$	1.1	$	0.0	$	1.1
Liabilities
Natural gas swaps	$	0.0	$	29.8	$	0.0	$	29.8
Total	$	0.0	$	29.8	$	0.0	$	29.8

Natural gas swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the 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.

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 Sep. 30, 2011, 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.

Fair Value of Long-Term Debt

At Sep. 30, 2011, Tampa Electric Company's total long-term debt had a carrying amount of $1,991.2 million and an estimated fair market value of $2,291.4 million. At Dec. 31, 2010, total long-term debt had a carrying amount of $2,069.5 million and an estimated fair market value of $2,217.0 million.

XML

Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Variable Interest Entity [Line Items]
Purchased power	$ 32.1	$ 45.2	$ 103.2	$ 151.5
Tampa Electric Co [Member] | Variable Interest Entity [Member] | Power Purchase Agreements [Member]
Variable Interest Entity [Line Items]
Purchased power	22.9	29.7	64.9	90.6
Tampa Electric Co [Member] | Power Purchase Agreements [Member]
Variable Interest Entity [Line Items]
Purchased power	12.0	14.7	24.9	45.0
Tampa Electric Co [Member] | Maximum Range[Member]
Variable Interest Entity [Line Items]
Multiple PPAs range			370
Tampa Electric Co [Member] | Minimum Range[Member]
Variable Interest Entity [Line Items]
Multiple PPAs range			121
Tampa Electric Co [Member]
Variable Interest Entity [Line Items]
Purchased power	$ 32.1	$ 45.2	$ 103.2	$ 151.5

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Jun. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Taxes [Abstract]
Interest income associated with uncertain tax positions					$ 1.2
After-tax benefit, excluding interest			1.6		4.0
Effective tax rate	36.18%	56.17%		36.02%	42.63%
Interest charges				0.2
Deferred taxes recognized on undistributed earnings		24.9			24.9
Foreign tax credit valuation allowance		$ 5.9			$ 5.9

XML

Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2011

Other Comprehensive Income

	Three months ended Sep. 30,									Nine months ended Sep. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2011
Unrealized (loss) gain on cash flow hedges	$	(2.1	)	$	0.8		$	(1.3	)	$	0.8		$	(0.3	)	$	0.5
Less: Gain reclassified to net income		(0.8	)		0.3			(0.5	)		(2.3	)		0.9			(1.4	)
Loss on cash flow hedges		(2.9	)		1.1			(1.8	)		(1.5	)		0.6			(0.9	)
Amortization of unrecognized benefit costs and other		0.7			(0.3	)		0.4			1.9			(0.7	)		1.2
Total other comprehensive (loss) income	$	(2.2	)	$	0.8		$	(1.4	)	$	0.4		$	(0.1	)	$	0.3
2010
Unrealized gain (loss) on cash flow hedges	$	0.9		$	(0.2	)	$	0.7		$	(0.5	)	$	0.2		$	(0.3	)
Plus: Loss reclassified to net income		1.2			(0.5	)		0.7			3.4			(1.3	)		2.1
Gain on cash flow hedges		2.1			(0.7	)		1.4			2.9			(1.1	)		1.8
Amortization of unrecognized benefit costs and other		0.6			(0.2	)		0.4			1.8			0.8			2.6
Recognized benefit costs due to settlement		0.0			0.0			0.0			1.6			(0.6	)		1.0
Total other comprehensive income	$	2.7		$	(0.9	)	$	1.8		$	6.3		$	(0.9	)	$	5.4

Accumulated Other Comprehensive Loss

(millions)	Sep. 30, 2011			Dec. 31, 2010
Unrecognized pension losses and prior service costs(1)	$	(25.5	)	$	(26.6	)
Unrecognized other benefit gains, prior service costs and transition obligations(2)		13.7			13.6
Net unrealized losses from cash flow hedges(3)		(5.1	)		(4.2	)
Total accumulated other comprehensive loss	$	(16.9	)	$	(17.2	)

(1) Net of tax benefit of $15.7 million and $16.2 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

(2) Net of tax expense of $5.9 million and $5.8 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

(3) Net of tax benefit of $3.3 million and $2.7 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

Tampa Electric Co [Member]

Other Comprehensive Income

Other Comprehensive Income	Three months ended Sep. 30,							Nine months ended Sep. 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2011
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.9	$	(0.4	)	$	0.5
2010
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.9	$	(0.3	)	$	0.6

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

(millions)	Sep. 30, 2011			Dec. 31, 2010
Net unrealized losses from cash flow hedges (1)	$	(4.8	)	$	(5.3	)
Total accumulated other comprehensive loss	$	(4.8	)	$	(5.3	)

(1) Net of tax benefit of $3.0 million and $3.4 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

XML

Consolidated Condensed Statements Of Income (Parenthetical) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Franchise fees and gross receipts taxes	$ 28.8	$ 31.0	$ 84.3	$ 90.0
Tampa Electric Co [Member] | Electric [Member]
Franchise fees and gross receipts taxes	24.7	26.4	65.3	69.6
Tampa Electric Co [Member] | Gas [Member]
Franchise fees and gross receipts taxes	4.1	4.6	19.0	20.4
Electric And Gas [Member]
Franchise fees and gross receipts taxes	28.8	31.0	84.3	90.0
Tampa Electric Co [Member]
Franchise fees and gross receipts taxes	$ 28.8	$ 31.0	$ 84.3	$ 90.0

XML

Restructuring Charges

9 Months Ended

Sep. 30, 2011

Restructuring Charges [Abstract]

Restructuring Charges

14. Restructuring Charges

On Jul. 30, 2009, TECO Energy, Inc. announced organizational changes that resulted in severance and other benefits costs that were mostly expensed during the fourth quarter of 2009. For the nine months ended Sep. 30, 2010, the remaining $1.5 million was recognized on the Consolidated Condensed Statements of Income under "Restructuring charges".

XML

Long-Term Debt (Details) (USD $)	0 Months Ended			9 Months Ended			0 Months Ended		0 Months Ended		0 Months Ended		9 Months Ended		0 Months Ended		0 Months Ended		1 Months Ended	9 Months Ended	0 Months Ended	3 Months Ended	9 Months Ended	0 Months Ended	3 Months Ended	9 Months Ended	0 Months Ended			9 Months Ended	0 Months Ended	9 Months Ended
	Feb. 18, 2011	Apr. 14, 2010	Mar. 22, 2010	Sep. 30, 2011	Sep. 30, 2010	Jan. 31, 2010	Mar. 15, 2010 4.00% Notes Due 2016 [Member] Teco Finance [Member]	Sep. 30, 2011 4.00% Notes Due 2016 [Member] Teco Finance [Member]	Mar. 15, 2010 5.15% Notes Due 2020 [Member] Teco Finance [Member]	Sep. 30, 2011 5.15% Notes Due 2020 [Member] Teco Finance [Member]	Mar. 22, 2010 7.20% Notes Due 2011 [Member]	Apr. 22, 2010 7.20% Notes Due 2011 [Member]	Sep. 30, 2010 7.20% Notes Due 2011 [Member]	Apr. 30, 2011 7.20% Notes Due 2011 [Member]	Mar. 22, 2010 7.20% Notes Due 2011 [Member] Teco Finance [Member]	Apr. 30, 2010 7.20% Notes Due 2011 [Member] Teco Finance [Member]	Mar. 22, 2010 7.0% Notes Due 2012 [Member]	Mar. 22, 2010 7.0% Notes Due 2012 [Member] Teco Finance [Member]	Apr. 30, 2010 Floating Rate Notes Due 2010 [Member] Teco Finance [Member]	Sep. 30, 2011 Premiums And Fees Expense [Member]	Mar. 01, 2011 PCIDA Bonds [Member]	Mar. 31, 2011 PCIDA Bonds [Member]	Sep. 30, 2011 PCIDA Bonds [Member]	Mar. 01, 2011 Tampa Electric Co [Member] PCIDA Bonds [Member]	Mar. 01, 2011 Tampa Electric Co [Member] PCIDA Bonds [Member]	Sep. 30, 2011 Tampa Electric Co [Member] PCIDA Bonds [Member]	Mar. 26, 2008 HCIDA Bonds [Member]	Mar. 26, 2008 Tampa Electric Co [Member] HCIDA Bonds [Member]	Mar. 22, 2010 Teco Finance [Member]	Sep. 30, 2011 Teco Finance [Member]	Feb. 18, 2011 Tampa Electric Co [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Sep. 30, 2010 Tampa Electric Co [Member]
Debt Instrument [Line Items]
Purchase in lieu of redemption				$ 150,800,000	$ 513,700,000																$ 75,000,000		$ 95,000,000	$ 75,000,000		$ 95,000,000	$ 20,000,000	$ 20,000,000				$ 78,800,000	$ 3,700,000
Aggregate principal amount issued		100,000,000					250,000,000			300,000,000		1,000
Principal amounts of notes redeemed												100,000,000
Redemption price of notes												1,066.38
Debt instrument maturity year																			2010
Stated interest rate								4.00%		5.15%				7.20%		7.20%	7.00%
Principal amount market price percentage							99.594%		99.552%
Debt instrument yield to maturity							4.077%		5.208%
Net proceeds																														543,500,000
Redeemable principal amount percentage		100.00%																												100.00%
Applicable treasury rate plus basis points	50																													25.00	50
Loss on debt extinguishment				0	(33,000,000)								6,600,000							25,500,000
Remaining unamortized debt issue costs				900,000
Interest at the initial term rate per annum																						1.50%			1.50%
Debt tender offer, purchase amount			70,000,000								43,000,000				156,900,000		27,000,000	73,100,000											230,000,000
Reconsolidated debt as a result of new accounting standards						$ 44,400,000

XML

Subsequent Events

9 Months Ended

Sep. 30, 2011

Subsequent Events

16. Subsequent Events

TECO Energy, Inc. $200 million bank credit facility amendment

On Oct. 25, 2011, TECO Energy, Inc. (TECO Energy) and its wholly-owned subsidiary, TECO Finance, Inc. (TECO Finance), amended their $200 million bank credit facility, entering into a Third Amended and Restated Credit Agreement with ten lenders. Under the amendment, TECO Finance continues to be the Borrower and TECO Energy continues to be the Guarantor. The amendment (i) extends the maturity date of the credit facility from May 9, 2012 to Oct. 25, 2016 (subject to further extension with the consent of each lender); (ii) continues to allow TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TECO Finance to borrow funds on a same-day basis under a new Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate (compared to $50 million in the aggregate under the previous agreement); (vi) continues to include a $200 million letter of credit facility and (vii) makes other technical changes.

Tampa Electric Company $325 million bank credit facility amendment

On Oct. 25, 2011, Tampa Electric Company (Tampa Electric) amended its $325 million bank credit facility, entering into a Third Amended and Restated Credit Agreement with ten lenders. The amendment (i) extends the maturity date of the credit facility from May 9, 2012 to Oct. 25, 2016 (subject to further extension with the consent of each lender); (ii) continues to allow Tampa Electric to borrow funds at a rate equal to the London interbank deposit rate plus a margin (iii) as an alternative to the above interest rate, allows Tampa Electric to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows Tampa Electric to borrow funds on a same-day basis under a new Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) continues to allow Tampa Electric to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility (compared to $50 million under the previous agreement); and (vii) makes other technical changes.

Tampa Electric Co [Member]

Subsequent Events

14. Subsequent Events

Tampa Electric Company $325 million bank credit facility amendment

On Oct. 25, 2011, Tampa Electric Company (Tampa Electric) amended its $325 million bank credit facility, entering into a Third Amended and Restated Credit Agreement with ten lenders. The amendment (i) extends the maturity date of the credit facility from May 9, 2012 to Oct. 25, 2016 (subject to further extension with the consent of each lender); (ii) continues to allow Tampa Electric to borrow funds at a rate equal to the London interbank deposit rate plus a margin (iii) as an alternative to the above interest rate, allows Tampa Electric to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows Tampa Electric to borrow funds on a same-day basis under a new Swingline Loan provision, which loans mature on the fourth Banking Day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant Swingline Lender prior to the making of any such loans; (v) continues to allow Tampa Electric to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility (compared to $50 million under the previous agreement); and (vii) makes other technical changes.

XML

Consolidated Condensed Statements Of Cash Flows (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash flows from operating activities
Net income	$ 219.6	$ 182.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	243.4	233.7
Deferred income taxes	117.5	136.5
Investment tax credits, net	(0.3)	(0.3)
Allowance for funds used during construction	(0.8)	(1.6)
Non-cash stock compensation	6.6	5.4
Gain on sale of business/assets, pretax	(0.5)	(0.9)
Non-cash debt extinguishment, pretax	0	0.9
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings	0	6.8
Deferred recovery clauses	3.6	44.6
Receivables, less allowance for uncollectibles	(9.4)	(82.0)
Inventories	39.7	(28.4)
Prepayments and other current assets	(4.4)	(4.3)
Taxes accrued	35.2	38.6
Interest accrued	23.2	23.7
Accounts payable	(26.9)	36.8
Other	25.1	0.7
Cash flows from operating activities	671.6	593.0
Cash flows from investing activities
Capital expenditures	(298.3)	(374.9)
Allowance for funds used during construction	0.8	1.6
Net proceeds from sale of business/assets	3.4	1.4
Net cash increase from consolidation	0	24.1
Contributions to unconsolidated affiliates	0	(1.7)
Other investments	14.4	(13.9)
Cash flows used in investing activities	(279.7)	(363.4)
Cash flows from financing activities
Dividends	(136.8)	(130.7)
Proceeds from the sale of common stock	6.6	5.6
Proceeds from long-term debt issuance	0	543.5
Repayment of long-term debt/Purchase in lieu of redemption	(150.8)	(513.7)
Dividend to noncontrolling interest	(0.6)	(0.7)
Net decrease in short-term debt	(12.0)	(28.0)
Cash flows used in financing activities	(293.6)	(124.0)
Net increase in cash and cash equivalents	98.3	105.6
Cash and cash equivalents at beginning of period	67.5	46.0
Cash and cash equivalents at end of period	165.8	151.6
Tampa Electric Co [Member]
Cash flows from operating activities
Net income	190.4	193.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	202.4	195.3
Deferred income taxes	79.0	27.7
Investment tax credits, net	(0.3)	(0.3)
Allowance for funds used during construction	(0.8)	(1.6)
Deferred recovery clauses	3.6	44.6
Receivables, less allowance for uncollectibles	10.9	(69.9)
Inventories	30.1	(31.8)
Prepayments	(2.7)	(1.8)
Taxes accrued	81.4	65.9
Interest accrued	21.9	16.8
Accounts payable	(33.6)	17.7
Gain on sale of assets, pretax	(0.2)	(0.2)
Other	20.1	5.0
Cash flows from operating activities	602.2	460.9
Cash flows from investing activities
Capital expenditures	(248.3)	(295.2)
Allowance for funds used during construction	0.8	1.6
Net proceeds from sale of assets	2.8	0
Cash flows used in investing activities	(244.7)	(293.6)
Cash flows from financing activities
Dividends	(159.3)	(174.9)
Proceeds from the sale of common stock	0	50.0
Repayment of long-term debt/Purchase in lieu of redemption	(78.8)	(3.7)
Net decrease in short-term debt	(12.0)	(28.0)
Cash flows used in financing activities	(250.1)	(156.6)
Net increase in cash and cash equivalents	107.4	10.7
Cash and cash equivalents at beginning of period	3.7	5.5
Cash and cash equivalents at end of period	$ 111.1	$ 16.2

XML

Other Comprehensive Income

9 Months Ended

Sep. 30, 2011

Other Comprehensive Income

8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (OCI) for the three and nine months ended Sep. 30, 2011 and 2010, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company's pension plans:

Other Comprehensive Income

	Three months ended Sep. 30,									Nine months ended Sep. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2011
Unrealized (loss) gain on cash flow hedges	$	(2.1	)	$	0.8		$	(1.3	)	$	0.8		$	(0.3	)	$	0.5
Less: Gain reclassified to net income		(0.8	)		0.3			(0.5	)		(2.3	)		0.9			(1.4	)
Loss on cash flow hedges		(2.9	)		1.1			(1.8	)		(1.5	)		0.6			(0.9	)
Amortization of unrecognized benefit costs and other		0.7			(0.3	)		0.4			1.9			(0.7	)		1.2
Total other comprehensive (loss) income	$	(2.2	)	$	0.8		$	(1.4	)	$	0.4		$	(0.1	)	$	0.3
2010
Unrealized gain (loss) on cash flow hedges	$	0.9		$	(0.2	)	$	0.7		$	(0.5	)	$	0.2		$	(0.3	)
Plus: Loss reclassified to net income		1.2			(0.5	)		0.7			3.4			(1.3	)		2.1
Gain on cash flow hedges		2.1			(0.7	)		1.4			2.9			(1.1	)		1.8
Amortization of unrecognized benefit costs and other		0.6			(0.2	)		0.4			1.8			0.8			2.6
Recognized benefit costs due to settlement		0.0			0.0			0.0			1.6			(0.6	)		1.0
Total other comprehensive income	$	2.7		$	(0.9	)	$	1.8		$	6.3		$	(0.9	)	$	5.4

Accumulated Other Comprehensive Loss

(millions)	Sep. 30, 2011			Dec. 31, 2010
Unrecognized pension losses and prior service costs(1)	$	(25.5	)	$	(26.6	)
Unrecognized other benefit gains, prior service costs and transition obligations(2)		13.7			13.6
Net unrealized losses from cash flow hedges(3)		(5.1	)		(4.2	)
Total accumulated other comprehensive loss	$	(16.9	)	$	(17.2	)

(1) Net of tax benefit of $15.7 million and $16.2 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

(2) Net of tax expense of $5.9 million and $5.8 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

(3) Net of tax benefit of $3.3 million and $2.7 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

Tampa Electric Co [Member]

Other Comprehensive Income

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Sep. 30,							Nine months ended Sep. 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2011
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.9	$	(0.4	)	$	0.5
2010
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2	$	0.9	$	(0.3	)	$	0.6

Accumulated Other Comprehensive Loss

(millions)	Sep. 30, 2011			Dec. 31, 2010
Net unrealized losses from cash flow hedges (1)	$	(4.8	)	$	(5.3	)
Total accumulated other comprehensive loss	$	(4.8	)	$	(5.3	)

(1) Net of tax benefit of $3.0 million and $3.4 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

XML

Accounting For Derivative Instruments And Hedging Activities (Energy Related Derivatives) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Current regulatory assets	$ 55.8		$ 62.7
Current regulatory liabilities	95.5		110.0
Long-term regulatory assets	331.2		341.9
Long-term regulatory liabilities	637.5		630.8
Regulatory assets	387.0		404.6
Regulatory liabilities	733.0		740.8
Tampa Electric Co [Member] | Energy Related Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	29.5	[1]
Current regulatory liabilities	0	[1]
Long-term regulatory assets	4.5	[1]
Long-term regulatory liabilities	0	[1]
Regulatory assets	34.0	[1]
Regulatory liabilities	0	[1]
Energy Related Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	29.5
Current regulatory liabilities	0
Long-term regulatory assets	4.5
Long-term regulatory liabilities	0
Regulatory assets	34.0
Regulatory liabilities	0
Tampa Electric Co [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	55.8		62.7
Current regulatory liabilities	95.5		110.0
Long-term regulatory assets	331.2		341.9
Long-term regulatory liabilities	637.5		630.8
Regulatory assets	387.0		404.6
Regulatory liabilities	$ 733.0		$ 740.8

[1] Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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.

XML

Accounting For Derivative Instruments And Hedging Activities (Fair Value Of The Overall Contractual Contingent Liability Positions) (Details) (USD $) In Millions	Sep. 30, 2011
Fair Value Asset/ (Liability)	$ (35.1)
Derivative Exposure Asset/ (Liability)	(35.1)
Posted Collateral	0
Tampa Electric Co [Member]
Fair Value Asset/ (Liability)	(34.0)
Derivative Exposure Asset/ (Liability)	(34.0)
Posted Collateral	$ 0

XML

Fair Value Measurements (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Schedule Of Recurring Fair Value Measures

	At fair value as of Sep. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Diesel fuel swaps		0.0		1.5		0.0		1.5
Total	$	0.0	$	1.5	$	0.0	$	1.5
Liabilities
Natural gas swaps	$	0.0	$	34.0	$	0.0	$	34.0
Diesel fuel swaps		0.0		1.5		0.0		1.5
Total	$	0.0	$	35.5	$	0.0	$	35.5
	At fair value as of Dec. 31, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.1	$	0.0	$	1.1
Diesel fuel swaps		0.0		1.8		0.0		1.8
Total	$	0.0	$	2.9	$	0.0	$	2.9
Liabilities
Natural gas swaps	$	0.0	$	29.8	$	0.0	$	29.8
Total	$	0.0	$	29.8	$	0.0	$	29.8

Tampa Electric Co [Member]

Schedule Of Recurring Fair Value Measures

	At fair value as of Sep. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Total	$	0.0	$	0.0	$	0.0	$	0.0
Liabilities
Natural gas swaps	$	0.0	$	34.0	$	0.0	$	34.0
Total	$	0.0	$	34.0	$	0.0	$	34.0

	At fair value as of Dec. 31, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	1.1	$	0.0	$	1.1
Total	$	0.0	$	1.1	$	0.0	$	1.1
Liabilities
Natural gas swaps	$	0.0	$	29.8	$	0.0	$	29.8
Total	$	0.0	$	29.8	$	0.0	$	29.8

XML

Accounting For Derivative Instruments And Hedging Activities

9 Months Ended

Sep. 30, 2011

Accounting For Derivative Instruments And Hedging Activities

12. 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 diesel fuel 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 accounting standards for derivative instruments and hedging activities. 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.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

The 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 Sep. 30, 2011, 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 Sep. 30, 2011 and Dec. 31, 2010:

Total Derivatives⁽¹⁾

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	1.3	$	2.7
Long-term assets		0.2		0.2
Total assets	$	1.5	$	2.9
Current liabilities	$	29.5	$	27.2
Long-term liabilities		6.0		2.6
Total liabilities	$	35.5	$	29.8

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The following table presents the derivative hedges of diesel fuel swaps and option contracts at Sep. 30, 2011 and Dec. 31, 2010 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	1.3	$	1.6
Long-term assets		0.2		0.2
Total assets	$	1.5	$	1.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		1.5		0.0
Total liabilities	$	1.5	$	0.0

The following table presents the derivative hedges of natural gas contracts at Sep. 30, 2011 and Dec. 31, 2010 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives

(millions)	Sep. 30, 2011		Dec. 31, 2010
Current assets	$	0.0	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.0	$	1.1
Current liabilities	$	29.5	$	27.2
Long-term liabilities		4.5		2.6
Total liabilities	$	34.0	$	29.8

The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Sep. 30, 2011 is a net loss of $5.1 million after tax and accumulated amortization. This compares to a net loss of $4.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2010.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at Sep. 30, 2011:

Derivatives Designated As Hedging Instruments

	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2011	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	1.3	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.2	Derivative liabilities		1.5
Natural gas derivatives:
Current	Derivative assets		0.0	Derivative liabilities		29.5
Long-term	Derivative assets		0.0	Derivative liabilities		4.5
Total derivatives designated as hedging instruments		$	1.5		$	35.5

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sep. 30, 2011:

Energy Related Derivatives

	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2011	Balance  Sheet Location(1)	Fair Value		Balance  Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.0	Regulatory assets	$	29.5
Long-term	Regulatory liabilities		0.0	Regulatory assets		4.5
Total		$	0.0		$	34.0

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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 Sep. 30, 2011, net pretax losses of $29.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The following tables present the effect of hedging instruments on OCI and income for the three months and nine months ended Sep. 30:

For the three months ended Sep. 30:

(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 Cash Flow Hedging Relationships	Effective Portion(1)				Effective Portion(1)
2011
Interest rate contracts:	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(1.3	)	Mining related costs		0.7
Total	$	(1.3	)		$	0.5
2010
Interest rate contracts:	$	0.0		Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		0.7		Mining related costs		(0.3	)
Total	$	0.7			$	(0.7	)

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

For the nine months ended Sep. 30:

(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 Cash Flow Hedging Relationships	Effective Portion(1)				Effective Portion(1)
2011
Interest rate contracts:	$	0.0		Interest expense	$	(0.5	)
Commodity contracts:
Diesel fuel derivatives		0.6		Mining related costs		2.0
Total	$	0.6			$	1.5
2010
Interest rate contracts:	$	(0.1	)	Interest expense	$	(1.2	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)	Mining related costs		(0.9	)
Total	$	(0.3	)		$	(2.1	)

(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 and nine months ended Sep. 30, 2011 and 2010, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sep. 30:

For the nine months ended Sep. 30:

(millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI(1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income(1)
2011
Interest rate swaps	$	0.0		$	0.0		$	(0.5	)
Diesel fuel derivatives		0.0			0.6			2.0
Total	$	0.0		$	0.6		$	1.5
2010
Interest rate swaps	$	(0.3	)	$	(0.1	)	$	(1.2	)
Diesel fuel derivatives		0.3			(0.2	)		(0.9	)
Total	$	0.0		$	(0.3	)	$	(2.1	)

(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, 2014 for both financial natural gas and financial diesel fuel contracts. The following table presents by commodity type the company's derivative volumes that, as of Sep. 30, 2011, are expected to settle during the 2011, 2012, 2013 and 2014 fiscal years:

(millions) Year	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
	Physical		Financial		Physical		Financial
2011		0.0		2.4		0.0		11.6
2012		0.0		2.6		0.0		35.0
2013		0.0		1.8		0.0		5.0
2014		0.0		1.0		0.0		0.0
Total		0.0		7.8		0.0		51.6

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 Sep. 30, 2011, all of the counterparties with transaction amounts outstanding in the company's energy portfolio are rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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 its 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.

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 Sep. 30, 2011:

Contingent Features

(millions) At Sep. 30, 2011	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(35.1	)	$	(35.1	)	$	0.0

Tampa Electric Co [Member]

Accounting For Derivative Instruments And Hedging Activities

10. 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.

Tampa Electric Company applies the accounting standards for derivatives and hedging. 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.

Tampa Electric Company applies accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for the regulated companies. These standards, 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 ( see Note 3).

Tampa Electric Company's physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if Tampa Electric Company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if Tampa Electric Company intends to receive physical delivery and if the transaction is reasonable in relation to Tampa Electric Company's business needs. As of Sep. 30, 2011, 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 Sep. 30, 2011 and Dec. 31, 2010 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)	Sep.  30, 2011		Dec.  31, 2010
Current assets	$	0.0	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.0	$	1.1
Current liabilities(1)	$	29.5	$	27.2
Long-term liabilities		4.5		2.6
Total liabilities	$	34.0	$	29.8

(1) Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

The ending balance in AOCI related to previously settled interest rate swaps at Sep. 30, 2011 is a net loss of $4.8 million after tax and accumulated amortization. This compares to a net loss of $5.3 million in AOCI after tax and accumulated amortization at Dec. 31, 2010.

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sep. 30, 2011:

Energy Related Derivatives

	Asset Derivatives				Liability Derivatives
(millions) at Sep. 30, 2011	Balance Sheet Location(1)		Fair              Value		Balance Sheet Location(1)		Fair              Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	0.0		Regulatory assets	$	29.5
Long-term		Regulatory liabilities		0.0		Regulatory assets		4.5
Total			$	0.0			$	34.0

(1) Natural gas derivatives are deferred in accordance with accounting standards for regulated operations 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 Sep. 30, 2011, net pretax losses of $29.5 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 three and nine months ended Sep. 30:

(millions)	Location of Loss Reclassified From AOCI Into Income	Amount of Loss Reclassified From AOCI Into Income(1)
Derivatives in Cash Flow Hedging Relationships	Effective Portion(1)	Three months ended Sep. 30:			Nine months ended Sep. 30:
2011
Interest rate contracts:	Interest expense	($	0.2	)	($	0.5	)
Total		($	0.2	)	($	0.5	)
2010
Interest rate contracts:	Interest expense	($	0.2	)	($	0.6	)
Total		($	0.2	)	($	0.6	)

(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 and nine months ended Sep. 30, 2011 and 2010, 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, 2013 for the financial natural gas contracts. The following table presents by commodity type the company's derivative volumes that, as of Sep. 30, 2011, are expected to settle during the 2011, 2012 and 2013 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2011		0.0		11.6
2012		0.0		35.0
2013		0.0		5.0
Total		0.0		51.6

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. Tampa Electric 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 Tampa Electric 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, Tampa Electric Company could suffer a material financial loss. However, as of Sep. 30, 2011, substantially all of the counterparties with transaction amounts outstanding in Tampa Electric Company's energy portfolio are rated investment grade by the major 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. Tampa Electric Company generally enters into the following master arrangements: (1) EEI agreements — standardized power sales contracts in the electric industry; (2) ISDA agreements — standardized financial gas and electric contracts; and (3) NAESB agreements — 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 its 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.

Certain of Tampa Electric Company 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 Sep. 30, 2011:

Contingent Features

(millions) At Sep. 30, 2011	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	$	(34.0	)	$	(34.0	)	$	0.0

XML

Consolidated Condensed Balance Sheets (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 165.8		$ 67.5
Short-term investments	0		14.8
Receivables, less allowance for uncollectibles	342.8		333.4
Inventories, at average cost
Fuel	124.1		169.5
Materials and supplies	83.8		78.1
Current derivative assets	1.3	[1]	2.7	[1]
Current regulatory assets	55.8		62.7
Deferred tax asset	76.3		0
Prepayments and other current assets	33.5		28.5
Income tax receivables/Taxes receivable	0.2		0.4
Total current assets	883.6		757.6
Property, plant and equipment
Electric	6,697.3		6,558.9
Gas	1,145.4		1,115.0
Construction work in progress	191.0		212.4
Other property	428.6		398.5
Property, plant and equipment	8,462.3		8,284.8
Accumulated depreciation	(2,578.3)		(2,443.8)
Total property, plant and equipment, net	5,884.0		5,841.0
Other assets/Deferred debits
Deferred income taxes, net	0		57.3
Long-term regulatory assets	331.2		341.9
Long-term derivative assets	0.2	[1]	0.2	[1]
Goodwill	55.4		55.4
Deferred charges and other assets	141.5		141.2
Total other assets/Total deferred debits	528.3		596.0
Total assets	7,295.9		7,194.6
Current liabilities
Recourse	374.9		67.1
Non-recourse	11.2		11.2
Notes payable	0		12.0
Accounts payable	252.5		281.5
Customer deposits	158.3		156.5
Current regulatory liabilities	95.5		110.0
Current derivative liabilities	29.5	[1]	27.2	[1]
Interest accrued	62.1		42.4
Taxes accrued	61.2		26.2
Other current liabilities	19.4		18.2
Total current liabilities	1,064.6		752.3
Other liabilities/Deferred credits
Deferred income taxes, net	138.3		0
Investment tax credits	10.1		10.4
Long-term regulatory liabilities	637.5		630.8
Long-term derivative liabilities	6.0	[1]	2.6	[1]
Deferred credits and other liabilities	487.0		479.8
Long-term debt, less amount due within one year
Recourse	2,664.9		3,114.6
Non-recourse	25.1		33.5
Total other liabilities/Total deferred credits	3,968.9		4,271.7
Commitments and Contingencies
Capital
Common equity	215.8		214.9
Additional paid in capital	1,550.4		1,542.0
Retained earnings	512.6		430.0
Accumulated other comprehensive loss	(16.9)		(17.2)
Total TECO Energy, Inc. capital	2,261.9		2,169.7
Noncontrolling interest	0.5		0.9
Total capital	2,262.4		2,170.6
Total liabilities and capital	7,295.9		7,194.6
Tampa Electric Co [Member]
Current assets
Cash and cash equivalents	111.1		3.7
Receivables, less allowance for uncollectibles	253.7		264.6
Inventories, at average cost
Fuel	84.2		119.0
Materials and supplies	63.8		59.1
Current derivative assets	0		1.1
Current regulatory assets	55.8		62.7
Deferred tax asset	28.7		1.5
Prepayments and other current assets	12.7		10.0
Income tax receivables/Taxes receivable	0		24.6
Total current assets	610.0		546.3
Property, plant and equipment
Electric	6,481.6		6,343.4
Gas	1,089.9		1,060.6
Construction work in progress	185.6		206.8
Other property	5.7		4.7
Property, plant and equipment	7,757.1		7,610.8
Accumulated depreciation	(2,202.7)		(2,093.9)
Public Utilities, Property, Plant and Equipment, Net, Total	5,554.4		5,516.9
Total property, plant and equipment, net	5,560.1		5,521.6
Other assets/Deferred debits
Long-term regulatory assets	331.2		341.9
Unamortized debt expense	15.0		17.8
Other	9.9		10.9
Total other assets/Total deferred debits	356.1		370.6
Total assets	6,526.2		6,438.5
Current liabilities
Notes payable	0		12.0
Long-term debt due within one year	374.9		3.4
Accounts payable	184.2		219.0
Customer deposits	158.3		156.5
Current regulatory liabilities	95.5		110.0
Current derivative liabilities	29.5		27.2
Interest accrued	46.5		24.6
Taxes accrued	70.8		14.0
Other current liabilities	12.2		12.2
Total current liabilities	971.9		578.9
Other liabilities/Deferred credits
Deferred income taxes, net	737.0		631.5
Investment tax credits	10.1		10.4
Long-term regulatory liabilities	637.5		630.8
Long-term derivative liabilities	4.5		2.6
Other	359.2		360.0
Long-term debt, less amount due within one year
Total other liabilities/Total deferred credits	1,748.3		1,635.3
Commitments and Contingencies
Capital
Common equity	1,852.4		1,852.4
Retained earnings	342.1		311.1
Accumulated other comprehensive loss	(4.8)		(5.3)
Total capital	2,189.7		2,158.2
Total liabilities and capital	6,526.2		6,438.5
Long-term debt, less amount due within one year	1,616.3		2,066.1
Total capitalization	$ 3,806.0		$ 4,224.3

[1] Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

XML

Regulatory (Narrative) (Details) (Tampa Electric Co [Member], USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Tampa Electric Co [Member]
Annual accrual, storm damage reserve	$ 8.0
Storm damage reserve	$ 41.5	$ 37.4

XML

Commitments And Contingencies (Letters Of Credit And Guarantees) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Guarantees Fuel Purchase Energy Management [Member] | Other Subsidiaries [Member]
Product Liability Contingency [Line Items]
2011	$ 0	[1]
2012-2015	0	[1]
After 2015	109.7	[1],[2]
Total	109.7	[1]
Liabilities Recognized at June 30, 2011	1.1	[1]
Tampa Electric Co [Member] | Letters Of Credit [Member]
Product Liability Contingency [Line Items]
2011	0
2012-2015	0
After 2015	0.7	[2]
Total	0.7
Liabilities Recognized at June 30, 2011	0.2
Guarantees Fuel Purchase Related [Member] | Teco Coal [Member]
Product Liability Contingency [Line Items]
2011	0	[1]
2012-2015	0	[1]
After 2015	5.4	[1],[2]
Total	5.4	[1]
Liabilities Recognized at June 30, 2011	1.1	[1]
Teco Coal [Member]
Product Liability Contingency [Line Items]
2011	0
2012-2015	0
After 2015	5.4	[2]
Total	5.4
Liabilities Recognized at June 30, 2011	1.1
Other Subsidiaries [Member]
Product Liability Contingency [Line Items]
2011	0
2012-2015	0
After 2015	115.1	[2]
Total	115.1
Liabilities Recognized at June 30, 2011	2.2
Tampa Electric Co [Member]
Product Liability Contingency [Line Items]
2011	0
2012-2015	0
After 2015	0.7	[2]
Total	0.7
Liabilities Recognized at June 30, 2011	$ 0.2

[1] The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sep. 30, 2011. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

[2] These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2015.

XML

Accounting For Derivative Instruments And Hedging Activities (Derivative Activity For Instruments Classified As Qualifying Cash Flow Hedges) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Derivatives, Fair Value [Line Items]
Fair Value Asset/(Liability)	$ 0		$ 0		$ 0		$ 0
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(1.3)	[1]	0.7	[1]	0.6	[1]	(0.3)	[1]
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	0.5	[1]	(0.7)	[1]	1.5	[1]	(2.1)	[1]
Interest Rate Swaps [Member]
Derivatives, Fair Value [Line Items]
Fair Value Asset/(Liability)	0		(0.3)		0		(0.3)
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	[1]	0	[1]	0	[1]	(0.1)	[1]
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	(0.2)	[1]	(0.4)	[1]	(0.5)	[1]	(1.2)	[1]
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Fair Value Asset/(Liability)	0		0.3		0		0.3
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(1.3)	[1]	0.7	[1]	0.6	[1]	(0.2)	[1]
Amount of Gain/(Loss) Reclassified From AOCI Into Income Effective Portion	$ 0.7	[1]	$ (0.3)	[1]	$ 2.0	[1]	$ (0.9)	[1]

[1] Changes in OCI and AOCI are reported in after-tax dollars.

XML

Other Comprehensive Income (Other Comprehensive Income) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Unrealized gain (loss) on cash flow hedges, Gross	$ (2.1)	$ 0.9	$ 0.8	$ (0.5)
Unrealized gain (loss) on cash flow hedges, Tax	0.8	(0.2)	(0.3)	0.2
Unrealized gain (loss) on cash flow hedges, Net	(1.3)	0.7	0.5	(0.3)
Loss reclassified to net income, Gross	(0.8)	1.2	(2.3)	3.4
Loss reclassified to net income, Tax	(0.3)	(0.5)	0.9	(1.3)
Loss reclassified to net income, Net	(0.5)	0.7	(1.4)	2.1
Gain on cash flow hedges, Gross	(2.9)	2.1	(1.5)	2.9
Gain on cash flow hedges, Tax	1.1	(0.7)	0.6	(1.1)
Gain on cash flow hedges, Net	(1.8)	1.4	(0.9)	1.8
Amortization of unrecognized benefit costs and other, Gross	0.7	0.6	1.9	1.8
Amortization of unrecognized benefit costs and other, Tax	(0.3)	(0.2)	(0.7)	0.8
Amortization of unrecognized benefit costs and other, Net	0.4	0.4	1.2	2.6
Recognized benefit costs due to settlement, Gross		0		1.6
Recognized benefit costs due to settlement, Tax		0		(0.6)
Recognized benefit costs due to settlement, Net		0		1.0
Total other comprehensive income, Gross	(2.2)	2.7	0.4	6.3
Total other comprehensive income, Tax	0.8	(0.9)	(0.1)	(0.9)
Total other comprehensive income, Net	(1.4)	1.8	0.3	5.4
Tampa Electric Co [Member]
Unrealized gain (loss) on cash flow hedges, Gross	0	0	0	0
Unrealized gain (loss) on cash flow hedges, Tax	0	0	0	0
Unrealized gain (loss) on cash flow hedges, Net	0	0	0	0
Loss reclassified to net income, Gross	0.3	0.3	0.9	0.9
Loss reclassified to net income, Tax	(0.1)	(0.1)	(0.4)	(0.3)
Loss reclassified to net income, Net	0.2	0.2	0.5	0.6
Gain on cash flow hedges, Gross	0.3	0.3	0.9	0.9
Gain on cash flow hedges, Tax	(0.1)	(0.1)	(0.4)	(0.3)
Gain on cash flow hedges, Net	0.2	0.2	0.5	0.6
Total other comprehensive income, Gross	0.3	0.3	0.9	0.9
Total other comprehensive income, Tax	(0.1)	(0.1)	(0.4)	(0.3)
Total other comprehensive income, Net	$ 0.2	$ 0.2	$ 0.5	$ 0.6

XML

Other Comprehensive Income (Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Unrecognized pension losses and prior service costs	$ (25.5)	[1]	$ (26.6)	[1]
Unrecognized other benefit gains, prior service costs and transition obligations	13.7	[2]	13.6	[2]
Net unrealized losses from cash flow hedges	(5.1)	[3]	(4.2)	[3]
Accumulated Other Comprehensive Income (Loss)	(16.9)		(17.2)
Unrecognized pension losses and prior service costs, tax benefit	15.7		16.2
Unrecognized other benefit gains, prior service costs and transition obligations, tax expense	5.9		5.8
Net unrealized losses from cash flow hedges, tax benefit	3.3		2.7
Tampa Electric Co [Member]
Net unrealized losses from cash flow hedges	(4.8)	[4]	(5.3)	[4]
Accumulated Other Comprehensive Income (Loss)	(4.8)		(5.3)
Net unrealized losses from cash flow hedges, tax benefit	$ 3.0		$ 3.4

[1] Net of tax benefit of $15.7 million and $16.2 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

[2] Net of tax expense of $5.9 million and $5.8 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

[3] Net of tax benefit of $3.3 million and $2.7 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

[4] Net of tax benefit of $3.0 million and $3.4 million as of Sep. 30, 2011 and Dec. 31, 2010, respectively.

XML

Accounting For Derivative Instruments And Hedging Activities (Derivatives Designated As Hedging Instruments) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Current assets	$ 1.3	[1]	$ 2.7	[1]
Long-term derivative assets	0.2	[1]	0.2	[1]
Total assets	1.5	[1]	2.9	[1]
Current liabilities	29.5	[1]	27.2	[1]
Long-term derivative liabilities	6.0	[1]	2.6	[1]
Total liabilities	35.5	[1]	29.8	[1]
Designated As Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total assets	1.5
Total liabilities	35.5
Designated As Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0
Long-term derivative assets	0
Current liabilities	29.5
Long-term derivative liabilities	4.5
Designated As Hedging Instrument [Member] | Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	1.3
Long-term derivative assets	0.2
Current liabilities	0
Long-term derivative liabilities	1.5
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0		1.1
Long-term derivative assets	0		0
Total assets	0		1.1
Current liabilities	29.5		27.2
Long-term derivative liabilities	4.5		2.6
Total liabilities	34.0		29.8
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	1.3		1.6
Long-term derivative assets	0.2		0.2
Total assets	1.5		1.8
Current liabilities	0		0
Long-term derivative liabilities	1.5		0
Total liabilities	$ 1.5		$ 0

[1] Amounts presented above are on a gross basis, with asset and liability positions netted by counterparty in accordance with accounting standards for derivatives and hedging.

XML

Regulatory (Schedule Of Regulatory Assets And Regulatory Liabilities) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended				9 Months Ended																																																																																																1 Months Ended
	Jun. 30, 2011	Apr. 30, 2011	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Maximum [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Maximum [Member]	Sep. 30, 2011 Minimum [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Minimum [Member]	Sep. 30, 2011 Regulatory Tax Asset [Member]		Dec. 31, 2010 Regulatory Tax Asset [Member]		Sep. 30, 2011 Tampa Electric Co [Member] Regulatory Tax Asset [Member]		Dec. 31, 2010 Tampa Electric Co [Member] Regulatory Tax Asset [Member]		Sep. 30, 2011 Cost Recovery Clauses [Member]	Dec. 31, 2010 Cost Recovery Clauses [Member]	Sep. 30, 2011 Cost Recovery Clauses [Member]	Dec. 31, 2010 Cost Recovery Clauses [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Cost Recovery Clauses [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Cost Recovery Clauses [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Cost Recovery Clauses [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Cost Recovery Clauses [Member]	Sep. 30, 2011 Postretirement Benefit Asset [Member]	Dec. 31, 2010 Postretirement Benefit Asset [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Postretirement Benefit Asset [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Postretirement Benefit Asset [Member]	Sep. 30, 2011 Environmental Remediation [Member]	Dec. 31, 2010 Environmental Remediation [Member]	Sep. 30, 2011 Environmental Remediation [Member]	Dec. 31, 2010 Environmental Remediation [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Environmental Remediation [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Environmental Remediation [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Environmental Remediation [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Environmental Remediation [Member]	Sep. 30, 2011 Competitive Rate Adjustment [Member]	Dec. 31, 2010 Competitive Rate Adjustment [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Competitive Rate Adjustment [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Competitive Rate Adjustment [Member]	Sep. 30, 2011 Other Regulatory Asset [Member]	Dec. 31, 2010 Other Regulatory Asset [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Other Regulatory Asset [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Other Regulatory Asset [Member]	Sep. 30, 2011 Total Other Regulatory Assets [Member]	Dec. 31, 2010 Total Other Regulatory Assets [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Total Other Regulatory Assets [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Total Other Regulatory Assets [Member]	Sep. 30, 2011 Deferred Income Tax Charges [Member]		Dec. 31, 2010 Deferred Income Tax Charges [Member]		Sep. 30, 2011 Deferred Income Tax Charges [Member]		Dec. 31, 2010 Deferred Income Tax Charges [Member]		Sep. 30, 2011 Tampa Electric Co [Member] Deferred Income Tax Charges [Member]		Dec. 31, 2010 Tampa Electric Co [Member] Deferred Income Tax Charges [Member]		Sep. 30, 2011 Tampa Electric Co [Member] Deferred Income Tax Charges [Member]		Dec. 31, 2010 Tampa Electric Co [Member] Deferred Income Tax Charges [Member]		Sep. 30, 2011 Deferred Bond Refinancing Costs [Member]		Dec. 31, 2010 Deferred Bond Refinancing Costs [Member]		Sep. 30, 2011 Tampa Electric Co [Member] Deferred Bond Refinancing Costs [Member]		Dec. 31, 2010 Tampa Electric Co [Member] Deferred Bond Refinancing Costs [Member]		Sep. 30, 2011 Deferred Gain On Property Sales [Member]		Dec. 31, 2010 Deferred Gain On Property Sales [Member]		Sep. 30, 2011 Tampa Electric Co [Member] Deferred Gain On Property Sales [Member]		Dec. 31, 2010 Tampa Electric Co [Member] Deferred Gain On Property Sales [Member]		Sep. 30, 2011 Total Other Regulatory Liabilities [Member]	Dec. 31, 2010 Total Other Regulatory Liabilities [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Total Other Regulatory Liabilities [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Total Other Regulatory Liabilities [Member]	Sep. 30, 2011 Storm Damage Reserve [Member]	Dec. 31, 2010 Storm Damage Reserve [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Storm Damage Reserve [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Storm Damage Reserve [Member]	Sep. 30, 2011 Provision For Stipulation And Other [Member]		Dec. 31, 2010 Provision For Stipulation And Other [Member]		Sep. 30, 2011 Tampa Electric Co [Member] Provision For Stipulation And Other [Member]		Dec. 31, 2010 Tampa Electric Co [Member] Provision For Stipulation And Other [Member]		Sep. 30, 2011 Accumulated Reserve-Cost Of Removal [Member]	Dec. 31, 2010 Accumulated Reserve-Cost Of Removal [Member]	Sep. 30, 2011 Tampa Electric Co [Member] Accumulated Reserve-Cost Of Removal [Member]	Dec. 31, 2010 Tampa Electric Co [Member] Accumulated Reserve-Cost Of Removal [Member]	Jun. 30, 2011 Tampa Electric Co [Member]	Apr. 30, 2011 Tampa Electric Co [Member]	Sep. 30, 2011 Tampa Electric Co [Member]	Dec. 31, 2010 Tampa Electric Co [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets			$ 387.0	$ 404.6					$ 64.4	[1]	$ 66.6	[1]	$ 64.4	[2]	$ 66.6	[2]	$ 38.0	$ 41.9			$ 38.0	$ 41.9			$ 228.9	$ 237.5	$ 228.9	$ 237.5	$ 23.2	$ 23.6			$ 23.2	$ 23.6			$ 3.2	$ 3.3	$ 3.2	$ 3.3	$ 17.1	$ 16.3	$ 17.1	$ 16.3	$ 322.6	$ 338.0	$ 322.6	$ 338.0	$ 64.4	[3]	$ 66.6	[3]					$ 64.4	[3]	$ 66.6	[3]					$ 12.2	[4]	$ 15.4	[4]	$ 12.2	[4]	$ 15.4	[4]																															$ 387.0	$ 404.6
Current regulatory assets			55.8	62.7																																																																																																			55.8	62.7
Long-term regulatory assets			331.2	341.9																																																																																																			331.2	341.9
Regulatory liabilities			733.0	740.8															70.7	76.2			70.7	76.2							21.2	21.2			21.2	21.2																	16.7	[3]	17.7	[3]					16.7	[3]	17.7	[3]									5.4	[5]	6.3	[5]	5.4	[5]	6.3	[5]	716.3	723.1	716.3	723.1	41.5	37.4	41.5	37.4	0.8	[6]	9.8	[6]	0.8	[6]	9.8	[6]	576.7	572.2	576.7	572.2			733.0	740.8
Current regulatory liabilities			95.5	110.0																																																																																																			95.5	110.0
Long-term regulatory liabilities			637.5	630.8																																																																																																			637.5	630.8
Amortization period					5	5	4	4
Stipulation earnings	11.75%	11.75%																																																																																																				11.75%
One time reduction to customers bills	$ 6.2	$ 3.0																																																																																																			$ 6.2	$ 3.0

[1] "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.

[2] "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.

[3] Primarily related to plant life and derivative positions.

[4] Amortized over the term of the related debt instruments.

[5] Amortized over a 4 or 5-year period with various ending dates.

[6] Includes a provision to reflect the FPSC-approved PGS stipulation regarding PGS's 2010 earnings above 11.75%. A one-time credit to customer bills totaling $3.0 million was applied in April 2011 and the $6.2 million remaining balance of the 2010 earnings above 11.75% was credited to accumulated depreciation reserves in June 2011.