UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 Aug. 1, 2011 was 215,722,727. As of Aug. 1, 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 Jun. 30, 2011 and Dec. 31, 2010, and the results of their operations and cash flows for the periods ended Jun. 30, 2011 and 2010. The results of operations for the three month and six month periods ended Jun. 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 29 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

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

2

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Jun. 30 2011		Dec. 31, 2010
Current assets
Cash and cash equivalents	$	61.8	$	67.5
Short-term investments		0.0		14.8
Receivables, less allowance for uncollectables of $4.5 and $4.5 at Jun. 30, 2011 and Dec. 31, 2010, respectively		335.4		333.4
Inventories, at average cost
Fuel		150.6		169.5
Materials and supplies		83.2		78.1
Current derivative asset		3.2		2.7
Current regulatory assets		43.9		62.7
Prepayments and other current assets		32.0		28.5
Income tax receivables		0.1		0.4
Total current assets		710.2		757.6
Property, plant and equipment
Utility plant in service
Electric		6,594.6		6,558.9
Gas		1,135.3		1,115.0
Construction work in progress		243.8		212.4
Other property		413.7		398.5
Property, plant and equipment		8,387.4		8,284.8
Accumulated depreciation		(2,528.9)		(2,443.8)
Total property, plant and equipment, net		5,858.5		5,841.0
Other assets
Deferred income taxes, net		0.0		57.3
Long-term regulatory assets		331.9		341.9
Long-term derivative assets		0.6		0.2
Goodwill		55.4		55.4
Deferred charges and other assets		141.4		141.2
Total other assets		529.3		596.0
Total assets	$	7,098.0	$	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)	Jun. 30, 2011		Dec. 31, 2010
Current liabilities
Long-term debt due within one year
Recourse	$	121.9	$	67.1
Non-recourse		11.2		11.2
Notes payable		32.0		12.0
Accounts payable		238.2		281.5
Customer deposits		158.2		156.5
Current regulatory liabilities		103.0		110.0
Current derivative liabilities		12.6		27.2
Interest accrued		43.5		42.4
Taxes accrued		48.2		26.2
Other current liabilities		18.2		18.2
Total current liabilities		787.0		752.3
Other liabilities
Deferred income taxes, net		14.9		0.0
Investment tax credits		10.2		10.4
Long-term regulatory liabilities		632.2		630.8
Long-term derivative liabilities		1.5		2.6
Deferred credits and other liabilities		486.9		479.8
Long-term debt, less amount due within one year
Recourse		2,921.2		3,114.6
Non-recourse		27.9		33.5
Total other liabilities		4,094.8		4,271.7
Commitments and Contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 215.7 million shares and 214.9 million shares outstanding at Jun. 30, 2011 and Dec. 31, 2010, respectively)		215.7		214.9
Additional paid in capital		1,546.8		1,542.0
Retained earnings		468.8		430.0
Accumulated other comprehensive loss		(15.5)		(17.2)
Total TECO Energy, Inc. capital		2,215.8		2,169.7
Noncontrolling interest		0.4		0.9
Total capital		2,216.2		2,170.6
Total liabilities and capital	$	7,098.0	$	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 Jun. 30,
(millions, except per share amounts)	2011		2010
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $27.1 in 2011 and $28.1 in 2010)	$	656.5	$	665.2
Unregulated		229.2		233.6
Total revenues		885.7		898.8
Expenses
Regulated operations
Fuel		194.2		185.4
Purchased power		43.9		49.1
Cost of natural gas sold		54.1		59.4
Other		82.1		96.5
Operation other expense
Mining related costs		130.7		137.6
Guatemalan power generation		22.7		17.7
Other		1.7		1.5
Maintenance		48.5		47.8
Depreciation and amortization		81.2		77.9
Taxes, other than income		55.5		56.0
Total expenses		714.6		728.9
Income from operations		171.1		169.9
Other income (expense)
Allowance for other funds used during construction		0.3		0.3
Other income		1.5		2.2
(Loss) on debt extinguishment		0.0		(6.6)
Income from equity investments		0.0		4.2
Total other income		1.8		0.1
Interest charges
Interest expense		51.3		58.4
Allowance for borrowed funds used during construction		(0.1)		(0.2)
Total interest charges		51.2		58.2
Income before provision for income taxes		121.7		111.8
Provision for income taxes		44.1		36.1
Net income	$	77.6	$	75.7
Less: Net income attributable to noncontrolling interest		(0.1)		(0.2)
Net income attributable to TECO Energy	$	77.5	$	75.5
Average common shares outstanding – Basic		213.6		212.5
– Diluted		215.2		214.7
Earnings per share attributable to TECO Energy – Basic	$	0.36	$	0.35
– Diluted	$	0.36	$	0.35
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

	Six months ended Jun. 30,
(millions, except per share amounts)	2011		2010
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $55.5 in 2011 and $59.0 in 2010)	$	1,243.6	$	1,371.7
Unregulated		438.2		439.4
Total revenues		1,681.8		1,811.1
Expenses
Regulated operations
Fuel		339.1		349.4
Purchased power		71.1		106.3
Cost of natural gas sold		136.1		175.4
Other		160.4		184.4
Operation other expense
Mining related costs		254.7		255.2
Guatemalan power generation		42.8		32.9
Other		3.1		3.1
Maintenance		97.3		92.5
Depreciation and amortization		161.0		154.9
Restructuring charges		0.0		1.5
Taxes, other than income		114.2		116.7
Total expenses		1,379.8		1,472.3
Income from operations		302.0		338.8
Other income (expense)
Allowance for other funds used during construction		0.6		1.3
Other income		3.0		5.6
(Loss) on debt extinguishment		0.0		(33.0)
Income from equity investments		0.0		6.9
Total other income		3.6		(19.2)
Interest charges
Interest expense		104.1		118.3
Allowance for borrowed funds used during construction		(0.3)		(0.8)
Total interest charges		103.8		117.5
Income before provision for income taxes		201.8		202.1
Provision for income taxes		72.5		70.4
Net income	$	129.3	$	131.7
Less: Net income attributable to noncontrolling interest		(0.1)		(0.4)
Net income attributable to TECO Energy	$	129.2	$	131.3
Average common shares outstanding – Basic		213.3		212.4
– Diluted		215.1		214.5
Earnings per share attributable to TECO Energy – Basic	$	0.60	$	0.61
– Diluted	$	0.60	$	0.61
Dividends paid per common share outstanding	$	0.420	$	0.405

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Jun. 30,				Six months ended Jun. 30,
(millions)	2011		2010		2011		2010
Net income	$	77.6	$	75.7	$	129.3	$	131.7
Other comprehensive income (loss), net of tax
Net unrealized (losses) gains on cash flow hedges		(1.4)		(0.4)		0.9		0.4
Amortization of unrecognized benefit costs and other		0.4		0.5		0.8		2.3
Recognized benefit costs due to settlement		0.0		0.0		0.0		0.9
Other comprehensive (loss) income, net of tax		(1.0)		0.1		1.7		3.6
Comprehensive income		76.6		75.8		131.0		135.3
Comprehensive loss attributable to noncontrolling interests		(0.1)		(0.2)		(0.1)		(0.4)
Comprehensive income attributable to TECO Energy, Inc.	$	76.5	$	75.6	$	130.9	$	134.9

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended Jun. 30,
(millions)	2011		2010
Cash flows from operating activities
Net income	$	129.3	$	131.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		161.0		154.9
Deferred income taxes		69.0		72.6
Investment tax credits, net		(0.2)		(0.2)
Allowance for funds used during construction		(0.6)		(1.3)
Non-cash stock compensation		4.2		3.4
Gain on sale of business/assets, pretax		(0.3)		(0.6)
Non-cash debt extinguishment, pretax		0.0		0.9
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		0.0		(1.2)
Deferred recovery clauses		6.3		12.9
Receivables, less allowance for uncollectibles		(2.0)		(70.0)
Inventories		13.8		(36.9)
Prepayments and other current assets		(3.5)		(2.8)
Taxes accrued		22.3		27.2
Interest accrued		4.6		3.9
Accounts payable		(34.6)		39.4
Other		17.5		(6.3)
Cash flows from operating activities		386.8		327.6
Cash flows from investing activities
Capital expenditures		(200.2)		(275.1)
Allowance for funds used during construction		0.6		1.3
Net proceeds from sale of business/assets		2.9		0.9
Net cash increase from consolidation (1)		0.0		24.1
Contributions to unconsolidated affiliates		0.0		(1.3)
Other investments		14.4		0.8
Cash flows (used in) investing activities		(182.3)		(249.3)
Cash flows from financing activities
Dividends		(90.4)		(86.7)
Proceeds from the sale of common stock		5.4		3.0
Proceeds from long-term debt issuance		0.0		543.5
Repayment of long-term debt/Purchase in lieu of redemption		(144.6)		(507.6)
Dividend to noncontrolling interest		(0.6)		(0.7)
Net increase in short-term debt		20.0		22.0
Cash flows (used in) financing activities		(210.2)		(26.5)
Net (decrease) increase in cash and cash equivalents		(5.7)		51.8
Cash and cash equivalents at beginning of period		67.5		46.0
Cash and cash equivalents at end of period	$	61.8	$	97.8

(1) In accordance with new accounting guidance, effective Jan. 1, 2010, the company reconsolidated $24.1 million in cash and cash equivalents related to two projects in Guatemala.

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 Jun. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Jun. 30, 2011 and 2010. The results of operations for the three month and six month periods ended Jun. 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 Jun. 30, 2011 and Dec. 31, 2010, unbilled revenues of $62.3 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 $27.1 million and $55.5 million, respectively, for the three and six months ended Jun. 30, 2011, compared to $28.1 million and $59.0 million for the three and six months ended Jun. 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 $27.1 million and $55.4 million, respectively, for the three and six months ended Jun. 30, 2011, compared to $28.0 million and $58.8 million for the three and six months ended Jun. 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 $43.9 million and $71.1 million, respectively, for the three and six months ended Jun. 30, 2011, compared to $49.1 million and $106.3 million for the three and six months ended Jun. 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 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.

9

2. New Accounting Pronouncements

Presentation of Comprehensive Income

In June 2011, the Financial Accounting Standards Board (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 $41.4 million and $37.4 million as of Jun. 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 Jun. 30, 2011 and Dec. 31, 2010 are presented in the following table:

Regulatory Assets and Liabilities

(millions)	Jun. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	65.2	$	66.6
Other:
Cost recovery clauses		22.7		41.9
Postretirement benefit asset		231.8		237.5
Deferred bond refinancing costs (2)		13.2		15.4
Environmental remediation		22.9		23.6
Competitive rate adjustment		3.2		3.3
Other		16.8		16.3
Total other regulatory assets		310.6		338.0
Total regulatory assets		375.8		404.6
Less: Current portion		43.9		62.7
Long-term regulatory assets	$	331.9	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	17.0	$	17.7
Other:
Cost recovery clauses		78.5		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.4		37.4
Deferred gain on property sales (3)		5.5		6.3
Provision for stipulation and other (4)		0.7		9.8
Accumulated reserve-cost of removal		570.9		572.2
Total other regulatory liabilities		718.2		723.1
Total regulatory liabilities		735.2		740.8
Less: Current portion		103.0		110.0
Long-term regulatory liabilities	$	632.2	$	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

	Jun. 30,		Dec 31,
(millions)	2011		2010
Clause recoverable (1)	$	25.9	$	45.2
Components of rate base (2)		243.3		248.1
Regulatory tax assets (3)		65.2		66.6
Capital structure and other (3)		41.4		44.7
Total	$	375.8	$	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.

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4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The Internal Revenue Service (IRS) concluded its examination of the company’s 2009 consolidated federal income tax return during 2010. The U.S. federal statute of limitations remains open for the year 2007 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 2005 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 six months ended Jun. 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 six months ended Jun. 30, 2011, the company recorded $0.2 million of interest charges. For the six months ended Jun. 30, 2010, the company recorded $1.3 million of interest income as a result of reaching a favorable settlement for certain state items that were under appeal. No amounts were recorded for penalties for the six month periods ended Jun. 30, 2011 or 2010.

The effective tax rate increased to 35.92% for the six-months ended Jun. 30, 2011 from 34.84% for the same period in 2010. The six-month period ended Jun. 30, 2010 included a benefit from the settlements of certain state items and a benefit resulting from the permanently reinvested earnings at DECA II, offset by 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.

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Pension Expense

(millions)	Pension Benefits				Other Postretirement Benefits
Three months ended Jun. 30,	2011		2010		2011		2010
Components of net periodic benefit expense
Service cost	$	3.8	$	3.9	$	0.5	$	0.8
Interest cost on projected benefit obligations		7.7		8.4		2.7		2.5
Expected return on assets		(9.5)		(9.2)		0.0		0.0
Amortization of:
Transition obligation		0.0		0.0		0.6		0.6
Prior service (benefit) cost		(0.1)		(0.1)		0.2		0.2
Actuarial loss (gain)		2.8		3.2		(0.1)		0.0
Pension expense		4.7		6.2		3.9		4.1
Settlement cost		0.0		0.1		0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	4.7	$	6.3	$	3.9	$	4.1
Six months ended Jun. 30,
Components of net periodic benefit expense
Service cost	$	8.0	$	8.1	$	1.1	$	1.6
Interest cost on projected benefit obligations		15.5		16.7		5.5		5.4
Expected return on assets		(19.2)		(18.2)		0.0		0.0
Amortization of:
Transition obligation		0.0		0.0		1.2		1.2
Prior service (benefit) cost		(0.2)		(0.2)		0.4		0.4
Actuarial loss		5.6		6.2		0.0		0.0
Pension expense		9.7		12.6		8.2		8.6
Settlement cost		0.0		1.6		0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	9.7	$	14.2	$	8.2	$	8.6

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 six months ended Jun. 30, 2011, TECO Energy and its subsidiaries reclassed $0.7 million and $1.3 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 six months ended Jun. 30, 2011, Tampa Electric Company reclassed $2.7 million and $5.7 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 $0.1 million and $1.6 million, respectively, for the three and six months ended Jun. 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.

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6. Short-Term Debt

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

Credit Facilities

	Jun. 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	$	7.0	$	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		25.0		0.0		200.0		0.0		6.7
Total	$	675.0	$	32.0	$	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.

(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 Jun. 30, 2011 and Dec. 31, 2010 were 0.65% and 0.64%, respectively.

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 offer 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 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 Jun. 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.

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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.

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 quarter ended Jun. 30, 2010. “Loss on debt extinguishment” also includes remaining unamortized debt issue costs of $0.9 million.

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8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (OCI) for the three and six months ended Jun. 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 Jun. 30,						Six months ended Jun. 30,
(millions)	Gross		Tax		Net		Gross		Tax		Net
2011
Unrealized (loss) gain on cash flow hedges	($	1.3)	$	0.5	($	0.8)	$	2.9	($	1.1)	$	1.8
Less: Gain reclassified to net income		(0.9)		0.3		(0.6)		(1.4)		0.5		(0.9)
(Loss) Gain on cash flow hedges		(2.2)		0.8		(1.4)		1.5		(0.6)		0.9
Amortization of unrecognized benefit costs and other		0.7		(0.3)		0.4		1.3		(0.5)		0.8
Total other comprehensive (loss) income	($	1.5)	$	0.5	($	1.0)	$	2.8	($	1.1)	$	1.7
2010
Unrealized loss on cash flow hedges	($	1.9)	$	0.8	($	1.1)	($	1.4)	$	0.4	($	1.0)
Less: Loss reclassified to net income		1.1		(0.4)		0.7		2.2		(0.8)		1.4
(Loss) Gain on cash flow hedges		(0.8)		0.4		(0.4)		0.8		(0.4)		0.4
Amortization of unrecognized benefit costs and other		0.8		(0.3)		0.5		1.4		0.9		2.3
Recognized benefit costs due to settlement		(0.6)		0.6		0.0		0.9		0.0		0.9
Total other comprehensive income	($	0.6)	$	0.7	$	0.1	$	3.1	$	0.5	$	3.6

Accumulated Other Comprehensive Loss

(millions)	Jun. 30, 2011		Dec. 31, 2010
Unrecognized pension losses and prior service costs(1)	($	25.8)	($	26.6)
Unrecognized other benefit gains, prior service costs and transition obligations (2)		13.6		13.6
Net unrealized losses from cash flow hedges(3)		(3.3)		(4.2)
Total accumulated other comprehensive loss	($	15.5)	($	17.2)

(1) Net of tax benefit of $15.9 million and $16.2 million as of Jun. 30, 2011 and Dec. 31, 2010, respectively.

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

(3) Net of tax benefit of $2.2 million and $ 2.7 million as of Jun. 30, 2011 and Dec. 31, 2010, respectively.

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9. Earnings Per Share

Earnings Per Share

	Three months ended Jun. 30,				Six months ended Jun. 30,
(millions, except per share amounts)	2011		2010		2011		2010
Basic earnings per share
Net income	$	77.6	$	75.7	$	129.3	$	131.7
Less: Income attributable to noncontrolling interest		(0.1)		(0.2)		(0.1)		(0.4)
Less: Amount allocated to nonvested participating shareholders		(0.4)		(0.5)		(0.7)		(1.0)
Net income attributable to TECO Energy available to common shareholders - basic	$	77.1	$	75.0	$	128.5	$	130.3
Average shares outstanding-common		213.6		212.5		213.3		212.4
Basic earnings per share attributable to TECO Energy available to common shareholders	$	0.36	$	0.35	$	0.60	$	0.61
Diluted earnings per share
Net income	$	77.6	$	75.7	$	129.3	$	131.7
Less: Income attributable to noncontrolling interest		(0.1)		(0.2)		(0.1)		(0.4)
Less: Amount allocated to nonvested participating shareholders		(0.4)		(0.5)		(0.7)		(1.0)
Net income attributable to TECO Energy available to common shareholders - diluted	$	77.1	$	75.0	$	128.5	$	130.3
Average shares outstanding-common		213.6		212.5		213.3		212.4
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		1.6		2.2		1.8		2.1
Adjusted average shares outstanding common - diluted		215.2		214.7		215.1		214.5
Diluted earnings per share attributable to TECO Energy available to common shareholders	$	0.36	$	0.35	$	0.60	$	0.61
Anti-dilutive shares		1.6		8.4		2.0		9.1

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 first portion of a non-jury trial in this case was held in June 2011 in the Dade County, Florida Circuit Court. The trial is expected to resume and conclude in October 2011. 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.

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Superfund and Former Manufactured Gas Plant Sites

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

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Guarantees and Letters of Credit

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

Guarantees-TECO Energy

(millions)
Guarantees for the Benefit of:	2011		2012-2015		After (1) 2015		Total		Liabilities Recognized at Jun. 30, 2011
TECO Coal
Guarantees:
Fuel purchase related (2)		0.0		0.0		5.4		5.4		1.9
		0.0		0.0		5.4		5.4		1.9
Other subsidiaries
Guarantees:
Fuel purchase/energy management (2)		0.0		0.0		109.7		109.7		0.0
Total	$	0.0	$	0.0	$	115.1	$	115.1	$	1.9

Letters of Credit-Tampa Electric Company

(millions) Letters of Credit for the Benefit of:	2011		2012-2015		After  (1) 2015		Total		Liabilities Recognized at Jun. 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 Jun. 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 Jun. 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.

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Segment Information ⁽¹⁾

(millions)	Tampa		Peoples		TECO		TECO		Other &		TECO
Three months ended Jun. 30,	Electric		Gas		Coal		Guatemala		Eliminations		Energy, Inc.
2011
Revenues - external	$	546.1	$	110.4	$	191.3	$	36.1	$	1.8	$	885.7
Sales to affiliates		0.4		0.8		0.0		0.0		(1.2)		0.0
Total revenues		546.5		111.2		191.3		36.1		0.6		885.7
Depreciation		55.3		12.0		11.7		1.9		0.3		81.2
Total interest charges(1)		30.4		4.4		1.7		1.9		12.8		51.2
Internally allocated interest (1)		0.0		0.0		1.7		1.6		(3.3)		0.0
Provision (benefit) for taxes		36.9		3.7		5.0		3.3		(4.8)		44.1
Net income (loss) attributable to TECO Energy	$	58.4	$	5.9	$	15.8	$	5.6	($	8.2)	$	77.5
2010
Revenues - external	$	552.8	$	112.4	$	200.6	$	32.9	$	0.1	$	898.8
Sales to affiliates		0.4		3.7		0.0		0.0		(4.1)		0.0
Total revenues		553.2		116.1		200.6		32.9		(4.0)		898.8
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		4.8		(0.6)		4.2
Depreciation		53.6		11.4		11.0		1.8		0.1		77.9
Total interest charges(1)		30.8		4.6		1.8		4.4		16.6		58.2
Internally allocated interest (1)		0.0		0.0		1.7		3.2		(4.9)		0.0
Provision (benefit) for taxes		33.8		3.3		4.5		2.8		(8.3)		36.1
Net income (loss) attributable to TECO Energy	$	56.8	$	5.1	$	20.7	$	10.6	($	17.7)	$	75.5
(millions)	Tampa		Peoples		TECO		TECO		Other &		TECO
Six months ended Jun. 30,	Electric		Gas		Coal		Guatemala		Eliminations		Energy, Inc.
2011
Revenues - external	$	979.0	$	264.6	$	365.0	$	69.7	$	3.5	$	1,681.8
Sales to affiliates		0.7		2.7		0.0		0.0		(3.4)		0.0
Total revenues		979.7		267.3		365.0		69.7		0.1		1,681.8
Depreciation		110.2		23.8		22.6		3.7		0.7		161.0
Total interest charges(1)		61.3		8.9		3.4		3.8		26.4		103.8
Internally allocated interest (1)		0.0		0.0		3.3		3.1		(6.4)		0.0
Provision (benefit) for taxes		56.9		13.0		6.6		6.1		(10.1)		72.5
Net income (loss) attributable to TECO Energy	$	90.0	$	20.6	$	24.0	$	11.9	($	17.3)	$	129.2
2010
Revenues - external	$	1,077.6	$	294.1	$	372.6	$	66.7	$	0.1	$	1,811.1
Sales to affiliates		0.7		14.9		0.0		0.0		(15.6)		0.0
Total revenues		1,078.3		309.0		372.6		66.7		(15.5)		1,811.1
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		8.0		(1.1)		6.9
Depreciation		106.6		22.8		21.8		3.6		0.1		154.9
Restructuring charges		0.0		0.0		0.0		0.0		1.5		1.5
Total interest charges(1)		61.1		9.2		3.6		9.0		34.6		117.5
Internally allocated interest (1)		0.0		0.0		3.5		6.5		(10.0)		0.0
Provision (benefit) for taxes		61.6		14.5		6.9		6.8		(19.4)		70.4
Net income (loss) attributable to TECO Energy	$	104.9	$	23.0	$	37.5	$	21.0	($	55.1)	$	131.3

20

(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations		TECO Energy, Inc.
At Jun. 30, 2011
Goodwill	$	0.0	$	0.0	$	0.0	$	55.4	$	0.0	$	55.4
Total assets	$	5,808.1	$	879.6	$	359.1	$	263.0	($	211.8)	$	7,098.0
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 June 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.

21

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 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 Jun. 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 Jun. 30, 2011 and Dec. 31, 2010:

Total Derivatives⁽¹⁾

	Jun. 30,		Dec. 31,
(millions)	2011		2010
Current assets	$	3.2	$	2.7
Long-term assets		0.6		0.2
Total assets	$	3.8	$	2.9
Current liabilities	$	12.6	$	27.2
Long-term liabilities		1.5		2.6
Total liabilities	$	14.1	$	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.

22

The following table presents the derivative hedges of heating oil swaps and option contracts at Jun. 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:

Heating Oil Derivatives

	Jun. 30,		Dec. 31,
(millions)	2011		2010
Current assets	$	2.9	$	1.6
Long-term assets		0.6		0.2
Total assets	$	3.5	$	1.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		0.4		0.0
Total liabilities	$	0.4	$	0.0

The following table presents the derivative hedges of natural gas contracts at Jun. 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

	Jun. 30,		Dec. 31,
(millions)	2011		2010
Current assets	$	0.3	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.3	$	1.1
Current liabilities	$	12.6	$	27.2
Long-term liabilities		1.1		2.6
Total liabilities	$	13.7	$	29.8

The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Jun. 30, 2011 is a net loss of $3.3 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 Jun. 30, 2011:

Derivatives Designated As Hedging Instruments

	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
at Jun. 30, 2011	Location	Value		Location	Value
Commodity Contracts:
Heating oil derivatives:
Current	Derivative assets	$	2.9	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.6	Derivative liabilities		0.4
Natural gas derivatives:
Current	Derivative assets		0.3	Derivative liabilities		12.6
Long-term	Derivative assets		0.0	Derivative liabilities		1.1
Total derivatives designated as hedging instruments		$	3.8		$	14.1

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

Energy Related Derivatives

	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
at Jun. 30, 2011	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.3	Regulatory assets	$	12.6
Long-term	Regulatory liabilities		0.0	Regulatory assets	$	1.1
Total		$	0.3		$	13.7

(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 Jun. 30, 2011, net pretax losses of $12.3 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 six months ended Jun. 30:

For the three months ended Jun. 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:
Heating oil derivatives		(0.8)	Mining related costs		0.8
Total	($	0.8)		$	0.6
2010
Interest rate contracts:	$	0.0	Interest expense	($	0.4)
Commodity contracts:
Heating oil derivatives		(1.1)	Mining related costs		(0.3)
Total	($	1.1)		($	0.7)

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

24

For the six months ended Jun. 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	($	0.3)
Commodity contracts:
Heating oil derivatives		1.8	Mining related costs		1.2
Total	$	1.8		$	0.9
2010
Interest rate contracts:	($	0.1)	Interest expense	($	0.9)
Commodity contracts:
Heating oil derivatives		(0.9)	Mining related costs		(0.5)
Total	($	1.0)		($	1.4)

(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 six months ended Jun. 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 six months ended Jun. 30:

For the six months ended Jun 30: (millions)	Fair Value Asset/(Liability)		Amount of Gain/(Loss) Recognized in OCI (1)		Amount of Gain/(Loss) Reclassified From AOCI Into Income
2011
Interest rate swaps	$	0.0	$	0.0	($	0.3)
Heating oil derivatives		3.1		1.8		1.2
Total	$	3.1	$	1.8	$	0.9
2010
Interest rate swaps	($	0.5)	($	0.1)	($	0.9)
Heating oil derivatives		(1.4)		(0.9)		(0.5)
Total	($	1.9)	($	1.0)	($	1.4)

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

25

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 heating oil fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of Jun. 30, 2011, are expected to settle during the 2011, 2012, 2013 and 2014 fiscal years:

	Heating Oil Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2011		0.0		4.8		0.0		23.4
2012		0.0		2.6		0.0		21.9
2013		0.0		1.8		0.0		3.2
2014		0.0		1.0		0.0		0.0
Total		0.0		10.2		0.0		48.5

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

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Jun. 30, 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 Jun. 30, 2011:

Contingent Features

(millions) At Jun. 30, 2011	Fair Value Asset/ (Liability)		Derivative Exposure Asset/ (Liability)		Posted Collateral
Credit Rating	($	13.8)	($	13.8)	$	0.0

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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 Jun. 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 heating oil swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures

	At fair value as of Jun. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Heating oil swaps		0.0		3.5		0.0		3.5
Total	$	0.0	$	3.8	$	0.0	$	3.8
Liabilities
Natural gas swaps	$	0.0	$	13.7	$	0.0	$	13.7
Heating oil swaps		0.0		0.4		0.0		0.4
Total	$	0.0	$	14.1	$	0.0	$	14.1
	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
Heating oil 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 heating oil swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of these swaps are the New York Mercantile Exchange (NYMEX) quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value.

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Jun. 30, 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 Jun. 30, 2011, total long-term debt had a carrying amount of $3,082.2 million and an estimated fair market value of $3,354.8 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 six months ended Jun. 30, 2010, the remaining $1.5 million was recognized on the Consolidated Condensed Statements of Income under “Restructuring charges”.

27

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 $26.2 million and $42.0 million pursuant to PPAs for the three and six months ended Jun. 30, 2011, respectively, and $30.6 million and $61.0 million for the three and six months ended Jun. 30, 2010, respectively.

In one instance Tampa Electric Company’s agreement with the 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 $5.9 million and $13.0 million for the three and six months ended Jun. 30, 2011, respectively, and $17.6 million and $30.3 million for the three and six months ended Jun. 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.

28

TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company as of Jun. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Jun. 30, 2011 and 2010. The results of operations for the three months and six months ended Jun. 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 48 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Jun. 30, 2011 and Dec. 31, 2010		30-31
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended Jun. 30, 2011 and 2010		32-33
Consolidated Condensed Statements of Cash Flows for the six month periods ended Jun. 30, 2011 and 2010		34
Notes to Consolidated Condensed Financial Statements		35

29

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Jun. 30,		Dec. 31,
(millions)	2011		2010
Property, plant and equipment
Utility plant in service
Electric	$	6,379.1	$	6,343.4
Gas		1,079.8		1,060.6
Construction work in progress		233.3		206.8
Property, plant and equipment, at original costs		7,692.2		7,610.8
Accumulated depreciation		(2,163.1)		(2,093.9)
		5,529.1		5,516.9
Other property		5.1		4.7
Total property, plant and equipment, net		5,534.2		5,521.6
Current assets
Cash and cash equivalents		10.9		3.7
Receivables, less allowance for uncollectibles of $3.2 and $3.2 at Jun. 30, 2011 and Dec. 31, 2010, respectively		248.6		264.6
Inventories, at average cost
Fuel		100.6		119.0
Materials and supplies		63.6		59.1
Current regulatory assets		43.9		62.7
Current derivative assets		0.3		1.1
Taxes receivable		0.0		24.6
Deferred tax asset		0.0		1.5
Prepayments and other current assets		12.4		10.0
Total current assets		480.3		546.3
Deferred debits
Unamortized debt expense		15.9		17.8
Long-term regulatory assets		331.9		341.9
Other		10.5		10.9
Total deferred debits		358.3		370.6
Total assets	$	6,372.8	$	6,438.5

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

30

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets -continued

Unaudited

Liabilities and Capital	Jun. 30,		Dec. 31,
(millions)	2011		2010
Capital
Common stock	$	1,852.4	$	1,852.4
Accumulated other comprehensive loss		(5.0)		(5.3)
Retained earnings		316.0		311.1
Total capital		2,163.4		2,158.2
Long-term debt, less amount due within one year		1,872.7		2,066.1
Total capitalization		4,036.1		4,224.3
Current liabilities
Long-term debt due within one year		122.0		3.4
Notes payable		7.0		12.0
Accounts payable		172.8		219.0
Customer deposits		158.2		156.5
Current regulatory liabilities		103.0		110.0
Current derivative liabilities		12.6		27.2
Current deferred income taxes, net		1.2		0.0
Interest accrued		29.8		24.6
Taxes accrued		28.7		14.0
Other		12.1		12.2
Total current liabilities		647.4		578.9
Deferred credits
Non-current deferred income taxes, net		685.9		631.5
Investment tax credits		10.2		10.4
Long-term derivative liabilities		1.1		2.6
Long-term regulatory liabilities		632.2		630.8
Other		359.9		360.0
Total deferred credits		1,689.3		1,635.3
Commitments and Contingencies (see Note 8)
Total liabilities and capital	$	6,372.8	$	6,438.5

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

	Three months ended! Jun. 30,
(millions)	2011		2010
Revenues
Electric (includes franchise fees and gross receipts taxes of $ 21.3 in 2011 and $ 21.8 in 2010)	$	546.4	$	553.1
Gas (includes franchise fees and gross receipts taxes of $ 5.8 in 2011 and $6.3 in 2010)		110.4		112.4
Total revenues		656.8		665.5
Expenses
Operations
Fuel		194.2		185.4
Purchased power		43.9		49.1
Cost of natural gas sold		54.2		59.4
Other		82.0		96.5
Maintenance		31.6		31.6
Depreciation		67.3		65.0
Taxes, federal and state		40.4		37.0
Taxes, other than income		44.9		45.2
Total expenses		558.5		569.2
Income from operations		98.3		96.3
Other income (expense)
Allowance for other funds used during construction		0.3		0.3
Taxes, non-utility federal and state		(0.2)		(0.1)
Other income, net		0.7		0.8
Total other income		0.8		1.0
Interest charges
Interest on long-term debt		32.1		32.8
Other interest		2.8		2.8
Allowance for borrowed funds used during construction		(0.1)		(0.2)
Total interest charges		34.8		35.4
Net income		64.3		61.9
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	$	64.5	$	62.1

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

32

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Six months ended Jun. 30,
(millions)	2011		2010
Revenues
Electric (includes franchise fees and gross receipts taxes of $ 40.6 in 2011 and $43.2 in 2010)	$	979.4	$	1,078.1
Gas (includes franchise fees and gross receipts taxes of $ 14.9 in 2011 and $15.8 in 2010)		264.7		294.1
Total revenues		1,244.1		1,372.2
Expenses
Operations
Fuel		339.1		349.4
Purchased power		71.1		106.3
Cost of natural gas sold		136.2		175.4
Other		160.2		184.2
Maintenance		63.1		61.6
Depreciation		134.0		129.4
Taxes, federal and state		69.5		75.8
Taxes, other than income		91.5		94.5
Total expenses		1,064.7		1,176.6
Income from operations		179.4		195.6
Other income (expense)
Allowance for other funds used during construction		0.6		1.3
Taxes, non-utility federal and state		(0.4)		(0.3)
Other income, net		1.2		1.6
Total other income		1.4		2.6
Interest charges
Interest on long-term debt		64.8		65.5
Other interest		5.7		5.6
Allowance for borrowed funds used during construction		(0.3)		(0.8)
Total interest charges		70.2		70.3
Net income		110.6		127.9
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges		0.3		0.4
Total other comprehensive income, net of tax		0.3		0.4
Comprehensive income	$	110.9	$	128.3

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended Jun. 30,
(millions)	2011		2010
Cash flows from operating activities
Net income	$	110.6	$	127.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		134.0		129.4
Deferred income taxes		57.5		23.5
Investment tax credits, net		(0.2)		(0.2)
Allowance for funds used during construction		(0.6)		(1.3)
Deferred recovery clause		6.3		12.9
Receivables, less allowance for uncollectibles		16.0		(59.1)
Inventories		13.9		(41.2)
Prepayments		(2.4)		(1.3)
Taxes accrued		39.3		42.9
Interest accrued		5.2		4.2
Accounts payable		(38.3)		27.9
Gain on sale of assets, pretax		(0.1)		(0.2)
Other		15.2		(4.9)
Cash flows from operating activities		356.4		260.5
Cash flows from investing activities
Capital expenditures		(166.3)		(212.7)
Allowance for funds used during construction		0.6		1.3
Net proceeds from sale of assets		2.6		0.0
Cash flows used in investing activities		(163.1)		(211.4)
Cash flows from financing activities
Common stock		0.0		50.0
Repayment of long-term debt/Purchase in lieu of redemption		(75.3)		0.0
Net (decrease) increase in short-term debt		(5.0)		22.0
Dividends		(105.8)		(119.2)
Cash flows used in financing activities		(186.1)		(47.2)
Net increase in cash and cash equivalents		7.2		1.9
Cash and cash equivalents at beginning of period		3.7		5.5
Cash and cash equivalents at end of period	$	10.9	$	7.4

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies 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 Jun. 30, 2011 and Dec. 31, 2010, and the results of operations and cash flows for the periods ended Jun. 30, 2011 and 2010. The results of operations for the three month and six month periods ended Jun. 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 Jun. 30, 2011 and Dec. 31, 2010, unbilled revenues of $62.3 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 $27.1 million and $55.5 million, respectively, for the three and six months ended Jun. 30, 2011, compared to $28.1 million and $59.0 million for the three and six months ended Jun. 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 $27.1 million and $55.4 million, respectively, for the three and six months ended Jun. 30, 2011, compared to $28.0 million and $58.8 million for the three and six months ended Jun. 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 $43.9 million and $71.1 million, respectively, for the three and six months ended Jun. 30, 2011, compared to $49.1 million and $106.3 million for the three and six months ended Jun. 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.

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.

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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, 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 $41.4 million and $37.4 million as of Jun. 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.

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

Regulatory Assets and Liabilities

(millions)	Jun. 30, 2011		Dec. 31, 2010
Regulatory assets:
Regulatory tax asset (1)	$	65.2	$	66.6
Other:
Cost recovery clauses		22.7		41.9
Postretirement benefit asset		231.8		237.5
Deferred bond refinancing costs (2)		13.2		15.4
Environmental remediation		22.9		23.6
Competitive rate adjustment		3.2		3.3
Other		16.8		16.3
Total other regulatory assets		310.6		338.0
Total regulatory assets		375.8		404.6
Less: Current portion		43.9		62.7
Long-term regulatory assets	$	331.9	$	341.9
Regulatory liabilities:
Regulatory tax liability (1)	$	17.0	$	17.7
Other:
Cost recovery clauses		78.5		76.2
Environmental remediation		21.2		21.2
Storm damage reserve		41.4		37.4
Deferred gain on property sales (3)		5.5		6.3
Provision for stipulation and other (4)		0.7		9.8
Accumulated reserve-cost of removal		570.9		572.2
Total other regulatory liabilities		718.2		723.1
Total regulatory liabilities		735.2		740.8
Less: Current portion		103.0		110.0
Long-term regulatory liabilities	$	632.2	$	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)	Jun. 30, 2011		Dec 31, 2010
Clause recoverable (1)	$	25.9	$	45.2
Components of rate base (2)		243.3		248.1
Regulatory tax assets (3)		65.2		66.6
Capital structure and other (3)		41.4		44.7
Total	$	375.8	$	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.

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4. Income Taxes

Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Tampa Electric Company’s effective tax rates for the six months ended Jun. 30, 2011 and Jun. 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 2007 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 2007 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 Jun. 30, 2011 and 2010, respectively, was $3.1 million and $4.4 million for pension benefits, and $3.2 million and $3.3 million for other postretirement benefits. For the six months ended Jun. 30, 2011 and 2010, respectively, net benefit expenses were $6.7 million and $9.3 million for pension benefits and $6.7 million and $6.9 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 six months ended Jun. 30, 2011, Tampa Electric Company reclassed $2.7 million and $5.7 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income. For the three months and six months ended Jun. 30, 2010, Tampa Electric Company reclassed $3.3 million and $6.4 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 Jun. 30, 2011 and Dec. 31, 2010, the following credit facilities and related borrowings existed:

	Jun. 30, 2011						Dec. 31, 2010
(millions)	Credit Facilities		Borrowings Outstanding  (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding  (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	7.0	$	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	$	7.0	$	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.

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 Jun. 30, 2011 and Dec. 31, 2010 were 0.53% and 0.64%, respectively.

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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 offer 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 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 Jun. 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.

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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 first portion of a non-jury trial in this case was held in June 2011 in the Dade County, Florida Circuit Court. The trial is expected to resume and conclude in October 2011. 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 PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Jun. 30, 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.

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Letters of Credit

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

Letters of Credit-Tampa Electric Company

(millions)
Letters of Credit for the Benefit of:	2011		2012-2015		After  (1) 2015		Total		Liabilities Recognized at Jun. 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 Jun. 30, 2011, Tampa Electric Company was in compliance with all applicable financial covenants.

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9. Segment Information

(millions) Three months ended Jun. 30,	Tampa Electric		Peoples Gas		Other & Eliminations		Tampa Electric Company
2011
Revenues - external	$	546.4	$	110.4	$	0.0	$	656.8
Sales to affiliates		0.1		0.8		(0.9)		0.0
Total revenues		546.5		111.2		(0.9)		656.8
Depreciation		55.3		12.0		0.0		67.3
Total interest charges		30.4		4.4		0.0		34.8
Provision for taxes		36.9		3.7		0.0		40.6
Net income		58.4		5.9		0.0		64.3
2010
Revenues - external	$	552.8	$	112.4	$	0.0	$	665.2
Sales to affiliates		0.4		3.7		(3.8)		0.3
Total revenues		553.2		116.1		(3.8)		665.5
Depreciation		53.6		11.4		0.0		65.0
Total interest charges		30.8		4.6		0.0		35.4
Provision for taxes		33.8		3.3		0.0		37.1
Net income		56.8		5.1		0.0		61.9
Six months ended Jun. 30,
2011
Revenues - external	$	979.4	$	264.7	$	0.0	$	1,244.1
Sales to affiliates		0.3		2.6		(2.9)		0.0
Total revenues		979.7		267.3		(2.9)		1,244.1
Depreciation		110.2		23.8		0.0		134.0
Total interest charges		61.3		8.9		0.0		70.2
Provision for taxes		56.9		13.0		0.0		69.9
Net income		90.0		20.6		0.0		110.6
Total assets at Jun. 30, 2011	$	5,556.2	$	839.6	($	23.0)	$	6,372.8
2010
Revenues - external	$	1,077.6	$	294.1	$	0.0	$	1,371.7
Sales to affiliates		0.7		14.9		(15.1)		0.5
Total revenues		1,078.3		309.0		(15.1)		1,372.2
Depreciation		106.6		22.8		0.0		129.4
Total interest charges		61.1		9.2		0.0		70.3
Provision for taxes		61.6		14.5		0.0		76.1
Net income		104.9		23.0		0.0		127.9
Total assets at Dec. 31, 2010	$	5,580.6	$	872.7	($	14.8)	$	6,438.5

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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 Jun. 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 Jun. 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)	Jun. 30, 2011		Dec. 31, 2010
Current assets	$	0.3	$	1.1
Long-term assets		0.0		0.0
Total assets	$	0.3	$	1.1
Current liabilities(1)	$	12.6	$	27.2
Long-term liabilities		1.1		2.6
Total liabilities	$	13.7	$	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 Jun. 30, 2011 is a net loss of $5.0 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.

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

Energy Related Derivatives

	Asset Derivatives			Liability Derivatives
(millions) at Jun. 30, 2011	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.3	Regulatory assets	$	12.6
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.1
Total		$	0.3		$	13.7

(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 Jun. 30, 2011, net pretax losses of $12.3 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 six months ended Jun. 30:

(millions)	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)	Three months ended Jun. 30:		Six months ended Jun. 30:
2011
Interest rate contracts:	Interest expense	($	0.2)	($	0.3)
Total		($	0.2)	($	0.3)
2010
Interest rate contracts:	Interest expense	($	0.2)	($	0.4)
Total		($	0.2)	($	0.4)

(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 six months ended Jun. 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 Jun. 30, 2011, are expected to settle during the 2011, 2012 and 2013 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2011		0.0		23.4
2012		0.0		21.9
2013		0.0		3.2
Total		0.0		48.5

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.

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

The table below presents the fair value of the overall contractual contingent liability positions for Tampa Electric Company’s derivative activity at Jun. 30, 2011:

Contingent Features

(millions) At Jun. 30, 2011	Fair Value Asset/ (Liability)		Derivative Exposure Asset/ (Liability)		Posted Collateral
Credit Rating	($	13.7)	($	13.7)	$	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 Jun. 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 Jun. 30, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Total	$	0.0	$	0.3	$	0.0	$	0.3
Liabilities
Natural gas swaps	$	0.0	$	13.7	$	0.0	$	13.7
Total	$	0.0	$	13.7	$	0.0	$	13.7

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	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 Jun. 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 Jun. 30, 2011, Tampa Electric Company’s total long-term debt had a carrying amount of $1,994.7 million and an estimated fair market value of $2,182.6 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 Jun. 30,						Six months ended Jun. 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		0.6		(0.3)		0.3
Gain on cash flow hedges		0.3		(0.1)		0.2		0.6		(0.3)		0.3
Total other comprehensive income	$	0.3	($	0.1)	$	0.2	$	0.6	($	0.3)	$	0.3
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		0.6		(0.2)		0.4
Gain on cash flow hedges		0.3		(0.1)		0.2		0.6		(0.2)		0.4
Total other comprehensive income	$	0.3	($	0.1)	$	0.2	$	0.6	($	0.2)	$	0.4
Accumulated Other Comprehensive Loss
(millions)							Jun. 30, 2011				Dec. 31, 2010
Net unrealized losses from cash flow hedges (1)							($	5.0)			($	5.3)
Total accumulated other comprehensive loss							($	5.0)			($	5.3)

(1) Net of tax benefit of $3.1 million and $3.4 million as of Jun. 30, 2011 and Dec. 31, 2010, respectively.

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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 $26.2 million and $42.0 million pursuant to PPAs for the three and six months ended Jun. 30, 2011, respectively, and $30.6 million and $61.0 million for the three and six months ended Jun. 30, 2010, respectively.

In one instance Tampa Electric Company’s agreement with the 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 $5.9 million and $13.0 million for the three and six months ended Jun. 30, 2011, respectively, and $17.6 million and $30.3 million for the three and six months ended Jun. 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.

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

This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Management’s Discussion and Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access 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 identify 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; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; and changes in the U.S. federal tax code on earnings from foreign investments that could reduce earnings. 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.

Earnings Summary - Unaudited

	Three months ended Jun. 30,				Six months ended Jun. 30,
(millions, except per share amounts)	2011		2010		2011		2010
Consolidated revenues	$	885.7	$	898.8	$	1,681.8	$	1,811.1
Net income attributable to TECO Energy	$	77.5	$	75.5	$	129.2	$	131.3
Average common shares outstanding
Basic		213.6		212.5		213.3		212.4
Diluted		215.2		214.7		215.1		214.5
Earnings per share - basic	$	0.36	$	0.35	$	0.60	$	0.61
Earnings per share - diluted	$	0.36	$	0.35	$	0.60	$	0.61

Operating Results

Three Months Ended June 30, 2011

TECO Energy, Inc. reported second quarter net income of $77.5 million, or $0.36 per share, compared to $75.5 million, or $0.35 per share, in the second quarter of 2010. Results in the second quarter of 2010 were reduced by a $4.1 million charge related to early debt retirement.

Six Months Ended June 30, 2011

Year-to-date net income and earnings per share were $129.2 million, or $0.60 per share, in 2011, compared to $131.3 million, or $0.61 per share, in the same period in 2010. Year-to-date results in 2010 were reduced by charges of $21.2 million, primarily for early retirement of TECO Energy and TECO Finance notes.

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 second quarter of $58.4 million, compared with $56.8 million for the same period in 2010. Results for the quarter reflected a 0.7% higher average number of customers, higher earnings on nitrogen oxide (NOx) control projects, and lower operations and maintenance expenses.

Total degree days in Tampa Electric’s service area were 12% above normal, but essentially in line with the second quarter of 2010. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, decreased 2.3% in the second quarter of 2011 compared to the same period in 2010. The quarterly energy sales shown on the statistical summary below reflects the energy sales based on the timing of billing cycles, which can vary period to period. Lower retail energy sales were driven primarily by lower sales to industrial-phosphate customers due to increased self-generation capacity, and the operation of a generating unit in 2011 by an industrial-phosphate customer in 2011, who had experienced an outage in 2010.

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Operations and maintenance expense, excluding all FPSC-approved cost recovery clauses, decreased $5.3 million, reflecting higher generating system maintenance expenses, which were more than offset by lower accruals for performance-based incentive compensation for all employees. Depreciation and amortization expense increased $1.0 million due to additions to facilities to serve customers.

Year-to-date net income was $90.0 million, compared with $104.9 million in the 2010 period, driven primarily by lower energy sales due to milder winter weather than 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.

Total degree days in Tampa Electric’s service area were 9% above normal, but 9% below the prior year-to-date period. Pretax base revenue was $25 to $30 million lower than 2010, primarily reflecting the milder weather and the voluntary conservation that typically occurs during periods without extreme weather.

In the 2011 year-to-date period, total net energy for load declined 6.5% compared to the same period in 2010. The year-to-date energy sales shown on the statistical summary below reflects the higher sales associated with the late December 2010 cold weather that are included in 2011 billed sales. 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.

Operations and maintenance expense, excluding all FPSC-approved cost recovery clauses, decreased $7.7 million. Higher spending on generating unit maintenance was more than offset by lower accruals of performance-based incentive compensation for all employees.

Compared to the 2010 year-to-date period, depreciation and amortization expense increased $2.2 million, reflecting the additions to facilities to serve customers discussed above.

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

	Operating Revenues						Kilowatt-hour sales
(millions, except average customers)	2011		2010		% Change		2011		2010		% Change
Three months ended Jun. 30,
By Customer Type
Residential	$	249.9	$	255.7		(2.3)		2,193.1		2,133.8		2.8
Commercial		155.0		161.3		(3.9)		1,569.8		1,549.3		1.3
Industrial – Phosphate		15.5		23.5		(34.0)		182.2		271.2		(32.8)
Industrial – Other		25.4		26.8		(5.2)		274.5		275.4		(0.3)
Other sales of electricity		46.7		46.9		(0.4)		462.7		438.7		5.5
Deferred and other revenues (1)		35.9		16.4		118.9
		528.4		530.6		(0.4)		4,682.3		4,668.4		0.3
Sales for resale		6.2		10.3		(39.8)		85.0		132.9		(36.0)
Other operating revenue		11.9		12.2		(2.5)
SO2 allowance sales		0.0		0.1		(100.0)
	$	546.5	$	553.2		(1.2)		4,767.3		4,801.3		(0.7)
Average customers (thousands)		675.5		671.0		0.7
Retail net energy for load (kilowatt hours)								5,188.8		5,313.4		(2.3)
Six months ended Jun. 30,
By Customer Type
Residential	$	475.2	$	522.9		(9.1)		4,167.0		4,363.8		(4.5)
Commercial		293.8		308.4		(4.7)		2,961.0		2,934.5		0.9
Industrial – Phosphate		31.0		45.0		(31.1)		366.5		514.9		(28.8)
Industrial – Other		48.6		50.8		(4.3)		525.9		518.2		1.5
Other sales of electricity		89.8		93.2		(3.6)		882.9		869.5		1.5
Deferred and other revenues (1)		2.1		13.0		(83.8)
		940.5		1,033.3		(9.0)		8,903.3		9,200.9		(3.2)
Sales for resale		12.5		20.1		(37.8)		190.0		227.1		(16.3)
Other operating revenue		26.7		24.6		8.5
SO2 Allowance sales		0.0		0.1		(100.0)
NOx Allowance sales		0.0		0.2		(100.0)
	$	979.7	$	1,078.3		(9.1)		9,093.3		9,428.0		(3.6)
Average customers (thousands)		674.8		670.5		0.6
Retail net energy for load (kilowatt hours)								9,304.1		9,949.5		(6.5)

(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 $5.9 million for the second quarter, compared to $5.1 million in the same period in 2010. Quarterly results reflect a 0.6% higher average number of customers, lower sales to residential customers due to mild spring weather and increased sales volumes to interruptible industrial customers due to the operation of several higher-usage customers that were idle in the 2010 period. Non-fuel operations and maintenance expense decreased slightly due to lower accruals of performance-based incentive compensation for all employees, partially offset by $2.1 million of expense related to the defense of environmental contamination claims. Results in the 2010 quarter included a $2.4 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%. Results also reflect increased depreciation expense due to routine plant additions.

Peoples Gas reported net income of $20.6 million for the year-to-date period, compared to $23.0 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. Gas transported for power generation customers increased over the 2010 year-to-date period due to lower natural gas prices that made it more economical to use natural gas for power generation. Non-fuel operations and maintenance expense was essentially unchanged from the 2010 period, driven primarily by the same factors as in the second quarter.

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

	Operating Revenues						Therms
(millions, except average customers)	2011		2010		% Change		2011		2010		% Change
Three months ended Jun. 30,
By Customer Type
Residential	$	28.7	$	29.2		(1.7)		13.1		13.5		(3.0)
Commercial		32.4		34.6		(6.4)		95.0		96.2		(1.2)
Industrial		2.1		2.2		(4.5)		49.4		48.5		1.9
Off system sales		33.4		36.0		(7.2)		69.8		72.7		(4.0)
Power generation		3.0		2.2		36.4		179.7		143.9		24.9
Other revenues		9.2		9.7		(5.2)
	$	108.8	$	113.9		(4.5)		407.0		374.8		8.6
By Sales Type
System supply	$	75.3	$	81.1		(7.2)		93.1		98.1		(5.1)
Transportation		24.2		23.1		4.8		313.9		276.7		13.4
Other revenues		9.2		9.7		(5.2)
	$	108.7	$	113.9		(4.6)		407.0		374.8		8.6
Average customers (thousands)		339.2		337.2		0.6
Six months ended Jun. 30,
By Customer Type
Residential	$	84.7	$	100.7		(15.9)		49.7		59.7		(16.8)
Commercial		77.4		84.6		(8.5)		217.4		221.5		(1.9)
Industrial		4.6		4.8		(4.2)		105.1		103.2		1.8
Off system sales		67.1		87.4		(23.2)		142.5		155.1		(8.1)
Power generation		5.5		4.5		22.2		296.0		272.8		8.5
Other revenues		22.8		22.4		1.8
	$	262.1	$	304.4		(13.9)		810.7		812.3		(0.2)
By Sales Type
System supply	$	186.2	$	230.0		(19.0)		217.7		244.2		(10.9)
Transportation		53.1		52.0		2.1		593.0		568.1		4.4
Other revenues		22.8		22.4		1.8
	$	262.1	$	304.4		(13.9)		810.7		812.3		(0.2)
Average customers (thousands)		339.0		336.8		0.7

TECO Coal

TECO Coal achieved second quarter net income of $15.8 million on sales of 2.1 million tons, compared to $20.7 million on sales of 2.4 million tons in the same period in 2010. Results in 2010 included a $2.0 million benefit from the settlement of state income tax issues recorded in prior years.

In 2011, results reflect an average net per-ton selling price, excluding transportation allowances, of slightly more than $89 per ton, almost 16% higher than in 2010, and above prior guidance due to a sales mix that was more heavily weighted to metallurgical and PCI coal. In the second quarter of 2011, the all-in total per-ton cost of production increased to $79 per ton, which is above the cost guidance range previously provided. Cost of production in the second quarter was driven by higher contract miner costs, higher costs of all supplies that are oil-related such as conveyor belts and tires, and lower productivity due to adverse weather. TECO Coal’s effective income tax rate in the second quarter of 2011 was 24%, the same as the 2010 period.

TECO Coal recorded year-to-date net income of $24.0 million on sales of 4.1 million tons in 2011, compared to $37.5 million on sales of 4.6 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 second quarter. The 2011 year-to-date average net per-ton selling price was $85 per ton and the all-in total per-ton cost of production was approximately $78 per ton. TECO Coal’s effective income tax rate was 22%, compared to 23%, excluding the effect of the state income tax settlements discussed above, in the 2010 year-to-date period.

TECO Coal’s year-to-date cost of production includes $0.35 per ton of costs associated with core drilling and exploration activities in an ongoing program to identify additional specialty coal (metallurgical and PCI) reserves on properties already under its control. These activities to identify incremental specialty coal reserves are in support of TECO Coal’s efforts to grow specialty coal sales to 50% of the sales mix within two years.

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TECO Guatemala

TECO Guatemala reported second quarter net income of $5.6 million in 2011, compared to $10.6 million in the 2010 period. Year-to-date 2011 net income was $11.9 million, compared to $21.0 million in the 2010 period. Results in the 2011 quarter reflect no earnings from DECA II (sold in October 2010), which were $4.8 million and $8.0 million in the 2010 quarter and year-to-date periods, respectively, and $1.7 million and $3.5 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 also reflect normal capacity payments compared to 2010 when the payments were reduced for a portion of the quarter due to unplanned outages in 2009, higher prices for spot energy sales, and lower interest expense due to lower rates on the non-recourse debt.

Parent & other

The cost for Parent & other in the second quarter of 2011 was $8.2 million, compared to a cost of $17.7 million in the same period in 2010. Results in 2011 reflect $3.5 million lower interest expense as a result of the 2011 debt retirements and the 2010 debt restructuring and retirement actions. In 2010, the cost for Parent & other included a $4.1 million charge for parent debt retirement. Results in 2010 also included a $0.7 million negative valuation adjustment to foreign tax credits based on estimated foreign source income and projected timing of the utilization of the net operating loss (NOL) carry forwards.

The year-to-date Parent & other cost was $17.3 million in 2011, compared to $55.1 million in the 2010 period. Results in 2011 reflect $7.3 million lower interest expense as a result of the 2011 debt retirements and the 2010 debt restructuring and retirement actions. The 2010 year-to-date cost included $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, 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 the first quarter.

Income Taxes

The provisions for income taxes from continuing operations for the six month periods ended Jun. 30, 2011 and 2010, were $72.5 million and $70.4 million, respectively.

Liquidity and Capital Resources

The table below sets forth the Jun. 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 Jun. 30, 2011 (millions)	Consolidated		Tampa Electric Company		Other		Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts / LCs		32.7		7.7		0.0		25.0
Available credit facilities		642.3		467.3		0.0		175.0
Cash and short-term investments		61.8		10.9		28.3		22.6
Total liquidity	$	704.1	$	478.2	$	28.3	$	197.6

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 Jun. 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 Jun. 30, 2011. Reference is made to the specific agreements and instruments for more details.

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Significant Financial Covenants

(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Jun.  30, 2011
Tampa Electric Company
Credit facility(2)	Debt/capital	Cannot exceed 65%		48.1%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%		48.1%
6.25% senior notes	Debt/capital	Cannot exceed 60%		48.1%
	Limit on liens(3)	Cannot exceed $700		$0 liens outstanding
Insurance agreement relating to certain pollution bonds	Limit on liens(3)	Cannot exceed $439 (7.5% of net assets)		$0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	EBITDA/interest(4)	Minimum of 2.6 times		4.7 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 Jun. 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 13 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.

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2011 Guidance and Business Drivers

Based on strong year-to-date actual results and expectations for the remainder of the year consistent with prior guidance, TECO Energy is maintaining its 2011 earnings per share guidance range of $1.25 to $1.40, excluding charges and gains, and is updating its business drivers as discussed below.

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 2010; however, due to the unusual weather experienced in 2010, it expects lower energy sales in 2011 assuming normal weather. In 2010, weather added between $30 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 now 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, which is $1 per ton higher than at the time guidance was originally provided, due to a higher percentage of specialty coal sales. The lower coal sales are driven by the year-to-date delays in mine plan approvals by regulatory authorities and the availability of contract miners. All of the expected 2011 sales are under contract. The selling price will average more than $90 per ton over the remainder of the year due to the completion of shipments of tons to European customers under contracts signed in 2010 in the first quarter. 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 cost of production is now expected to be at the high end of the previously provided cost range of $74 and $78 per ton, due to higher contract miner costs, higher safety related costs, higher royalties and severance costs, which are a function of selling price, and higher surface mining cost, primarily due to longer hauling distances as a result of delays in the issuance of permits. TECO Coal’s effective income tax rate is expected to be about 25% for the full year.

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 Sep. 14, 2010. TECO Guatemala’s results will 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 will reflect 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 the strength of the economic and housing market recovery in Florida, weather and customer usage at the Florida utilities, and margins at TECO Coal.

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.

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

The valuation methods we used to determine fair value are described 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 Jun. 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.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

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

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 11% from Dec. 31, 2010 to Jun. 30, 2011. For natural gas, the company maintains a similar volume hedged as of Jun. 30, 2011 from Dec. 31, 2010.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three months ended Jun. 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		(4.2	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		20.8
Net fair value of derivatives as of Jun. 30, 2011	$	(10.3	)
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		(4.2	)
Recorded in earnings		0.0
Realized net settlement of derivatives		20.8
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Jun. 30, 2011	$	(10.3	)

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

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Jun. 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)		(9.4)		(0.9)		(10.3)
Model prices (2)		0.0		0.0		0.0
Total	$	(9.4)	$	(0.9)	$	(10.3)

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

(2) Model prices are used for determining the fair value of energy derivatives where price quotes are infrequent or the market is illiquid. Significant inputs to the models are derived from market-observable data and actual historical experience.

For all unrealized derivative contracts, the valuation is an estimate based on the best available information. Actual cash flows could be materially different from the estimated value upon maturity.

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Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

(a) Evaluation of Disclosure Controls and Procedures. TECO Energy’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this quarterly report (the Evaluation Date). Based on such evaluation, TECO Energy’s principal financial officer and principal executive officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective.

(b) Changes in Internal Controls. There was no change in TECO Energy’s internal control over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TECO Energy’s internal 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 the recently proposed Item 106 of Regulation S-K (17 CFR 229.106) is included in Exhibit 99.1 to this quarterly report.

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PART II. OTHER INFORMATION

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

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

	(a) Total Number  of Shares (or Units) Purchased (1)		(b) Average Price Paid  per Share (or Unit)		(c) Total Number of  Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Apr. 1, 2011 – Apr. 30, 2011		215,213	$	18.85		0.0	$	0.0
May 1, 2011 – May 31, 2011		6,517	$	19.05		0.0	$	0.0
Jun. 1, 2011 – Jun. 30, 2011		1,326	$	18.93		0.0	$	0.0
Total 2nd Quarter 2011		223,056	$	18.86		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 59.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		TECO ENERGY, INC.
		(Registrant)
Date:	August 5, 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:	August 5, 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)

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INDEX TO EXHIBITS

Exhibit No.	Description
3.1	Articles of Incorporation of TECO Energy, Inc., as amended on Apr. 20, 1993 (Exhibit 3, Form 10 Q for the quarter ended Mar. 31, 1993 of TECO Energy, Inc.).	*
3.2	Bylaws of TECO Energy, Inc., as amended effective 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.

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