Tampa Electric 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2010

OR

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

For the transition period from            to            

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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.    YES  x    NO  ¨

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).    YES  x    NO  ¨

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

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

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

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

Indicate by check mark whether TECO Energy, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

Indicate by check mark whether Tampa Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Oct. 28, 2010 was 214,742,478. As of Oct. 28, 2010, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

Tampa Electric Company meets the conditions set forth in General Instruction (H) (1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

This combined Form 10-Q represents separate filings by TECO Energy, Inc. and Tampa Electric Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Each registrant makes representations only as to information relating to itself and its subsidiaries.

Page 1 of 62

Index to Exhibits appears on page 61.

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sep. 30, 2010 and Dec. 31, 2009, and the results of their operations and cash flows for the periods ended Sep. 30, 2010 and 2009. The financial statements for the periods ended Sep. 30, 2010 include the financial position, results of operations and cash flows for two power generation projects in Guatemala, previously reflected as unconsolidated affiliates, that were reconsolidated effective Jan. 1, 2010 in accordance with new accounting guidance. The results of operations for the three month and nine month periods ended Sep. 30, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010. 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, 2009 and to the notes on pages 9 through 30 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2010 and Dec. 31, 2009		3-4
Consolidated Condensed Statements of Income for the three month and nine month periods ended Sep. 30, 2010 and 2009		5-6
Consolidated Condensed Statements of Comprehensive Income for the three month and nine month periods ended Sep. 30, 2010 and 2009		7
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2010 and 2009		8
Notes to Consolidated Condensed Financial Statements		9-30

2

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions, except for share amounts)	Sep. 30, 2010			Dec. 31, 2009
Current assets
Cash and cash equivalents	$	151.6		$	46.0
Short-term investments		14.7			0.8
Receivables, less allowance for uncollectibles of $3.5 and $3.0 at Sep. 30, 2010 and Dec. 31, 2009, respectively		371.5			277.4
Inventories, at average cost
Fuel		156.8			124.3
Materials and supplies		77.8			65.7
Current derivative asset		0.8			0.8
Current regulatory assets		67.6			109.2
Prepayments and other current assets		31.5			25.7
Income tax receivables		2.1			1.7
Total current assets		874.4			651.6
Property, plant and equipment
Utility plant in service
Electric		6,521.6			6,079.5
Gas		1,041.0			1,017.2
Construction work in progress		249.0			304.5
Other property		395.4			377.2
Property, plant and equipment		8,207.0			7,778.4
Accumulated depreciation		(2,411.1	)		(2,234.3	)
Total property, plant and equipment, net		5,795.9			5,544.1
Other assets
Deferred income taxes		84.3			222.7
Long-term regulatory assets		327.4			335.6
Long-term derivative assets		0.2			0.2
Investment in unconsolidated affiliates		137.8			279.3
Goodwill		59.4			59.4
Deferred charges and other assets		150.6			126.6
Total other assets		759.7			1,023.8
Total assets	$	7,430.0		$	7,219.5

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

3

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets –continued

Unaudited

Liabilities and Capital (millions, except for share amounts)	Sep. 30, 2010			Dec. 31, 2009
Current liabilities
Long-term debt due within one year
Recourse	$	67.1		$	106.5
Non-recourse		10.1			1.4
Notes payable		27.0			55.0
Accounts payable		257.1			251.4
Customer deposits		154.9			151.2
Current regulatory liabilities		108.7			85.4
Current derivative liabilities		45.8			34.0
Interest accrued		72.1			45.3
Taxes accrued		61.7			20.5
Other current liabilities		17.4			20.6
Total current liabilities		821.9			771.3
Other liabilities
Investment tax credits		10.5			10.8
Long-term regulatory liabilities		614.5			602.6
Long-term derivative liabilities		5.8			3.6
Deferred credits and other liabilities		513.3			544.2
Long-term debt, less amount due within one year
Recourse		3,275.7			3,195.4
Non-recourse		37.1			6.2
Total other liabilities		4,456.9			4,362.8
Commitments and contingencies (seeNote 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 214.7 million and 213.9 million shares outstanding at Sep. 30, 2010 and Dec. 31, 2009, respectively)		214.7			213.9
Additional paid in capital		1,537.9			1,530.8
Retained earnings		417.4			365.7
Accumulated other comprehensive loss		(19.6	)		(25.0	)
TECO Energy Stockholders’ Equity		2,150.4			2,085.4
Noncontrolling interest		0.8			0.0
Total equity		2,151.2			2,085.4
Total liabilities and capital	$	7,430.0		$	7,219.5

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

4

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Three months ended Sep. 30,
(millions, except per share amounts)	2010			2009
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $31.0 in 2010 and $30.5 in 2009)	$	707.4		$	719.3
Unregulated		194.4			177.0
Total revenues		901.8			896.3
Expenses
Regulated operations
Fuel		224.5			253.5
Purchased power		45.2			46.3
Cost of natural gas sold		61.0			47.5
Other		96.1			87.1
Operation other expense
Mining related costs		119.9			123.2
Guatemalan power generation		15.6			3.0
Other		1.9			0.5
Maintenance		44.6			46.3
Depreciation and amortization		78.8			72.8
Restructuring charges		0.0			25.0
Recoveries from previously impaired assets		(2.9	)		0.0
Taxes, other than income		57.4			56.1
Total expenses		742.1			761.3
Income from operations		159.7			135.0
Other income (expense)
Allowance for other funds used during construction		0.3			2.5
Other income		10.4			1.2
Income from equity investments		3.6			11.3
Total other income		14.3			15.0
Interest charges
Interest expense		57.5			58.2
Allowance for borrowed funds used during construction		(0.1	)		(0.9	)
Total interest charges		57.4			57.3
Income before provision for income taxes		116.6			92.7
Provision for income taxes		65.5			27.9
Net income		51.1			64.8
Less: Net income attributable to noncontrolling interest		(0.1	)		0.0
Net income attributable to TECO Energy	$	51.0		$	64.8
Average common shares outstanding– Basic		212.8			211.9
– Diluted		215.1			213.2
Earnings per share attributable to TECO Energy– Basic	$	0.24		$	0.30
– Diluted	$	0.24		$	0.30
Dividends paid per common share outstanding	$	0.205		$	0.200

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

5

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Nine months ended Sep. 30,
(millions, except per share amounts)	2010			2009
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $90.0 in 2010 and $88.8 in 2009)	$	2,079.1		$	2,036.0
Unregulated		633.8			509.5
Total revenues		2,712.9			2,545.5
Expenses
Regulated operations
Fuel		573.9			707.7
Purchased power		151.5			144.6
Cost of natural gas sold		236.4			186.7
Other		280.5			245.1
Operation other expense
Mining related costs		375.1			352.6
Guatemalan power generation		48.5			9.2
Other		5.0			2.7
Maintenance		137.1			144.9
Depreciation and amortization		233.7			213.8
Restructuring charges		1.5			25.0
Recoveries from previously impaired assets		(2.9	)		0.0
Taxes, other than income		174.1			172.4
Total expenses		2,214.4			2,204.7
Income from operations		498.5			340.8
Other income (expense)
Allowance for other funds used during construction		1.6			8.3
Other income		16.0			21.3
Loss on debt extinguishment		(33.0	)		0.0
Income from equity investments		10.5			33.0
Total other income		(4.9	)		62.6
Interest charges
Interest expense		175.8			173.2
Allowance for borrowed funds used during construction		(0.9	)		(3.2	)
Total interest charges		174.9			170.0
Income before provision for income taxes		318.7			233.4
Provision for income taxes		135.9			73.0
Net income		182.8			160.4
Less: Net income attributable to noncontrolling interest		(0.5	)		0.0
Net income attributable to TECO Energy	$	182.3		$	160.4
Average common shares outstanding– Basic		212.5			211.7
– Diluted		214.6			212.8
Earnings per share attributable to TECO Energy– Basic	$	0.85		$	0.75
– Diluted	$	0.85		$	0.75
Dividends paid per common share outstanding	$	0.610		$	0.600

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Sep. 30,					Nine months ended Sep. 30,
(millions)	2010			2009		2010			2009
Net income	$	51.1		$	64.8	$	182.8		$	160.4
Other comprehensive income (loss), net of tax
Net unrealized gains on cash flow hedges		1.4			2.8		1.8			13.3
Amortization of unrecognized benefit costs and other		0.4			0.1		2.6			0.8
Recognized benefit costs due to settlement		0.0			0.0		1.0			0.0
Reclassification to earnings - loss on available-for-sale securities		0.0			0.0		0.0			1.7
Other comprehensive income, net of tax		1.8			2.9		5.4			15.8
Comprehensive income		52.9			67.7		188.2			176.2
Comprehensive income attributable to noncontrolling interests		(0.1	)		0.0		(0.5	)		0.0
Comprehensive income attributable to TECO Energy, Inc.	$	52.8		$	67.7	$	187.7		$	176.2

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sep. 30,
(millions)	2010			2009
Cash flows from operating activities
Net income	$	182.8		$	160.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		233.7			213.8
Deferred income taxes		136.5			73.0
Investment tax credits, net		(0.3	)		(0.3	)
Allowance for funds used during construction		(1.6	)		(8.3	)
Non-cash stock compensation		5.4			8.6
Gain on sale of business/assets, pretax		(0.9	)		(15.5	)
Non-cash debt extinguishment, pretax		0.9			0.0
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings		6.8			(9.2	)
Deferred recovery clauses		44.6			111.4
Receivables, less allowance for uncollectibles		(82.0	)		(50.7	)
Inventories		(28.4	)		(37.6	)
Prepayments and other current assets		(4.3	)		(1.6	)
Taxes accrued		38.6			39.2
Interest accrued		23.7			37.1
Accounts payable		36.8			(27.3	)
Other		0.7			46.9
Cash flows from operating activities		593.0			539.9
Cash flows from investing activities
Capital expenditures		(374.9	)		(499.4	)
Allowance for funds used during construction		1.6			8.3
Net proceeds from sale of business/assets		1.4			29.5
Net cash increase from consolidation		24.1			0.0
Restricted cash		0.0			0.5
Contributions to unconsolidated affiliates		(1.7	)		(0.2	)
Other investments		(13.9	)		17.1
Cash flows used in investing activities		(363.4	)		(444.2	)
Cash flows from financing activities
Dividends		(130.7	)		(128.1	)
Proceeds from the sale of common stock		5.6			3.5
Proceeds from long-term debt		543.5			102.1
Repayment of long-term debt/Purchase in lieu of redemption		(513.7	)		(6.9	)
Dividend to noncontrolling interest		(0.7	)		0.0
Net decrease in short-term debt		(28.0	)		(33.0	)
Cash flows used in financing activities		(124.0	)		(62.4	)
Net increase in cash and cash equivalents		105.6			33.3
Cash and cash equivalents at beginning of period		46.0			12.2
Cash and cash equivalents at end of period	$	151.6		$	45.5

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. Prior periods presented in this quarterly report were not restated. (SeeNote 16.)

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy is not the primary beneficiary but is able to exert significant influence. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sep. 30, 2010 and Dec. 31, 2009, and the results of operations and cash flows for the periods ended Sep. 30, 2010 and 2009. The results of operations for the three and nine month periods ended Sep. 30, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010.

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

Revenues

As of Sep. 30, 2010 and Dec. 31, 2009, unbilled revenues of $60.3 million and $51.6 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 $31.0 million and $90.0 million, respectively, for the three and nine months ended Sep. 30, 2010, compared to $30.5 million and $88.8 million, respectively, for the three and nine months ended Sep. 30, 2009. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These totaled $31.1 million and $89.9 million, respectively, for the three and nine months ended Sep. 30, 2010, compared to $30.5 million and $88.7 million, respectively, for the three and nine months ended Sep. 30, 2009.

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 $45.2 million and $151.5 million, respectively, for the three and nine months ended Sep. 30, 2010, compared to $46.3 million and $144.6 million, respectively, for the three and nine months ended Sep. 30, 2009. 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, primarily at TECO Coal, the cash inflows and outflows are included in the operating section. For natural gas, primarily at Tampa Electric and PGS, 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

Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses

In July 2010, the Financial Accounting Standards Board (FASB) issued guidance requiring improved disclosures about the credit quality of a company’s financing receivables and their associated credit reserves. The guidance is effective for interim and annual periods that end after Dec. 15, 2010. This guidance will not have any effect on the company’s results of operations, statement of position or cash flows.

Subsequent Events

In February 2010, the FASB issued additional guidance related to subsequent event disclosure. The guidance was effective upon issuance and has no effect on the company’s results of operations, statement of position or cash flows.

Fair Value Measures and Disclosures

In January 2010, the FASB issued guidance that requires entities to disclose more information regarding the movements between Levels 1 and 2 of the fair value hierarchy. The guidance is effective for fiscal years that begin after Dec. 15, 2010, and for interim periods within that year. This guidance will not have any effect on the company’s results of operations, statement of 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 regulation 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.

Stipulation with Intervenors – Tampa Electric

As previously reported in the company’s Annual Report on Form 10-K for the period ended Dec. 31, 2009, the FPSC, in connection with Tampa Electric’s 2008 base rate request, approved a $25.7 million increase in base rates effective Jan. 1, 2010 (step increase), subject to refund, for certain capital additions placed in service in 2009.

In connection with the base rate request, the FPSC had rejected the intervenors’ arguments that the approved 2010 increase violated the intervenors’ due process rights, Florida Statutes or FPSC rules. The intervenors filed an appeal with the Florida Supreme Court in September 2009, which Tampa Electric opposed.

In July 2010, Tampa Electric entered into a stipulation with the intervenors to resolve all issues related to the 2008 base rate case including the 2010 step increase, as well as the intervenors’ appeal to the Florida Supreme Court. Under the terms of the stipulation, the $25.7 million step increase would remain in effect for 2010, and Tampa Electric would make a one-time reduction of $24.0 million to customers’ bills in 2010.

In August 2010, the FPSC voted to approve the July stipulation, which was contained in their Docket No. 090368-EI “Review of the continuing need and cost associated with Tampa Electric Company’s 5 Combustion Turbines and Big Bend Rail Facility”. This stipulation now resolves all issues in the above docket and all issues in the intervenors’ appeal of the FPSC’s 2009 decision in Tampa Electric’s base rate proceeding pending before the Florida Supreme Court. The docket related to the base rate proceeding is now closed. The one-time reduction of $24.0 million to customers’ bills in 2010 is reflected in the third quarter operating results as a reduction in revenue.

Effective Jan. 1, 2011, and for subsequent years, rates of $24.4 million (a $1.3 million reduction from the $25.7 million in effect for 2010) related to the step increase will be in effect.

Wholesale and Transmission Rate Cases

In July 2010, Tampa Electric filed wholesale requirements and transmission rate cases with the FERC. Tampa Electric’s last wholesale requirements rate case was in 1991 and the associated service agreements were approved by the FERC in the mid-1990s.

10

The FERC approved Tampa Electric’s proposed transmission rates as filed with the FERC, which became effective Sep. 14, 2010, subject to refund. The FERC also approved Tampa Electric’s proposed wholesale requirements rates, as filed with the FERC, to become effective Mar. 1, 2011, subject to refund. The proposed wholesale requirements and transmission rates are not expected to have a material impact on Tampa Electric’s results.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually effective May 2009 to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $35.4 million and $29.3 million as of Sep. 30, 2010 and Dec. 31, 2009, respectively.

Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year.

Details of the regulatory assets and liabilities as of Sep. 30, 2010 and Dec. 31, 2009 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sep. 30, 2010		Dec. 31, 2009
Regulatory assets:
Regulatory tax asset(1)	$	67.8	$	69.0
Other:
Cost recovery clauses		51.1		89.4
Postretirement benefit asset		219.6		229.1
Deferred bond refinancing costs(2)		15.2		18.0
Environmental remediation		21.9		21.2
Competitive rate adjustment		3.2		3.1
Other		16.2		15.0
Total other regulatory assets		327.2		375.8
Total regulatory assets		395.0		444.8
Less: Current portion		67.6		109.2
Long-term regulatory assets	$	327.4	$	335.6
Regulatory liabilities:
Regulatory tax liability(1)	$	16.4	$	19.6
Other:
Cost recovery clauses		52.1		61.4
Environmental remediation		19.9		19.9
Transmission and delivery storm reserve		35.4		29.3
Deferred gain on property sales(3)		1.5		2.8
Provision for stipulation and other (4)		34.0		0.7
Accumulated reserve-cost of removal		563.9		554.3
Total other regulatory liabilities		706.8		668.4
Total regulatory liabilities		723.2		688.0
Less: Current portion		108.7		85.4
Long-term regulatory liabilities	$	614.5	$	602.6

(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 one-time credit to be applied to Tampa Electric customers’ bills in the fourth quarter of 2010 related to the stipulation and a provision for PGS’ estimated earnings above its allowed return on equity range of 9.75% to 11.75%. The disposition of any earnings above the top of PGS’ allowed range would be determined by the FPSC.

11

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

Regulatory assets
(millions)	Sep. 30, 2010		Dec. 31, 2009
Clause recoverable(1)	$	54.3	$	92.5
Components of rate base(2)		229.8		238.1
Regulatory tax assets(3)		67.8		69.0
Capital structure and other(3)		43.1		45.2
Total	$	395.0	$	444.8

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

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

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

4. 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 2008 consolidated federal income tax return during 2009. During the third quarter, the company received and agreed to a proposed settlement related to the only outstanding issue for the 2008 tax return. The settlement is expected to be finalized in the fourth quarter, without material impact on earnings or operating cash flows. The U.S. federal statute of limitations remains open for the year 2007 and onward. Years 2009 and 2010 are currently under examination by the IRS under their Compliance Assurance Program. The company does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2010. 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 first and second quarters of 2010, the company reached a favorable settlement for certain state items that were under appeal and as a result recorded a $4.0 million after-tax benefit, excluding interest. No additional amounts were recorded during the third quarter of 2010. Therefore, during the nine months ending Sep. 30, 2010, the company recorded a $4.0 million after-tax benefit, excluding interest, for these state items.

The company recognizes interest and penalties associated with uncertain tax positions in the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. During the first and second quarters of 2010, the company recorded $2.0 million in pretax interest income as a result of finalizing the settlement of certain state tax items. During the nine month periods ended Sep. 30, 2010 and Sep. 30, 2009, the company recorded ($1.2) million and $0.7 million, respectively, of pretax (income) charges for interest only. No amounts have been recorded for penalties for the nine month periods ended Sep. 30, 2010 or Sep. 30, 2009.

The effective tax rate increased to 42.63% for the nine months ended Sep. 30, 2010 from 31.28% for the same period in 2009, primarily due to $24.9 million of U.S. deferred taxes recognized on undistributed earnings of certain foreign subsidiaries which are no longer considered indefinitely reinvested, and an additional $5.9 million valuation allowance related to our updated, anticipated ability to use foreign tax credits. SeeNote 17 for more details.

12

5. Employee Postretirement Benefits

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Sep. 30,	2010			2009			2010		2009
Components of net periodic benefit expense
Service cost	$	4.0		$	4.0		$	0.8	$	0.8
Interest cost on projected benefit obligations		8.2			8.5			2.8		2.9
Expected return on assets		(9.0	)		(9.5	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.5		0.6
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.2
Actuarial loss		3.2			2.2			0.0		0.0
Pension expense		6.3			5.1			4.3		4.5
Curtailment loss		0.0			0.2			0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	6.3		$	5.3		$	4.3	$	4.5
Nine months ended Sep. 30,
Components of net periodic benefit expense
Service cost	$	12.1		$	11.8		$	2.4	$	2.3
Interest cost on projected benefit obligations		24.9			25.3			8.2		8.5
Expected return on assets		(27.2	)		(28.4	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			1.7		1.7
Prior service (benefit) cost		(0.3	)		(0.3	)		0.6		0.6
Actuarial loss		9.4			6.5			0.0		0.0
Pension expense		18.9			14.9			12.9		13.1
Curtailment loss		0.0			0.2			0.0		0.0
Settlement cost		1.6			0.0			0.0		0.0
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	20.5		$	15.1		$	12.9	$	13.1

For the fiscal 2010 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.75% for pension benefits under its qualified pension plan, and a discount rate of 5.60% for its other postretirement benefits as of their Jan. 1, 2010 measurement dates. Additionally, TECO Energy assumed a discount rate of 5.75% for its Supplemental Executive Retirement Plan (SERP) benefits as of its Mar. 1 and Jan. 1, 2010 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 months and nine months ended Sep. 30, 2010, TECO Energy and its subsidiaries reclassed $0.6 million and $1.8 million, respectively, of unamortized transition obligation, prior service cost and actuarial gains and losses from accumulated other comprehensive income to net income as part of periodic benefit expense. In addition, during the three months and nine months ended Sep. 30, 2010, Tampa Electric Company reclassed $3.1 million and $9.5 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 a settlement charge of $1.6 million for the nine months ended Sep. 30, 2010 for pay-outs from its SERP.

In September 2010, TECO Energy made a contribution to its qualified pension plan of $34.5 million.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, The Health Care and Education Reconciliation Act (the Acts) were signed into law. Among other things, the 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. TECO Energy is reviewing certain other aspects of the Acts that could impact the cost of medical benefits provided to retirees and active employees. These impacts are not expected to be material to the company’s future results of operations, statement of position or cash flows.

13

6. Short-Term Debt

At Sep. 30, 2010 and Dec. 31, 2009, the following credit facilities and related borrowings existed:

Credit Facilities
	Sep. 30, 2010						Dec. 31, 2009
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of  Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility	$	325.0	$	0.0	$	0.9	$	325.0	$	55.0	$	0.7
1-year accounts receivable facility		150.0		27.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility(2)		200.0		0.0		6.7		200.0		0.0		6.9
Total	$	675.0	$	27.0	$	7.6	$	675.0	$	55.0	$	7.6

(1) Borrowings outstanding are reported as notes payable.

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

These credit facilities require commitment fees ranging from 7.0 to 60.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Sep. 30, 2010 and Dec. 31, 2009 was 0.85% and 0.66%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 19, 2010, Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 8 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. 18, 2011, (ii) provides that TRC will pay program and liquidity fees, which, pursuant to the amendment, will total 100 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

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

On Mar. 15, 2010, TECO Finance, Inc. issued $250 million aggregate principal amount of 4.00% Notes due Mar. 15, 2016 and $300 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 a portion of 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.

14

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 million principal amount of TECO Energy notes for cash and approximately $230 million principal amount of TECO Finance notes for cash.

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

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

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

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

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

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

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

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

Redemption of TECO Energy, Inc. 7.2% Notes due 2011

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

Reconsolidation of TCAE and CGESJ

Effective Jan. 1, 2010, new accounting standards for consolidations amended the determination of the primary beneficiaries for variable interest entities. As a result of adopting these standards, TECO Guatemala, Inc., a wholly-owned subsidiary of TECO Energy, was determined to be the primary beneficiary of, and therefore required to consolidate, both the Tampa Centro Americana de Electricidad (TCAE) and Central Generadora Eléctrica San José (CGESJ) projects in Guatemala. (SeeNote 16.) The consolidation resulted in a net $44.4 million increase of non-recourse debt.

15

8. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (OCI) for the three months and nine months ended Sep. 30, 2010 and 2009, related to changes in the fair value of cash flow hedges, amortization of unrecognized benefit costs associated with the company’s pension plans and unrecognized gains and losses on available-for-sale securities:

Other Comprehensive Income
	Three months ended Sep. 30,									Nine months ended Sep. 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2010
Unrealized gain (loss) on cash flow hedges	$	0.9		($	0.2	)	$	0.7		($	0.5	)	$	0.2		($	0.3	)
Plus: Loss reclassified to net income		1.2			(0.5	)		0.7			3.4			(1.3	)		2.1
Gain on cash flow hedges		2.1			(0.7	)		1.4			2.9			(1.1	)		1.8
Amortization of unrecognized benefit costs and other		0.6			(0.2	)		0.4			1.8			0.8			2.6
Recognized benefit costs due to settlement		0.0			0.0			0.0			1.6			(0.6	)		1.0
Total other comprehensive income	$	2.7		($	0.9	)	$	1.8		$	6.3		($	0.9	)	$	5.4
2009
Unrealized (loss) gain on cash flow hedges	($	1.4	)	$	0.5		($	0.9	)	$	1.7		($	0.6	)	$	1.1
Plus: Loss reclassified to net income		5.8			(2.1	)		3.7			19.4			(7.2	)		12.2
Gain on cash flow hedges		4.4			(1.6	)		2.8			21.1			(7.8	)		13.3
Amortization of unrecognized benefit costs		0.5			(0.2	)		0.3			1.6			(0.6	)		1.0
Change in benefit obligation due to remeasurement		(0.3	)		0.1			(0.2	)		(0.3	)		0.1			(0.2	)
Reclassification to earnings loss on available-for-sale securities		0.0			0.0			0.0			1.7			0.0			1.7
Total other comprehensive income	$	4.6		($	1.7	)	$	2.9		$	24.1		($	8.3	)	$	15.8

Accumulated Other Comprehensive Loss
(millions)	Sep. 30, 2010			Dec. 31, 2009
Unrecognized pension losses and prior service costs(1)	($	25.8	)	($	27.8	)
Unrecognized other benefit gains, prior service costs and transition obligations(2)		11.7			10.1
Net unrealized losses from cash flow hedges(3)		(5.5	)		(7.3	)
Total accumulated other comprehensive loss	($	19.6	)	($	25.0	)

(1) Net of tax benefit of $15.9 million and $17.1 million as of Sep. 30, 2010 and Dec. 31, 2009, respectively.

(2) Net of tax expense of $4.6 million and $6.0 million as of Sep. 30, 2010 and Dec. 31, 2009, respectively.

(3) Net of tax benefit of $3.4 million and $4.5 million as of Sep. 30, 2010 and Dec. 31, 2009, respectively.

16

9. Earnings Per Share

Earnings Per Share
	Three months ended Sep. 30,						Nine months ended Sep. 30,
(millions, except per share amounts)	2010			2009			2010			2009
Basic earnings per share
Net income	$	51.1		$	64.8		$	182.8		$	160.4
Less: Income attributable to noncontrolling interest		(0.1	)		0.0			(0.5	)		0.0
Less: Amount allocated to nonvested participating shareholders		(0.4	)		(0.5	)		(1.3	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - basic	$	50.6		$	64.3		$	181.0		$	159.0
Average shares outstanding common		212.8			211.9			212.5			211.7
Basic earnings per share attributable to TECO Energy available to common shareholders	$	0.24		$	0.30		$	0.85		$	0.75
Diluted earnings per share
Net income	$	51.1		$	64.8		$	182.8		$	160.4
Less: Income attributable to noncontrolling interest		(0.1	)		0.0			(0.5	)		0.0
Less: Amount allocated to nonvested participating shareholders		(0.4	)		(0.5	)		(1.3	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - diluted	$	50.6		$	64.3		$	181.0		$	159.0
Average shares outstanding common		212.8			211.9			212.5			211.7
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		2.3			1.3			2.1			1.1
Adjusted average shares outstanding common - diluted		215.1			213.2			214.6			212.8
Diluted earnings per share attributable to TECO Energy available to common shareholders	$	0.24		$	0.30		$	0.85		$	0.75
Anti-dilutive shares		2.5			5.7			4.3			6.1

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, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

TECO Coal Corporation and Premier Elkhorn Coal Corporation v. Orlando Utilities Commission (OUC)

TECO Coal Corporation and Premier Elkhorn Corporation (collectively TECO Coal) wholly-owned subsidiaries of TECO Energy, Inc., filed a declaratory judgment suit on Dec. 21, 2007, in the U.S. District Court for the Eastern District of Kentucky. The dispute stems from a 1995 coal supply contract that contains a mechanism to adjust the contract price every six months based on changes in government-published indexes intended to track changes in unit costs in TECO Coal’s cost of production for supplying the coal. TECO Coal maintains that it is commercially impractical to continue the contract because that mechanism has not worked as intended and has resulted in an unintended windfall for OUC. OUC has filed a counterclaim unrelated to the commercial impracticability claim that seeks damages for TECO Coal’s failure to deliver coal in 2008 when TECO Coal notified OUC of its inability to deliver coal as a result of force majeure.

17

On Sep. 17, 2010, the Court granted OUC’s motion for summary judgment against TECO Coal’s claim and denied OUC’s motion for summary judgment on its breach of contract counterclaim against TECO Coal which is expected to proceed to trial during the first half of 2011. TECO Coal cannot appeal the dismissal of its claim until after the trial. As of Sep. 30, 2010, the ultimate resolution of this proceeding is uncertain and no potential loss has been accrued.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through Tampa Electric and PGS, is a potentially responsible party (PRP) for certain superfund sites and, through PGS, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2010, Tampa Electric Company has estimated its ultimate financial liability to be $19.9 million, primarily at PGS, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves 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 federal Superfund law 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, is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company is in the process of responding to such matter, and the scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

18

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and Tampa Electric Company’s letters of credit and guarantees as of Sep. 30, 2010 is as follows:

Letters of Credit and Guarantees-TECO Energy
(millions)	2010		2011-2014		After(1) 2014		Total		Liabilities Recognized at Sep. 30, 2010
Letters of Credit and Guaranteesfor the Benefit of:
Tampa Electric
Guarantees:
Fuel purchase/energy management(2)	$	0.0	$	0.0	$	20.0	$	20.0	$	1.0
		0.0		0.0		20.0		20.0		1.0
TECO Coal
Letters of credit		0.0		0.0		6.7		6.7		0.0
Guarantees: Fuel purchase related(2)		0.0		0.0		5.4		5.4		1.3
		0.0		0.0		12.1		12.1		1.3
Other subsidiaries
Guarantees:
Fuel purchase/energy management(2)		0.0		0.0		109.7		109.7		0.0
Total	$	0.0	$	0.0	$	141.8	$	141.8	$	2.3
Letters of Credit-Tampa Electric Company
(millions)	2010		2011-2014		After(1) 2014		Total		Liabilities Recognized at Sep. 30, 2010
Letters of Credit for the Benefit of:
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.9	$	0.9	$	0.0
Total	$	0.0	$	0.0	$	0.9	$	0.9	$	0.0

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2014.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sep. 30, 2010. 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 other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2010, 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.

19

Segment Information(1)
(millions) Three months ended Sep. 30,	Tampa(3) Electric		Peoples Gas		TECO Coal		TECO (2) Guatemala			Other & Eliminations			TECO Energy
2010
Revenues - external	$	593.3	$	114.1	$	165.3	$	29.0		$	0.1		$	901.8
Sales to affiliates		0.3		2.5		0.0		0.0			(2.8	)		0.0
Total revenues		593.6		116.6		165.3		29.0			(2.7	)		901.8
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		4.1			(0.5	)		3.6
Depreciation		54.4		11.5		11.0		1.8			0.1			78.8
Total interest charges(1)		30.7		4.6		1.6		4.0			16.5			57.4
Internally allocated interest(1)		0.0		0.0		1.5		3.0			(4.5	)		0.0
Provision (benefit) for taxes		36.8		2.4		2.2		29.1			(5.0	)		65.5
Net income (loss) attributable to TECO Energy	$	61.9	$	3.7	$	8.3	($	12.6	)	($	10.3	)	$	51.0
2009
Revenues - external	$	620.6	$	98.7	$	175.1	$	1.9		$	0.0		$	896.3
Sales to affiliates		0.3		2.3		0.0		0.0			(2.6	)		0.0
Total revenues		620.9		101.0		175.1		1.9			(2.6	)		896.3
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		11.3			0.0			11.3
Depreciation		50.8		11.1		10.6		0.2			0.1			72.8
Restructuring charges		18.1		4.5		0.0		0.0			2.4			25.0
Total interest charges(1)		29.8		4.6		1.8		3.3			17.8			57.3
Internally allocated interest(1)		0.0		0.0		1.6		3.2			(4.8	)		0.0
Provision (benefit) for taxes		31.9		2.2		3.7		1.1			(11.0	)		27.9
Net income (loss) attributable to TECO Energy	$	54.3	$	3.4	$	11.6	$	8.1		($	12.6	)	$	64.8
(millions) Nine months ended Sep. 30,	Tampa Electric		Peoples Gas		TECO Coal		TECO (2) Guatemala			Other & Eliminations			TECO Energy
2010
Revenues - external	$	1,670.9	$	408.2	$	537.9	$	95.7		$	0.2		$	2,712.9
Sales to affiliates		1.0		17.4		0.0		0.0			(18.4	)		0.0
Total revenues		1,671.9		425.6		537.9		95.7			(18.2	)		2,712.9
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		12.1			(1.6	)		10.5
Depreciation		161.0		34.3		32.8		5.4			0.2			233.7
Restructuring charges		0.0		0.0		0.0		0.0			1.5			1.5
Total interest charges(1)		91.8		13.8		5.2		13.0			51.1			174.9
Internally allocated interest(1)		0.0		0.0		5.0		9.5			(14.5	)		0.0
Provision (benefit) for taxes		98.4		16.9		9.1		35.9			(24.4	)		135.9
Net income (loss) attributable to TECO Energy	$	166.8	$	26.7	$	45.8	$	8.4		($	65.4	)	$	182.3
2009
Revenues - external	$	1,691.1	$	344.9	$	503.4	$	6.0		$	0.1		$	2,545.5
Sales to affiliates		1.0		12.2		0.0		0.0			(13.2	)		0.0
Total revenues		1,692.1		357.1		503.4		6.0			(13.1	)		2,545.5
Equity earnings of unconsolidated affiliates		0.0		0.0		0.0		33.0			0.0			33.0
Depreciation		148.1		32.9		32.0		0.6			0.2			213.8
Restructuring charges		18.1		4.5		0.0		0.0			2.4			25.0
Total interest charges(1)		86.6		14.1		5.5		9.6			54.2			170.0
Internally allocated interest(1)		0.0		0.0		4.8		9.4			(14.2	)		0.0
Provision (benefit) for taxes		69.1		12.3		6.7		10.7			(25.8	)		73.0
Net income (loss) attributable to TECO Energy	$	121.1	$	19.2	$	29.7	$	29.2		($	38.8	)	$	160.4
At Sep. 30, 2010
Goodwill	$	0.0	$	0.0	$	0.0	$	59.4		$	0.0		$	59.4
Investment in unconsolidated affiliates		0.0		0.0		0.0		137.6			0.2			137.8
Total assets	$	5,834.1	$	884.8	$	331.1	$	452.9		($	72.9	)	$	7,430.0
At Dec. 31, 2009
Goodwill	$	0.0	$	0.0	$	0.0	$	59.4		$	0.0		$	59.4
Investment in unconsolidated affiliates		0.0		0.0		0.0		279.2			0.1			279.3
Total assets	$	5,697.9	$	870.1	$	326.6	$	380.7		($	55.8	)	$	7,219.5

20

(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 July through September 2010 were at a pretax rate of 6.50% and for January through June 2010 and 2009 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.

(2) Revenues for 2009 are exclusive of entities deconsolidated as a result of the accounting guidance for variable interest entities. Total revenues for unconsolidated affiliates, attributable to TECO Guatemala based on ownership percentages, were $30.8 million and $62.2 million for the three and nine months ended Sep. 30, 2009. Net income attributable to TECO Energy for the nine months ended Sep. 30, 2009 includes the gain on the sale of a 16.5% interest in the Central American fiber optic telecommunication provider Navega. Entities were consolidated as of Jan. 1, 2010 as a result of accounting guidance effective on that date. SeeNote 16 for more information. The Provision for taxes for the three months ended Sep. 30, 2010 includes $24.9 million of U.S. deferred taxes recognized on undistributed earnings. SeeNote 4 for more information.

(3) Revenues for the three months and nine months ended Sep. 30, 2010 reflect the reduction resulting from the FPSC stipulation of $24.0 million. SeeNote 3 for more information.

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.

New accounting standards for disclosures became effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008. This new standard requires enhanced disclosures about a company’s derivative activities and how the related hedged items affect a company’s financial position, financial performance and cash flows. The new requirements include quantitative disclosures about the company’s fair value amounts of gains and losses associated with derivative instruments, as well as disclosures about credit-risk-related contingent features in derivative agreements. The company adopted this new standard effective Jan. 1, 2009.

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 to reflect the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (seeNote 3).

A company’s physical contracts qualify for the normal purchase/normal sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Sep. 30, 2010, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at Sep. 30, 2010 and Dec. 31, 2009:

Total Derivatives(1)
(millions)	Sep. 30, 2010		Dec. 31, 2009
Current assets	$	0.8	$	0.8
Long-term assets		0.2		0.2
Total assets	$	1.0	$	1.0
Current liabilities	$	45.8	$	34.0
Long-term liabilities		5.8		3.6
Total liabilities	$	51.6	$	37.6

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

22

The following table presents the derivative hedges of heating oil contracts at Sep. 30, 2010 and Dec. 31, 2009 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Heating Oil Derivatives
(millions)	Sep. 30, 2010		Dec. 31, 2009
Current assets	$	0.1	$	0.0
Long-term assets		0.2		0.2
Total assets	$	0.3	$	0.2
Current liabilities	$	0.0	$	0.9
Long-term liabilities		0.0		0.0
Total liabilities	$	0.0	$	0.9

The following table presents the derivative hedges of natural gas contracts at Sep. 30, 2010 and Dec. 31, 2009 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sep. 30, 2010		Dec. 31, 2009
Current assets	$	0.7	$	0.8
Long-term assets		0.0		0.0
Total assets	$	0.7	$	0.8
Current liabilities	$	45.5	$	33.1
Long-term liabilities		5.8		3.6
Total liabilities	$	51.3	$	36.7

The ending balance in accumulated other comprehensive income (AOCI) related to the cash flow hedges and previously settled interest rate swaps at Sep. 30, 2010 is a net loss of $5.5 million after tax and accumulated amortization. This compares to a net loss of $7.3 million in AOCI after tax and accumulated amortization at Dec. 31, 2009.

The following table presents the derivative hedges of interest rate swaps at Sep. 30, 2010 and Dec. 31, 2009 to limit the exposure to market changes in interest rates on outstanding debt:

Interest Rate Swaps
(millions)	Sep. 30, 2010		Dec. 31, 2009 (1)
Current assets	$	0.0	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.0	$	0.0
Current liabilities	$	0.3	$	0.0
Long-term liabilities		0.0		0.0
Total liabilities	$	0.3	$	0.0

(1) Interest rate swaps residing on the balance sheet of TECO Guatemala, Inc. were deconsolidated at Dec. 31, 2009. SeeNote 16.

23

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at Sep. 30, 2010:

Derivatives Designated As Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2010	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Heating oil derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.2	Derivative liabilities		0.0
Natural gas derivatives:
Current	Derivative assets		0.7	Derivative liabilities		45.5
Long-term	Derivative assets		0.0	Derivative liabilities		5.8
Interest rate swaps:
Current	Derivative assets		0.0	Derivative liabilities		0.3
Long-term	Derivative assets		0.0	Derivative liabilities		0.0
Total derivatives designated as hedging instruments		$	1.0		$	51.6

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sep. 30, 2010:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2010	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.7	Regulatory assets	$	45.5
Long-term	Regulatory liabilities		0.0	Regulatory assets		5.8
Total		$	0.7		$	51.3

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

Based on the fair value of the instruments at Sep. 30, 2010, net pretax losses of $44.8 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

24

The following tables present the effect of hedging instruments on OCI and income for the three months and nine months ended Sep. 30, 2010:

For the three months ended Sep. 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging                    Relationships	Effective Portion(1)				Effective Portion(1)
2010
Interest rate contracts:	$	0.0		Interest expense	($	0.4	)
Commodity contracts:
Heating oil derivatives		0.7		Mining related costs		(0.3	)
Total	$	0.7			($	0.7	)
2009
Interest rate contracts:	($	0.1	)	Interest expense	($	0.5	)
Commodity contracts:
Heating oil derivatives		(0.7	)	Mining related costs		(2.9	)
Natural gas derivatives		(0.1	)	Mining related costs		(0.3	)
Total	($	0.9	)		($	3.7	)

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

For the nine months ended Sep. 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging                    Relationships	Effective Portion(1)				Effective Portion(1)
2010
Interest rate contracts:	($	0.1	)	Interest expense	($	1.2	)
Commodity contracts:
Heating oil derivatives		(0.2	)	Mining related costs		(0.9	)
Total	($	0.3	)		($	2.1	)
2009
Interest rate contracts:	($	0.1	)	Interest expense	($	1.6	)
Commodity contracts:
Heating oil derivatives		1.8		Mining related costs		(9.9	)
Natural gas derivatives		(0.6	)	Mining related costs		(0.7	)
Total	$	1.1			($	12.2	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months and nine months ended Sep. 30, 2010 and 2009, all hedges were effective.

25

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sep. 30, 2010 and 2009:

For the nine months ended Sep. 30: (millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI(1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2010
Interest rate swaps	($	0.3	)	($	0.1	)	($	1.2	)
Heating oil derivatives		0.3			(0.2	)		(0.9	)
Total	$	0.0		($	0.3	)	($	2.1	)
2009
Interest rate swaps	$	0.0		($	0.1	)	($	1.6	)
Heating oil derivatives		(7.1	)		1.8			(9.9	)
Natural gas derivatives		(0.1	)		(0.6	)		(0.7	)
Total	($	7.2	)	$	1.1		($	12.2	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2012 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 Sep. 30, 2010, are expected to settle during the 2010, 2011 and 2012 fiscal years:

	Heating Oil Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2010		0.0		2.3		0.0		9.5
2011		0.0		4.8		0.0		20.6
2012		0.0		0.5		0.0		4.5
Total		0.0		7.6		0.0		34.6

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

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Sep. 30, 2010, substantially 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 our counterparties and to consider nonperformance in valuing counterparty positions. The company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of Sep. 30, 2010, substantially all positions with counterparties are net liabilities.

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

26

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at Sep. 30, 2010:

Contingent Features
(millions) At Sep. 30, 2010	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	50.6	)	($	50.6	)	$	0.0

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2010 and Dec. 31, 2009. 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, interest rate and heating oil swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Sep. 30, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.7	$	0.0	$	0.7
Heating oil swaps		0.0		0.3		0.0		0.3
Total	$	0.0	$	1.0	$	0.0	$	1.0
Liabilities
Natural gas swaps	$	0.0	$	51.3	$	0.0	$	51.3
Interest rate swaps		0.0		0.3		0.0		0.3
Total	$	0.0	$	51.6	$	0.0	$	51.6
	At fair value as of Dec. 31, 2009
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.8	$	0.0	$	0.8
Heating oil swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	1.0	$	0.0	$	1.0
Liabilities
Natural gas swaps	$	0.0	$	36.7	$	0.0	$	36.7
Heating oil swaps		0.0		0.9		0.0		0.9
Total	$	0.0	$	37.6	$	0.0	$	37.6

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

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

27

Fair Value of Debt Outstanding

At Sep. 30, 2010, total long-term debt had a carrying amount of $3,390.0 million and an estimated fair market value of $3,756.9 million. At Dec. 31, 2009, total long-term debt had a carrying amount of$3,309.7 million and an estimated fair market value of $3,500.3 million.

14. Asset Dispositions

Sale of DECA II

On Oct. 21, 2010, a TECO Energy subsidiary, TPS de Ultramar, Ltd. (TPSU), sold its interest in Distribución Eléctrica Centro Americana II, S.A. (DECA II) to Empresas Públicas de Medellín E.S.P. (EPM), a multi-utility company based in Medellín Colombia, under a Stock Purchase Agreement (SPA) for a sales price of $181.5 million. SeeNote 17 for further information.

Sale of Navega

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

15. Restructuring Charges

On Jul. 30, 2009, TECO Energy, Inc. announced organizational changes and a new senior management structure as part of its response to industry changes, economic uncertainties and its commitment to maintain a lean and efficient organization. As a second step in response to these factors, on Aug. 31, 2009, the company decided on a total reduction in force of 229 jobs. The reduction in force was substantially completed by Dec. 31, 2009. In connection with this reduction in force, the company incurred total costs of $26.6 million related to severance and other benefits. For the three months ended Mar. 31, 2010, the remaining $1.5 million of these costs were recognized on the Consolidated Condensed Statements of Income under “Restructuring Charges”. The company’s wholly-owned subsidiary, Tampa Electric Company, incurred $23.1 million of such costs, all of which were recognized in the year ended Dec. 31, 2009. The total cash payments related to these actions were $28.4 million; including $4.9 million for the settlement of pension obligations. As of Mar. 31, 2010, all restructuring charges were paid or settled.

Restructuring Charges Incurred
(millions)	Termination of  Benefits			Other Costs			Total
Total costs expected to be incurred	$	26.6		$	0.6		$	27.2
Costs incurred in 2009		(25.1	)		(0.6	)		(25.7	)
Costs incurred in 2010		(1.5	)		0.0			(1.5	)
Total costs remaining	$	0.0		$	0.0		$	0.0
Accrued Liability for Restructuring Charges
(millions)	Termination of Benefits			Other Costs			Total
Beginning balance, Jul. 1, 2009	$	0.0		$	0.0		$	0.0
Costs incurred and charged to expense		26.6			0.6			27.2
Costs paid/settled		(22.9	)		(0.6	)		(23.5	)
Non-cash expense		(3.7	)		0.0			(3.7	)
Ending balance, Sep. 30, 2010	$	0.0		$	0.0		$	0.0

Restructuring Charges by Segment
(millions)	Tampa Electric			PGS			Other(1)			Total
Total costs expected to be incurred	$	18.4		$	4.7		$	4.1		$	27.2
Costs incurred in 2009		(18.4	)		(4.7	)		(2.6	)		(25.7	)
Costs incurred in 2010		0.0			0.0			(1.5	)		(1.5	)
Total costs remaining	$	0.0		$	0.0		$	0.0		$	0.0

(1) Restructuring costs incurred at the parent company.

28

16. Variable Interest Entities

The company formed TCAE to own and construct the Alborada Power Station and the company formed CGESJ to own and construct the San José Power Station. Both power stations are located in Guatemala and both projects obtained long-term power purchase agreements (PPAs) with Empresa Eléctrica de Guatemala, S.A. (EEGSA), a distribution utility in Guatemala. The terms of the two separate PPAs include EEGSA’s right to the full capacity of the plants for 15 years, U.S. dollar based capacity payments, certain terms for providing fuel, and certain other terms including the right to extend the Alborada and San José contracts. Under prior accounting standards for consolidation, management believed that EEGSA was the primary beneficiary of the variable interests in TCAE and CGESJ due to the terms of the PPAs. Accordingly, both entities were deconsolidated as of Jan. 1, 2004. The TCAE deconsolidation resulted in the initial removal of $25.0 million of debt and $15.1 million of net assets from TECO Energy’s Consolidated Balance Sheet. The CGESJ deconsolidation resulted in the initial removal of $65.5 million of debt and $106.6 million of net assets from TECO Energy’s Consolidated Balance Sheet. The results of operations for the two projects were classified as “Income from equity investments” on TECO Energy’s Consolidated Statements of Income since the date of deconsolidation through Dec. 31, 2009.

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. As a result of adopting this amendment, the company reconsolidated both TCAE and CGESJ.

The following table summarizes combined income statement information for the TCAE and CGESJ projects for the three months and nine months ended Sep. 30, 2010, which were consolidated, and Sep. 30, 2009, which were not consolidated:

Summary Results for TCAE and CGESJ
	For the three months ended Sep. 30,				For the nine months ended Sep. 30,
(millions)	2010		2009		2010		2009
Revenues	$	28.5	$	30.8	$	94.1	$	62.1
Operating expenses		16.4		20.5		52.1		35.2
Project level income(1)		15.8		8.0		40.1		20.0

(1) Excludes taxes, allocated interest expense and administrative and general expenses. Includes project level interest.

The following table summarizes combined balance sheet information for the TCAE and CGESJ projects for the periods ended Sep. 30, 2010, which is now consolidated, and Dec. 31, 2009, which were not consolidated:

Summary Results for TCAE and CGESJ
(millions)	Sep. 30, 2010		Dec. 31, 2009
Current assets	$	64.8	$	58.1
Long-term assets and other deferred debits		155.5		161.2
Total assets	$	220.3	$	219.3
Current liabilities	$	22.6	$	17.6
Long-term liabilities and other deferred credits		40.6		51.2
Equity		157.1		150.5
Total liabilities and equity	$	220.3	$	219.3

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 variable interest entities. 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 $45.0 million and $46.3 million, and $151.5 million and $144.6 million, under these PPAs for the three months and nine months ended Sep. 30, 2010 and 2009, respectively.

29

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 the 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. The company purchased $14.7 million and $6.9 million, and $45.0 million and $24.3 million under this PPA for the three months and nine months ended Sep. 30, 2010 and 2009, respectively.

The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. Other than the Guatemalan projects previously mentioned, in the normal course of business, our involvement with the remaining VIEs does not affect our Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

17. Subsequent Events

CAFTA Arbitration Claim

On Jan. 13, 2009, a TECO Energy subsidiary, TECO Guatemala Holdings, LLC, (TGH), delivered a Notice of Intent to the Guatemalan government that it intended to file an arbitration claim against the Republic of Guatemala under the Dominican Republic Central America – United States Free Trade Agreement (DR – CAFTA) alleging a violation of fair and equitable treatment of its investment in EEGSA. On Oct. 20, 2010, TGH filed a Notice of Arbitration with the International Centre for Settlement of Investment Disputes to proceed with its arbitration claim.

The arbitration was prompted by actions of the Guatemalan government in July 2008 which, among other things, unilaterally reset the distribution tariff for EEGSA at levels well below the then existing tariffs. These actions caused a significant reduction in earnings from EEGSA. Until Oct. 21, 2010, TGH held a 24% ownership interest in EEGSA through a holding company (DECA II) with Iberdrola Energia, S.A. and Electricidade de Portugal, S.A. On such date, TGH’s interest was sold (see below). In connection with the sale of TGH’s ownership interest in EEGSA, TGH reserved the right to pursue the arbitration claim described above.

Sale of DECA II

On Oct. 21, 2010, a TECO Energy subsidiary, TPSU, sold its 30% interest in DECA II to EPM, a multi-utility company based in Medellín Colombia, under an SPA, for a sale price of $181.5 million. TPSU is a subsidiary of TECO Guatemala Holdings, LLC (TGH).

DECA II is a holding company in which, prior to the sale, TGH held a 30% interest, Iberdrola Energia, S.A. held a 49% interest and EDP – Energias de Portugal, S.A. held a 21% interest. Each of these parties sold its interest in DECA II pursuant to the SPA. DECA II holds an 80.9% ownership interest in EEGSA and affiliated companies. EEGSA is the largest Guatemalan distribution utility, which serves Guatemala City, the capital of Guatemala and the surrounding region.

TGH received $181.5 million of the $605.0 million total purchase price for its 30% interest. In addition, TGH will repatriate approximately $25.0 million of cash previously held offshore in a tax deferral structure. The sale will result in a fourth quarter pretax book gain of approximately $38.0 million at TECO Guatemala. During the third quarter, TECO Guatemala recorded a $24.9 million income tax charge related to the unwinding of the tax deferral structure as the earnings from DECA II are no longer considered indefinitely reinvested. During the fourth quarter, the company anticipates recording approximately $15.0 million of Guatemalan and U.S. tax expenses as a result of the transaction.

Redemption of 7.0% notes due May 1, 2012

On Nov. 3, 2010, TECO Energy and TECO Finance submitted optional redemption notices to holders of $73.2 million and $163.1 million, respectively, of 7.0% notes due May 1, 2012. The optional redemption price of the 7.0% notes is equal to the greater of (i) 100% of the principal amount of 7.0% notes redeemed or (ii) the present value of the remaining payments of principal and interest on the 7.0% notes redeemed, discounted at an applicable treasury rate (as defined in the 7.0% notes indenture) plus 25 basis points; in either case, the optional redemption price will include accrued and unpaid interest to the redemption date. Settlement of the optional redemption is expected to be Dec. 2, 2010.

30

TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company as of Sep. 30, 2010 and Dec. 31, 2009, and the results of operations and cash flows for the periods ended Sep. 30, 2010 and 2009. The results of operations for the three months and nine months ended Sep. 30, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010. 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, 2009 and to the notes on pages 37 through 48 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2010 and Dec. 31, 2009		32-33
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and nine month periods ended Sep. 30, 2010 and 2009		34-35
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2010 and 2009		36
Notes to Consolidated Condensed Financial Statements		37-48

31

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Sep. 30, 2010			Dec. 31, 2009
Property, plant and equipment
Utility plant in service
Electric	$	6,306.2		$	6,065.9
Gas		1,041.0			1,017.2
Construction work in progress		189.1			303.0
Property, plant and equipment, at original costs		7,536.3			7,386.1
Accumulated depreciation		(2,068.6	)		(1,988.1	)
		5,467.7			5,398.0
Other property		4.7			4.4
Total property, plant and equipment, net		5,472.4			5,402.4
Current assets
Cash and cash equivalents		16.2			5.5
Receivables, less allowance for uncollectibles of $2.1 and $1.6 at Sep. 30, 2010 and Dec. 31, 2009, respectively		298.5			228.6
Inventories, at average cost
Fuel		114.1			85.8
Materials and supplies		59.3			55.8
Current regulatory assets		67.6			109.2
Current derivative assets		0.7			0.8
Taxes receivable		0.0			16.8
Prepayments and other current assets		13.8			12.0
Total current assets		570.2			514.5
Deferred debits
Unamortized debt expense		17.8			20.1
Long-term regulatory assets		327.4			335.6
Other		24.0			1.2
Total deferred debits		369.2			356.9
Total assets	$	6,411.8		$	6,273.8

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

32

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets – continued

Unaudited

Liabilities and Capital	Sep. 30,			Dec. 31,
(millions)	2010			2009
Capital
Common stock	$	1,852.4		$	1,802.4
Accumulated other comprehensive loss		(5.5	)		(6.1	)
Retained earnings		326.0			307.5
Total capital		2,172.9			2,103.8
Long-term debt, less amount due within one year		1,991.0			1,994.4
Total capitalization		4,163.9			4,098.2
Current liabilities
Long-term debt due within one year		3.4			3.7
Notes payable		27.0			55.0
Accounts payable		188.5			206.1
Customer deposits		154.9			151.2
Current regulatory liabilities		108.7			85.4
Current derivative liabilities		45.5			33.1
Current deferred income taxes		0.2			15.9
Interest accrued		44.5			27.7
Taxes accrued		61.2			12.1
Other		12.0			16.5
Total current liabilities		645.9			606.7
Deferred credits
Non-current deferred income taxes		589.5			543.8
Investment tax credits		10.5			10.8
Long-term derivative liabilities		5.8			3.6
Long-term regulatory liabilities		614.5			602.6
Other		381.7			408.1
Total deferred credits		1,602.0			1,568.9
Total liabilities and capital	$	6,411.8		$	6,273.8

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

33

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Sep. 30,
(millions)	2010			2009
Revenues
Electric (includes franchise fees and gross receipts taxes of $26.4 in 2010 and $25.7 in 2009)	$	593.5		$	620.8
Gas (includes franchise fees and gross receipts taxes of $4.6 in 2010 and $4.8 in 2009)		114.1			98.6
Total revenues		707.6			719.4
Expenses
Operations
Fuel		224.5			253.5
Purchased power		45.2			46.3
Cost of natural gas sold		61.0			47.5
Other		96.0			87.0
Maintenance		28.7			32.1
Depreciation		65.9			61.9
Restructuring charges		0.0			22.6
Taxes, federal and state		38.9			33.9
Taxes, other than income		47.4			45.6
Total expenses		607.6			630.4
Income from operations		100.0			89.0
Other income
Allowance for other funds used during construction		0.3			2.5
Taxes, non-utility federal and state		(0.3	)		(0.2	)
Other income, net		0.9			0.8
Total other income		0.9			3.1
Interest charges
Interest on long-term debt		32.6			32.6
Other interest		2.8			2.7
Allowance for borrowed funds used during construction		(0.1	)		(0.9	)
Total interest charges		35.3			34.4
Net income	$	65.6		$	57.7
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	$	65.8		$	57.9

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

34

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Nine months ended Sep. 30,
(millions)	2010			2009
Revenues
Electric (includes franchise fees and gross receipts taxes of $69.6 in 2010 and $70.5 in 2009)	$	1,671.6		$	1,691.8
Gas (includes franchise fees and gross receipts taxes of $20.4 in 2010 and $18.3 in 2009)		408.2			344.8
Total revenues		2,079.8			2,036.6
Expenses
Operations
Fuel		573.9			707.7
Purchased power		151.5			144.6
Cost of natural gas sold		236.4			186.7
Other		280.2			244.8
Maintenance		90.3			100.1
Depreciation		195.3			181.0
Restructuring charges		0.0			22.6
Taxes, federal and state		114.7			80.8
Taxes, other than income		141.9			138.0
Total expenses		1,784.2			1,806.3
Income from operations		295.6			230.3
Other income
Allowance for other funds used during construction		1.6			8.3
Taxes, non-utility federal and state		(0.6	)		(0.6	)
Other income, net		2.5			3.0
Total other income		3.5			10.7
Interest charges
Interest on long-term debt		98.1			95.4
Other interest		8.4			8.5
Allowance for borrowed funds used during construction		(0.9	)		(3.2	)
Total interest charges		105.6			100.7
Net income	$	193.5		$	140.3
Other comprehensive income, net of tax
Net unrealized gain on cash flow hedges		0.6			0.5
Total other comprehensive income, net of tax		0.6			0.5
Comprehensive income	$	194.1		$	140.8

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

35

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sep. 30,
(millions)	2010			2009
Cash flows from operating activities
Net income	$	193.5		$	140.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation		195.3			181.0
Deferred income taxes		27.7			32.6
Investment tax credits, net		(0.3	)		(0.3	)
Allowance for funds used during construction		(1.6	)		(8.3	)
Deferred recovery clause		44.6			111.4
Receivables, less allowance for uncollectibles		(69.9	)		(46.6	)
Inventories		(31.8	)		(20.7	)
Prepayments		(1.8	)		(1.0	)
Taxes accrued		65.9			34.5
Interest accrued		16.8			17.2
Accounts payable		17.7			(31.9	)
Gain on sale of assets, pretax		(0.2	)		(0.4	)
Other		5.0			39.4
Cash flows from operating activities		460.9			447.2
Cash flows from investing activities
Capital expenditures		(295.2	)		(461.0	)
Allowance for funds used during construction		1.6			8.3
Net proceeds from sale of assets		0.0			0.4
Cash flows used in investing activities		(293.6	)		(452.3	)
Cash flows from financing activities
Proceeds from long-term debt		0.0			102.1
Common stock		50.0			0.0
Repayment of long-term debt		(3.7	)		(5.5	)
Net (decrease) increase in short-term debt		(28.0	)		25.0
Dividends		(174.9	)		(113.4	)
Cash flows (used in) from financing activities		(156.6	)		8.2
Net increase in cash and cash equivalents		10.7			3.1
Cash and cash equivalents at beginning of period		5.5			3.6
Cash and cash equivalents at end of period	$	16.2		$	6.7

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

36

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., and is comprised of the Electric division, generally referred to as Tampa Electric, the Natural Gas division, generally referred to as Peoples Gas System (PGS) and the accounts of variable interest entities (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. (SeeNote 12.)

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company and subsidiaries as of Sep. 30, 2010 and Dec. 31, 2009, and the results of operations and cash flows for the periods ended Sep. 30, 2010 and 2009. The results of operations for the three and nine month periods ended Sep. 30, 2010 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2010.

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 consolidated condensed balance sheet data was derived from audited financial statements, however this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by GAAP in the United States of America.

Revenues

As of Sep. 30, 2010 and Dec. 31, 2009, unbilled revenues of $60.3 million and $51.6 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 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 $31.0 million and $90.0 million, respectively, for the three and nine months ended Sep. 30, 2010, compared to $30.5 million and $88.8 million, respectively, for the three and nine months ended Sep. 30, 2009. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These totaled $31.1 million and $89.9 million, respectively, for the three and nine months ended Sep. 30, 2010, compared to $30.5 million and $88.7 million, respectively, for the three and nine months ended Sep. 30, 2009.

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 $45.2 million and $151.5 million, respectively, for the three and nine months ended Sep. 30, 2010, compared to $46.3 million and $144.6 million, respectively, for the three and nine months ended Sep. 30, 2009. 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.

37

2. New Accounting Pronouncements

Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses

In July 2010, the Financial Accounting Standards Board (FASB) issued guidance requiring improved disclosures about the credit quality of a company’s financing receivables and their associated credit reserves. The guidance was effective for interim and annual periods that end after Dec. 15, 2010. This guidance will not have any effect on the company’s results of operations, statement of position or cash flows.

Subsequent Events

In February 2010, the FASB issued additional guidance related to subsequent event disclosure. The guidance was effective upon issuance and has no effect on the company’s results of operations, statement of position or cash flows.

Fair Value Measures and Disclosures

In January 2010, the FASB issued guidance that requires entities to disclose more information regarding the movements between Levels 1 and 2 of the fair value hierarchy. The guidance was effective for fiscal years that begin after Dec. 15, 2010, and for interim periods within that year. This guidance will not have any effect on the company’s results of operations, statement of 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, Tampa Electric is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the regulation 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.

Stipulation with Intervenors – Tampa Electric

As previously reported in the company’s Annual Report on Form 10-K for the period ended Dec. 31, 2009, the FPSC, in connection with Tampa Electric’s 2008 base rate request, approved a $25.7 million increase in base rates effective Jan. 1, 2010 (step increase), subject to refund, for certain capital additions placed in service in 2009.

In connection with the base rate request, the FPSC had rejected the intervenors’ arguments that the approved 2010 increase violated the intervenors’ due process rights, Florida Statutes or FPSC rules. The intervenors filed an appeal with the Florida Supreme Court in September 2009, which Tampa Electric opposed.

In July 2010, Tampa Electric entered into a stipulation with the intervenors to resolve all issues related to the 2008 base rate case including the 2010 step increase, as well as the intervenors’ appeal to the Florida Supreme Court. Under the terms of the stipulation, the $25.7 million step increase would remain in effect for 2010, and Tampa Electric would make a one-time reduction of $24.0 million to customers’ bills in 2010.

In August 2010, the FPSC voted to approve the July stipulation, which was contained in their Docket No. 090368-EI “Review of the continuing need and cost associated with Tampa Electric Company’s 5 Combustion Turbines and Big Bend Rail Facility”. This stipulation now resolves all issues in the above docket and all issues in the intervenors’ appeal of the FPSC’s 2009 decision in Tampa Electric’s base rate proceeding pending before the Florida Supreme Court. The docket related to the base rate proceeding is now closed. The one-time reduction of $24.0 million to customers’ bills in 2010 is reflected in the third quarter operating results as a reduction in revenue.

Effective Jan. 1, 2011, and for subsequent years, rates of $24.4 million (a $1.3 million reduction from the $25.7 million in effect for 2010) related to the step increase will be in effect.

Wholesale and Transmission Rate Cases

In July 2010, Tampa Electric filed wholesale requirements and transmission rate cases with the FERC. Tampa Electric’s last wholesale requirements rate case was in 1991 and the associated service agreements were approved by the FERC in the mid-1990s. The FERC approved Tampa Electric’s proposed transmission rates as filed with the FERC, which became effective Sep. 14, 2010, subject to refund. The FERC also approved Tampa Electric’s proposed wholesale requirements rates, as filed with the FERC, to become effective Mar. 1, 2011, subject to refund. The proposed wholesale requirements and transmission rates are not expected to have a material impact on Tampa Electric’s results.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually effective May 2009 to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $35.4 million and $29.3 million as of Sep. 30, 2010 and Dec. 31, 2009, respectively.

38

Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; and the deferral of costs as regulatory assets to the period that the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year.

Details of the regulatory assets and liabilities as of Sep. 30, 2010 and Dec. 31, 2009 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sep. 30, 2010		Dec. 31, 2009
Regulatory assets:
Regulatory tax asset(1)	$	67.8	$	69.0
Other:
Cost recovery clauses		51.1		89.4
Postretirement benefit asset		219.6		229.1
Deferred bond refinancing costs(2)		15.2		18.0
Environmental remediation		21.9		21.2
Competitive rate adjustment		3.2		3.1
Other		16.2		15.0
Total other regulatory assets		327.2		375.8
Total regulatory assets		395.0		444.8
Less: Current portion		67.6		109.2
Long-term regulatory assets	$	327.4	$	335.6
Regulatory liabilities:
Regulatory tax liability(1)	$	16.4	$	19.6
Other:
Cost recovery clauses		52.1		61.4
Environmental remediation		19.9		19.9
Transmission and delivery storm reserve		35.4		29.3
Deferred gain on property sales(3)		1.5		2.8
Provision for stipulation and other(4)		34.0		0.7
Accumulated reserve-cost of removal		563.9		554.3
Total other regulatory liabilities		706.8		668.4
Total regulatory liabilities		723.2		688.0
Less: Current portion		108.7		85.4
Long-term regulatory liabilities	$	614.5	$	602.6

(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 one-time credit to be applied to Tampa Electric customers’ bills in the fourth quarter of 2010 related to the stipulation and a provision for PGS’ estimated earnings above its allowed return on equity range of 9.75% to 11.75%. The disposition of any earnings above the top of PGS’ allowed range would be determined by the FPSC.

39

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

Regulatory assets
(millions)	Sep. 30, 2010		Dec 31, 2009
Clause recoverable(1)	$	54.3	$	92.5
Components of rate base(2)		229.8		238.1
Regulatory tax assets(3)		67.8		69.0
Capital structure and other(3)		43.1		45.2
Total	$	395.0	$	444.8

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

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

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

4. 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 rate for the nine months ended Sep. 30, 2010 and Sep. 30, 2009 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the equity portion of Allowance for Funds Used During Construction.

The Internal Revenue Service (IRS) concluded its examination of the company’s consolidated federal income tax return for the year 2008 during 2009. During the third quarter, TECO Energy agreed to a proposed settlement related to the only outstanding issue for the 2008 tax return. The settlement is expected to be finalized in the fourth quarter, without a material impact on earnings or operating cash flows. The U.S. federal statute of limitations remains open for the year 2007 and onward. Years 2009 and 2010 are currently under examination by the IRS under the Compliance Assurance Program, a program in which TECO Energy is a participant. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2010. 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. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

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 inNote 5,Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. Tampa Electric Company’s portion of the net pension expense for the three months ended Sep. 30, 2010 and 2009, respectively, was $4.7 million and $4.6 million for pension benefits, and $3.4 million for other postretirement benefits. For the nine months ended Sep. 30, 2010 and 2009, respectively, net benefit expenses were $14.0 million and $12.2 million for pension benefits and $10.3 million and $10.2 million for other postretirement benefits.

For the fiscal 2010 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.25% and a discount rate of 5.75% for pension benefits under its qualified pension plan, and a discount rate of 5.60% for its other postretirement benefits as of their Jan. 1, 2010 measurement dates. Additionally, TECO Energy assumed a discount rate of 5.75% for its Supplemental Executive Retirement Plan (SERP) benefits as of its Mar. 1 and Jan. 1, 2010 measurement dates.

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

In September 2010, TECO Energy made a contribution to its qualified pension plan of approximately $34.5 million. Tampa Electric Company’s portion of this contribution was $29.1 million.

40

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, The Health Care and Education Reconciliation Act (the Acts) were signed into law. Among other things, the 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, Tampa Electric Company reduced its deferred tax asset by $5.3 million and recorded a corresponding regulatory tax asset. Tampa Electric Company is reviewing certain other aspects of the Acts that could impact the cost of medical benefits provided to retirees and active employees. These impacts are not expected to be material to the company’s future results of operations, statement of position or cash flows.

6. Short-Term Debt

At Sep. 30, 2010 and Dec. 31, 2009, the following credit facilities and related borrowings existed:

Credit Facilities
	Sep. 30, 2010						Dec. 31, 2009
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility	$	325.0	$	0.0	$	0.9	$	325.0	$	55.0	$	0.7
1-year accounts receivable facility		150.0		27.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	27.0	$	0.9	$	475.0	$	55.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

These credit facilities require commitment fees ranging from 7.0 to 60.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at both Sep. 30, 2010 and Dec. 31, 2009 was 0.85% and 0.64%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 19, 2010, Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric Company, amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 8 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. 18, 2011, (ii) provides that TRC will pay program and liquidity fees, which, pursuant to the amendment, will total 100 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.

41

7. Other Comprehensive Income

Other Comprehensive Income	Three months ended Sep. 30,							Nine months ended Sep. 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2010
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.3	)		0.6
Total other comprehensive income	$	0.3	($	0.1	)	$	0.2	$	0.9	($	0.3	)	$	0.6
2009
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Add: Loss reclassified to net income		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Gain on cash flow hedges		0.3		(0.1	)		0.2		0.9		(0.4	)		0.5
Total other comprehensive income	$	0.3	($	0.1	)	$	0.2	$	0.9	($	0.4	)	$	0.5

Accumulated Other Comprehensive Loss
(millions)	Sep. 30, 2010			Dec. 31, 2009
Net unrealized losses from cash flow hedges(1)	($	5.5	)	($	6.1	)
Total accumulated other comprehensive loss	($	5.5	)	($	6.1	)

(1) Net of tax benefit of $3.5 million and $3.8 million as of Sep. 30, 2010 and Dec. 31, 2009, respectively.

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, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through Tampa Electric and PGS, is a potentially responsible party (PRP) for certain superfund sites and, through PGS, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2010, Tampa Electric Company has estimated its ultimate financial liability to be $19.9 million, primarily at PGS, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves 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 federal Superfund law 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, is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company is in the process of responding to such matter, and the scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

Letters of Credit

At Sep. 30, 2010, Tampa Electric Company had $0.9 million of letters of credit outstanding.

42

Letters of Credit -Tampa Electric Company
(millions)
Letters of Credit for the Benefit of:	2010		2011-2014		After 2014		Total		Liabilities Recognized at Sep. 30, 2010
Tampa Electric
Letters of credit	$	0.0	$	0.0	$	0.9	$	0.9	$	0.0
Total	$	0.0	$	0.0	$	0.9	$	0.9	$	0.0

Financial Covenants

In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2010, Tampa Electric Company was in compliance with applicable financial covenants.

9. Segment Information

Tampa Electric Company segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of Tampa Electric Company 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 Tampa Electric Company, but are included in determining reportable segments.

43

(millions)	Tampa(1)		Peoples		Other &			Tampa Electric
Three months ended Sep. 30,	Electric		Gas		Eliminations			Company
2010
Revenues - external	$	593.3	$	114.1	$	0.0		$	707.4
Sales to affiliates		0.3		2.5		(2.6	)		0.2
Total revenues		593.6		116.6		(2.6	)		707.6
Depreciation		54.4		11.5		0.0			65.9
Total interest charges		30.7		4.6		0.0			35.3
Provision for taxes		36.8		2.4		0.0			39.2
Net income		61.9		3.7		0.0			65.6
2009
Revenues - external	$	620.6	$	98.7	$	0.0		$	719.3
Sales to affiliates		0.3		2.3		(2.5	)		0.1
Total revenues		620.9		101.0		(2.5	)		719.4
Depreciation		50.8		11.1		0.0			61.9
Restructuring charges		18.1		4.5		0.0			22.6
Total interest charges		29.8		4.6		0.0			34.4
Provision for taxes		31.9		2.2		0.0			34.1
Net income		54.3		3.4		0.0			57.7
Nine months ended Sep. 30,
2010
Revenues - external	$	1,670.9	$	408.2	$	0.0		$	2,079.1
Sales to affiliates		1.0		17.4		(17.7	)		0.7
Total revenues		1,671.9		425.6		(17.7	)		2,079.8
Depreciation		161.0		34.3		0.0			195.3
Total interest charges		91.8		13.8		0.0			105.6
Provision for taxes		98.4		16.9		0.0			115.3
Net income		166.8		26.7		0.0			193.5
Total assets at Sep. 30, 2010	$	5,582.3	$	835.9	($	6.4	)	$	6,411.8
2009
Revenues - external	$	1,691.1	$	344.9	$	0.0		$	2,036.0
Sales to affiliates		1.0		12.2		(12.6	)		0.6
Total revenues		1,692.1		357.1		(12.6	)		2,036.6
Depreciation		148.1		32.9		0.0			181.0
Restructuring charges		18.1		4.5		0.0			22.6
Total interest charges		86.6		14.1		0.0			100.7
Provision for taxes		69.1		12.3		0.0			81.4
Net income		121.1		19.2		0.0			140.3
Total assets at Dec. 31, 2009	$	5,457.5	$	826.0	($	9.7	)	$	6,273.8

(1) Revenues for the three months and nine months ended Sep. 30, 2010 reflect the reduction resulting from the FPSC stipulation of $24.0 million. SeeNote 3 for more information.

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.

44

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 other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

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. (seeNote 3.)

A company’s physical contracts qualify for the normal purchase/normal sale (NPNS) exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Sep. 30, 2010, all of Tampa Electric Company’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at Sep. 30, 2010 and Dec. 31, 2009 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(1)
	Sep. 30,		Dec. 31,
(millions)	2010		2009
Current assets	$	0.7	$	0.8
Long-term assets		0.0		0.0
Total assets	$	0.7	$	0.8
Current liabilities(1)	$	45.5	$	33.1
Long-term liabilities		5.8		3.6
Total liabilities	$	51.3	$	36.7

(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 accumulated other comprehensive income (AOCI) related to previously settled interest rate swaps at Sep. 30, 2010 is a net loss of $5.5 million after tax and accumulated amortization. This compares to a net loss of $6.1 million in AOCI after tax and accumulated amortization at Dec. 31, 2009.

45

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sep. 30, 2010:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) at Sep. 30, 2010	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.7	Regulatory assets	$	45.5
Long-term	Regulatory liabilities		0.0	Regulatory assets		5.8
Total		$	0.7		$	51.3

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

Based on the fair value of the instruments at Sep. 30, 2010, net pretax losses of $44.8 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next twelve months.

The following table presents the effect of hedging instruments on OCI and income for the three and nine months ended Sep. 30, 2010 and 2009:

(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 Sep. 30:			Nine months ended Sep. 30:
2010
Interest rate contracts:	Interest expense	($	0.2	)	($	0.6	)
Total		($	0.2	)	($	0.6	)
2009
Interest rate contracts:	Interest expense	($	0.2	)	($	0.5	)
Total		($	0.2	)	($	0.5	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months and nine months ended Sep. 30, 2010 and 2009, all hedges were effective.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2012 for the financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Sep. 30, 2010, are expected to settle during the 2010, 2011 and 2012 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2010		0.0		9.5
2011		0.0		20.6
2012		0.0		4.5
Total		0.0		34.6

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

46

It is possible that volatility in commodity prices could cause Tampa Electric Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, Tampa Electric Company could suffer a material financial loss. However, as of Sep. 30, 2010, 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. The company generally enters into the following master arrangements: (1) Edison Electric Institute agreements (EEI) - standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements (ISDA) - standardized financial gas and electric contracts; and (3) North American Energy Standards Board agreements (NAESB) - standardized physical gas contracts. Tampa Electric Company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

Tampa Electric Company has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. Tampa Electric Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are generally not adjusted as Tampa Electric Company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, Tampa Electric Company considers general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of Sep. 30, 2010, substantially all positions with counterparties are net liabilities.

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

The table below presents the fair value of the overall contractual contingent liability positions for Tampa Electric Company’s derivative activity at Sep. 30, 2010:

(millions) At Sep. 30, 2010	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	50.6	)	($	50.6	)	$	0.0

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth, by level within the fair value hierarchy, Tampa Electric Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Sep. 30, 2010 and Dec. 31, 2009. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Tampa Electric Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Sep. 30, 2010
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.7	$	0.0	$	0.7
Total	$	0.0	$	0.7	$	0.0	$	0.7
Liabilities
Natural gas swaps	$	0.0	$	51.3	$	0.0	$	51.3
Total	$	0.0	$	51.3	$	0.0	$	51.3

47

	At fair value as of Dec. 31, 2009
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.8	$	0.0	$	0.8
Total	$	0.0	$	0.8	$	0.0	$	0.8
Liabilities
Natural gas swaps	$	0.0	$	36.7	$	0.0	$	36.7
Total	$	0.0	$	36.7	$	0.0	$	36.7

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

Tampa Electric Company considered the impact of nonperformance risk in determining the fair value of derivatives. Tampa Electric Company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2010, the fair value of derivatives was not materially affected by nonperformance risk. Tampa Electric Company’s net positions with substantially all counterparties were liability positions.

Fair Value of Long-Term Debt

At Sep. 30, 2010, Tampa Electric Company’s total long-term debt had a carrying amount of $1,994.4 million and an estimated fair market value of $2,229.3 million. At Dec. 31, 2009, total long-term debt had a carrying amount of $1,999.4 million and an estimated fair market value of $2,115.4 million.

12. Variable Interest Entities

Tampa Electric Company accounts for VIEs under accounting standards for consolidations. In accordance with these standards, Tampa Electric Company evaluates for consolidation all long-term agreements with VIEs in which contractual, ownership or other pecuniary interests in that entity change with changes in the fair value of the entity’s net assets. A party to an agreement 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, is considered to be the primary beneficiary and is required to consolidate that entity.

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 variable interest entities. 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 $45.0 million and $46.3 million, and $151.5 million and $144.6 million, under these PPAs for the three months and nine months ended Sep. 30, 2010 and 2009, 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 consolidation standards. Under the standards, Tampa Electric 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, under the contract 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. Tampa Electric Company purchased $14.7 million and $6.9 million, and $45.0 million and $24.3 million under this PPA for the three months and nine months ended Sep. 30, 2010 and 2009, 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. Tampa Electric Company’s involvement with these VIEs does not affect our Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

48

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida economy and demand for TECO Coal ‘s production; weather variations and changes in customer energy usage patterns affecting sales and operating costs at Tampa Electric and Peoples Gas and 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; fuel cost recoveries and related cash at Tampa Electric and natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; changes in the U.S. federal tax code on earnings from foreign investments that could reduce earnings. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2009, and as updated by Item 1A “Risk Factors” of Part II of its Report on Form 10-Q for the quarter ended Mar. 31, 2010.

Earnings Summary -Unaudited
	Three months ended Sep. 30,				Nine months ended Sep. 30,
(millions, except per share amounts)	2010		2009		2010		2009
Consolidated revenues		901.8		896.3		2,712.9		2,545.5
Net income		51.0		64.8		182.3		160.4
Average common shares outstanding
Basic		212.8		211.9		212.5		211.7
Diluted		215.1		213.2		214.6		212.8
Earnings per share - basic
Earnings per share - basic		0.24		0.30		0.85		0.75
Earnings per share - diluted
Earnings per share - diluted		0.24		0.30		0.85		0.75

Operating Results

Three Months Ended Sep. 30, 2010

TECO Energy, Inc. reported third quarter net income of $51.0 million or $0.24 per share, compared to $64.8 million or $0.30 per share in the third quarter of 2009. Net income in the third quarter was reduced by the one time $24.0 million reduction in base revenue ($14.7 million after-tax) at Tampa Electric under its regulatory agreement approved by the Florida Public Service Commission (FPSC) in August, and a $24.9 million tax charge on undistributed earnings at DECA II as a result of its sale in October 2010. Net income included a $1.8 million benefit from the recovery of fees related to the previously sold McAdams Power Station. Third quarter 2009 net income included $15.4 million of restructuring charges and $5.2 million related to the write-off of project development costs at Tampa Electric and a $0.2 million valuation adjustment to auction rate securities held at TECO Energy.

Nine Months Ended Sep. 30, 2010

Year-to-date net income and earnings per share were $182.3 million or $0.85 per share in 2010, compared to $160.4 million or $0.75 per share in the same period in 2009. Year-to-date net income in 2010 was reduced by the third quarter factors discussed above and $20.3 million of early debt retirement charges and the final $0.9 million of restructuring charges recorded in the first quarter of 2010. Year-to-date net income in 2009 included the third quarter factors discussed above, a $3.8 million loss on auction-rate securities held at TECO Energy, and an $8.7 million net gain on the sale of TECO Guatemala’s 16.5% interest in the Central American fiber optic telecommunications provider Navega.

Operating Company Results

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

Due to an accounting rule change related to variable interest entities, effective Jan. 1, 2010 the results from the San José and Alborada power stations at TECO Guatemala were consolidated in the financial statements of TECO Energy. Prior periods have not been restated to reflect this change, which did not affect net income.

49

Tampa Electric Company – Electric Division

Tampa Electric reported net income for the third quarter of $61.9 million, compared with $54.3 million for the same period in 2009. There were no charges or gains in the third quarter of 2010. Third quarter 2009 net income was reduced by $11.1 million of restructuring charges and the $5.2 million write-off of project development costs primarily related to the Polk Unit 6 IGCC project.

Net income for the 2010 quarter reflected the one-time $24.0 million reduction in base revenues ($14.7 million after tax) associated with the regulatory agreement approved by the FPSC in August that resolved all outstanding issues in the 2008 base rate case. Net income also reflected the 2010 component of rates approved by the FPSC in December 2009, 0.8% higher average number of customers, higher earnings on nitrogen oxide (NOx) control projects, and higher operations and maintenance expenses. Net income included $0.2 million of Allowance for Funds Used During Construction (AFUDC) - equity, which represents allowed equity cost capitalized to construction costs, compared with $2.5 million in the 2009 period.

Total retail energy sales increased 3.6% in the third quarter of 2010, compared to the same period in 2009. Total degree days in Tampa Electric’s service area were 6% above normal and 4% higher than in the third quarter of 2009. Pretax base revenue increased between $6.0 and $8.0 million from hotter summer weather in the third quarter of 2010, compared to the same period last year. Pretax base revenues increased between $7.0 and $9.0 million in the third quarter of 2010, due to the new base rates approved by the FPSC for Tampa Electric effective in January 2010.

Sales to the weather-sensitive residential customer segment increased 5.7% due to the hotter-than-normal summer weather and customer growth. Sales to the commercial customer segment increased 2.6% in the third quarter, primarily due to hotter-than-normal summer weather. Sales to non-phosphate industrial customers increased 5.3% due to increased operations for several customers following low usage in 2009. Sales to industrial-phosphate customers decreased 3.3% in the third quarter of 2010, driven by increased self-generation by a single large phosphate producer, which is expected to continue.

Operations and maintenance expense, excluding charges and all FPSC-approved cost recovery clauses, increased slightly, driven primarily by the accrual of performance-based incentive compensation for all employees based on financial results.

Compared to the third quarter of 2009, depreciation and amortization expense increased $2.2 million, reflecting additions to facilities to serve customers including peaking combustion turbines, NOx control projects and coal rail unloading facilities.

Year-to-date net income was $166.8 million, compared with $121.1 million in the 2009 period. There were no charges or gains in the 2010 period. Year-to-date 2009 net income was reduced by the $16.3 million of third-quarter charges described above.

Year-to-date 2010 results were driven primarily by higher base revenues from favorable weather, new base rates, 0.6% higher average number of customers, higher earnings on NOx control projects, and lower operations and maintenance expenses. Net income included $1.6 million of AFUDC - equity, compared with $8.3 million in the 2009 period for NOx control projects, coal rail unloading facilities and peaking combustion turbines. Sales to other utilities increased 15% from the 2009 period, reflecting 2010’s weather extremes.

Total degree days in Tampa Electric’s service area were 14% above normal and 10% above the prior year-to-date period. Pretax base revenue increased between $24.0 and $33.0 million from favorable weather in 2010 compared to the same period last year. Pretax base revenues increased between $50.0 and $60.0 million in the 2010 year-to-date period due to the new base rates approved by the FPSC for Tampa Electric effective in May 2009 and January 2010.

In the 2010 year-to-date period, total retail energy sales increased 4.2%, compared to the 2009 period, driven primarily by favorable weather and the 0.6% increase in the average number of customers. Favorable weather in the period contributed to an 8.6% increase in sales to the weather-sensitive residential customer class. Sales to industrial-other customers declined 3.2% primarily due to economic conditions. Operations and maintenance expense, excluding restructuring charges, project write-off and all FPSC-approved cost recovery clauses, decreased $2.1 million, due to lower spending on generating unit maintenance more than offsetting the accrual of performance-based incentive compensation for all employees.

Compared to the 2009 year-to-date period, depreciation and amortization expense increased $8.0 million, reflecting the additions to facilities to serve customers discussed above. In 2010, interest expense increased $3.2 million due to debt issued in 2009.

50

A summary of Tampa Electric’s regulated operating statistics for the three months and nine months ended Sep. 30, 2010 and 2009 follows:

	Operating Revenues									Kilowatt-hour sales
(millions, except average customers)	2010			2009			% Change			2010		2009		% Change
Three months ended Sep. 30,
By Customer Type
Residential	$	339.2		$	325.1			4.3			2,830.0		2,677.3		5.7
Commercial		183.3			183.2			0.1			1,792.9		1,747.8		2.6
Industrial – Phosphate		19.0			20.1			(5.5	)		210.4		217.7		(3.4	)
Industrial – Other		27.8			26.8			3.7			285.9		271.5		5.3
Other sales of electricity		50.7			52.3			(3.1	)		482.8		492.9		(2.0	)
Deferred and other revenues(1)		(28.7	)		(7.8	)		267.9			0.0		0.0		0.0
Total		591.3			599.7			(1.4	)		5,602.0		5,407.2		3.6
Provision for revenue stipulation		(24.0	)		0.0			0.0			0.0		0.0		0.0
Sales for resale		13.1			8.3			57.8			173.2		81.1		113.6
Other operating revenue		13.2			12.9			2.3			0.0		0.0		0.0
Total	$	593.6		$	620.9			(4.4	)		5,775.2		5,488.3		5.2
Average customers (thousands)		671.0			665.6			0.8
Retail output to line (kilowatt hours)											5,820.4		5,722.4		1.7
Nine months ended Sep. 30,
By Customer Type
Residential	$	862.1		$	833.8			3.4			7,193.7		6,622.1		8.6
Commercial		491.7			522.8			(5.9	)		4,727.4		4,711.3		0.3
Industrial – Phosphate		64.1			60.9			5.3			725.4		684.8		5.9
Industrial – Other		78.6			85.4			(8.0	)		804.1		830.7		(3.2	)
Other sales of electricity		143.9			152.7			(5.8	)		1,352.3		1,357.7		(0.4	)
Deferred and other revenues(1)		(15.5	)		(32.9	)		(52.9	)		0.0		0.0		0.0
Total		1,624.9			1,622.7			0.1			14,802.9		14,206.6		4.2
Provision for revenue stipulation		(24.0	)		0.0			0.0			0.0		0.0		0.0
Sales for resale		33.0			33.5			(1.5	)		400.2		347.8		15.1
Other operating revenue		37.8			35.8			5.6			0.0		0.0		0.0
SO2 Allowance sales		0.0			0.1			(100.0	)		0.0		0.0		0.0
NOx Allowance sales		0.2			0.0			0.0			0.0		0.0		0.0
Total	$	1,671.9		$	1,692.1			(1.2	)		15,203.1		14,554.4		4.5
Average customers (thousands)		670.6			666.4			0.6
Retail output to line (kilowatt hours)											15,770.0		15,185.7		3.8

(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 $3.7 million for the third quarter, compared to $3.4 million in the same period in 2009. There were no charges or gains in the third quarter of 2010. Net income in 2009 was reduced by $2.8 million of restructuring costs. Quarterly results in 2010 reflect a 0.6% higher average number of customers, increased sales to commercial and industrial customers due to the return to service of several higher volume customers that were idle in the 2009 period. Non-fuel operations and maintenance expense increased, due to the accrual of performance-based incentive compensation for all employees based on financial results and a provision related to potential earnings above the top of the allowed return on equity (ROE) range, discussed below. Results also reflect increased depreciation expense due to routine plant additions.

For 2010, as a result primarily of the unprecedented cold winter weather, Peoples Gas expects to earn above the top of its allowed ROE range of 9.75% to 11.75%. As a result, in the third quarter of 2010, Peoples Gas recorded an additional provision related to these potential earnings. The disposition of any earnings above the top of the allowed range would be determined by the FPSC.

Peoples Gas reported net income of $26.7 million for the year-to-date period, compared to net income of $19.2 million, which was reduced by $2.8 million of restructuring costs, in the same period in 2009. Results reflect a 0.5% higher average number of customers. Residential customer usage increased due to the cold first quarter winter weather in 2010. Pretax base revenues increased approximately $10 million due to the unprecedented cold winter weather and approximately $5 million due to the higher base rates which became effective in June 2009. Increased sales to commercial and industrial customers reflect the colder-than-normal winter weather, the return to service of several higher volume customers that were idle in the 2009 period and generally higher usage by those customers. Off-System sales and gas transported for power generation customers increased over the 2009 year-to-date period due to higher power demand in the first quarter. Non-fuel operations and maintenance expense increased, due to the same factors as in the third quarter.

51

A summary of PGS’ regulated operating statistics for the three months and nine months ended Sep. 30, 2010 and 2009 follows:

	Operating Revenues							Therms
(millions, except average customers)	2010		2009		% Change			2010		2009		% Change
Three months ended Sep. 30,
By Customer Type
Residential	$	24.0	$	25.0		(4.0	)		9.9		9.9		0.0
Commercial		27.0		29.1		(7.2	)		85.5		83.3		2.6
Industrial		2.2		1.7		29.4			46.5		41.5		12.0
Off system sales		49.2		31.9		54.2			94.1		82.8		13.6
Power generation		3.0		2.4		25.0			180.0		159.0		13.2
Other revenues		8.9		8.7		2.3			0.0		0.0		0.0
Total	$	114.3	$	98.8		15.7			416.0		376.5		10.5
By Sales Type
System supply	$	83.4	$	69.7		19.7			115.0		104.0		10.6
Transportation		22.0		20.4		7.8			301.0		272.5		10.5
Other revenues		8.9		8.7		2.3			0.0		0.0		0.0
Total	$	114.3	$	98.8		15.7			416.0		376.5		10.5
Average customers (thousands)		335.2		333.0		0.6
Nine months ended Sep. 30,
By Customer Type
Residential	$	124.6	$	111.4		11.8			69.7		56.7		22.9
Commercial		111.7		109.6		1.9			307.0		284.9		7.8
Industrial		7.0		5.7		22.8			149.6		133.8		11.8
Off system sales		136.5		84.6		61.3			249.3		196.0		27.2
Power generation		7.5		7.8		(3.8	)		452.8		412.0		9.9
Other revenues		31.3		31.7		(1.3	)		0.0		0.0		0.0
Total	$	418.6	$	350.8		19.3			1,228.4		1,083.4		13.4
By Sales Type
System supply	$	313.3	$	252.9		23.9			359.2		295.2		21.7
Transportation		74.0		66.2		11.8			869.2		788.2		10.3
Other revenues		31.3		31.7		(1.3	)		0.0		0.0		0.0
Total	$	418.6	$	350.8		19.3			1,228.4		1,083.4		13.4
Average customers (thousands)		336.2		334.7		0.4

TECO Coal

TECO Coal achieved third quarter net income of $8.3 million on sales of 2.2 million tons, compared to $11.6 million on sales of 2.3 million tons in the same period in 2009. In 2010, results reflect an average net per-ton selling price, excluding transportation allowances, of $76 per ton, due to a sales mix that was more heavily weighted to utility steam coal as a result of transportation constraints. In the third quarter of 2010, the all-in total per-ton cost of production increased to almost $71 per ton from the timing of surface mine reclamation activities, generally higher mining costs due to increased inspection activities, and availability of contract miners. TECO Coal’s effective income tax rate in the third quarter of 2010 was 24%, which was the same as the 2009 period.

TECO Coal recorded year-to-date net income of $45.8 million on sales of 6.8 million tons in 2010, compared to $29.7 million on sales of 6.8 million tons in the 2009 period. Year-to-date net income includes a $5.3 million benefit from the settlement of state income tax issues recorded in prior years. The 2010 year-to-date sales mix was driven by the same factors as the third quarter. The 2010 year-to-date average net per-ton selling price was more than $76 per ton, and the all-in total per-ton cost of production was almost $69 per ton. TECO Coal’s effective income tax rate was a more normal 23%, excluding the effect of the state income tax settlements discussed above, compared to 18% in the 2009 year-to-date period.

TECO Guatemala

TECO Guatemala reported a third quarter loss of $12.6 million in 2010, compared to net income of $8.1 million in the 2009 period. TECO Guatemala’s third quarter 2010 net income was reduced by the $24.9 million tax charge related to undistributed earnings as a result of the sale of its ownership interest in DECA II, which included EEGSA and affiliated companies, on Oct. 21, 2010. There were no charges or gains in the third quarter of 2009.

52

Year-to-date 2010 net income was $8.4 million, compared to $29.2 million in the 2009 period. Year-to-date 2010 net income included the third quarter tax charge. Year-to-date 2009 net income included an $8.7 million gain on the sale of the telecommunication company, Navega.

Third quarter 2010 results include a $3.6 million benefit from insurance recoveries related to the unplanned outages at the San José Power Station in 2009. Normal operations and capacity payments at San José increased net income $2.9 million in 2010. In the 2010 year-to-date period, higher capacity payments, contract sales and first quarter spot energy sales at the San José Power Station increased net income $11.9 million. Because the capacity payment for the San José Power Station is calculated on a rolling 12-month average, it returned to normal levels in the second quarter of 2010. Year-to-date results in 2010 for DECA II included an $0.8 million benefit related to an adjustment to previously estimated year-end equity balances, compared to a similar $2.5 million benefit in 2009.

On Oct. 21, 2010, TECO Energy announced that a subsidiary, TPS de Ultramar, Ltd. (TPSU), sold its interest in Distribución Eléctrica Centro Americana II, S.A. (DECA II) to Empresas Públicas de Medellín E.S.P. (EPM), a multi-utility company based in Medellín Colombia, under a Stock Purchase Agreement (SPA) signed on Oct. 21, 2010, for a purchase price of $181.5 million. TPSU is a subsidiary of TECO Guatemala Holdings, LLC (TGH).

DECA II is a holding company in which, prior to the sale, TGH held a 30% interest, Iberdrola Energia, S.A. held a 49% interest and EDP – Energias de Portugal, S.A. held a 21% interest. Each of these parties sold its interest in DECA II pursuant to the SPA. DECA II holds an 80.9% ownership interest in Empresa Eléctrica de Guatemala (EEGSA) and affiliated companies. EEGSA is the largest Guatemalan distribution utility, which serves Guatemala City, the capital of Guatemala and the surrounding region.

SeeNote 17 – Subsequent Eventto theTECO Energy Consolidated Financial Statements for additional information.

Parent & Other

The cost for Parent & other in the third quarter of 2010 was $10.3 million, compared to a cost of $12.6 million in the same period in 2009. The third quarter 2010 cost included a $1.8 million benefit from the recovery of fees related to the previously sold McAdams Power Station. The third quarter cost in 2009 included a $1.5 million gain on the sale of the final lease in a leveraged lease portfolio, $1.5 million of restructuring costs and a $0.2 million charge associated with the sale of auction-rate securities held at TECO Energy Parent.

The year-to-date Parent & other cost was $65.4 million in 2010, compared to $38.8 million in the 2009 period. The 2010 year-to-date cost included the third quarter benefit related to the McAdams Power station, the $20.3 million of debt retirement charges and $0.9 million of final restructuring charges. The 2009 year-to-date Parent & other cost included the $1.5 million restructuring charge and the $3.8 million valuation adjustment on student-loan securities held at TECO Energy and a $2.6 million benefit from a sale of property by TECO Properties. In 2010, the year-to-date cost for Parent & other also included negative valuation adjustments to foreign tax credits totaling $5.9 million based on estimated foreign source income and projected timing of the utilization of the net operating loss carryforwards, 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 nine month periods ended Sep. 30, 2010 and 2009 were $135.9 million and $73.0 million, respectively. The nine months ended Sep. 30, 2010 includes the $24.9 million of U.S. deferred taxes recognized on undistributed earnings of certain foreign subsidiaries which are no longer considered indefinitely reinvested.

Liquidity and Capital Resources

The table below sets forth the Sep. 30, 2010 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and Tampa Electric Company credit facilities.

	Balances as of Sep. 30, 2010
(millions)	Consolidated		Tampa Electric Company		Other		Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts / LCs		34.6		27.9		0.0		6.7
Available credit facilities		640.4		447.1		0.0		193.3
Cash and short-term investments		166.3		16.2		61.8		88.3
Total liquidity	$	806.7	$	463.3	$	61.8	$	281.6

53

In the first quarter of 2010, TECO Energy and TECO Finance tendered for, purchased and retired a total of $300 million aggregate principal amount of 7.00% and 7.20% TECO Energy and TECO Finance notes, and TECO Finance issued $250 million aggregate principal amount of 4.00% notes due in 2016 and $300 million aggregate principal amount of 5.15% notes due in 2020, which notes are fully and unconditionally guaranteed by TECO Energy. In April 2010, TECO Energy redeemed all of the outstanding $100 million aggregate principal amount of its floating rate notes due May 2010 and $100 million aggregate principal amount of its 7.20% notes due in 2011.

On Nov. 3, 2010, TECO Energy and TECO Finance submitted optional redemption notices to holders of $73.2 million and $163.1 million, respectively, of 7.0% notes due May 1, 2012. Settlement of the optional redemption is expected to be Dec. 2, 2010. SeeNote 17 - Subsequent Events to the TECO Energy Consolidated Financial Statements for additional information.

Credit Ratings of Senior Unsecured Debt at Sep. 30, 2010
	Standard & Poor’s	Moody’s	Fitch
Tampa Electric Company	BBB	Baa1	BBB+
TECO Energy/TECO Finance	BBB-	Baa3	BBB-

Standard & Poor’s, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for Standard & Poor’s is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign 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 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 investment grade credit ratings. SeeNote 11 to theTampa Electric Company 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.

2010 Earnings Outlook

At the time TECO Energy announced Tampa Electric’s regulatory stipulation and a one-time $24 million base revenue reduction for 2010, in July it tightened the outlook for 2010 earnings to a range of $1.25 and $1.35 per share including the effects of the previously announced regulatory stipulation and excluding charges and gains.

As a result of margin compression on TECO Coal sales, and the loss of DECA II earnings for the final two months of the year, TECO Energy believes it is unlikely that results will exceed the middle of its guidance range.

The guidance was provided in the form of a range to allow for varying outcomes with respect to important variables, such as the strength of the economic recovery in 2010, weather and customer usage at the Florida utilities, and demand for production, achieved margins and the potential for deferral of contracted tons at TECO Coal. The July guidance range included TECO Coal’s sales forecast of 9.0 million tons, at an average selling price of $77 per ton. The all-in total cost of production was expected to be within the previously provided range of $65 to $69 per ton but towards the high end, reflecting higher contract miner costs and the negative impact on productivity of increased safety inspections. In February, Tampa Electric and Peoples Gas forecasted no customer growth and weather-normalized energy sales below 2009 levels, primarily due to lower expected sales to commercial and non-phosphate industrial customers; however, year-to-date customer and weather normalized energy sales growth has been stronger than initially expected.

Tampa Electric entered into a stipulation with the intervenors from its 2008 base rate proceeding (the Office of Public Counsel, the State of Florida Office of the Attorney General, the Florida Industrial Powers User Group and the Florida Retail Federation). The stipulation, which was approved by the FPSC in August, resolves all issues in the docket and all issues in the intervenors appeal of the FPSC’s 2009 decision in the base rate proceeding pending before the Florida Supreme Court, thereby enabling the docket related to the base rate proceeding to be closed.

Under the terms of the stipulation, the $25.7 million step increase remains in effect for 2010. The stipulation included a one-time reduction of $24.0 million to customer’s bills, which Tampa Electric recognized in the third quarter of 2010 and will apply to customer bills in the fourth quarter. Effective Jan. 1, 2011, and for subsequent years, rates of $24.4 million (a $1.3 million reduction from the $25.7 million in effect for 2010) related to the step increase will be in effect.

With the effects of the regulatory stipulation included, Tampa Electric expects to earn near the midpoint of its allowed ROE range of 10.25% to 12.25%. Taking into account the disposition of earnings above the top of its allowed ROE range, Peoples Gas expects to earn at the top of its allowed ROE range of 9.75% to 11.75% for the year, primarily as a result of the abnormally cold winter weather. In the 2010 year-to-date period, Tampa Electric and Peoples Gas have recorded actual customer growth of 0.6% and 0.5%, respectively, and 4.2% higher retail electric sales and 13.4% higher therm sales, respectively, due to favorable weather and customer growth. The utilities expect to benefit from the year-to-date actual customer growth for the remainder of the year. However, this guidance assumed normal weather for the remainder of the year, but October weather has consistently been milder than normal.

TECO Coal expects to sell almost 9 million tons at an average price of more than $76 per ton. The all-in, total cost of production is expected to be at the top of the previously provided range of $65 to $69 per ton due to the timing of surface mine reclamation activities and generally higher mining costs due to increased inspection activities. The utility steam coal market remains weak for new contract activity, but customers are taking delivery of existing contract amounts in 2010. TECO Coal’s effective income tax rate is expected to be the normal 25% for 2010.

The San José Power Station is operating normally and the capacity payments are back to normal levels. Due to the resumption of normal rainfall, the ability to make spot energy sales at good margins, which favorably impacted results earlier in the year, is expected to be limited in the fourth quarter. Prior to its sale, EEGSA experienced customer and energy sales growth and that partially mitigated the negative impacts of the lower Value Added Distribution. Prior to the sale, DECA II was expected to contribute approximately $15 million to 2010 net income at TECO Guatemala; the Oct. 21, 2010 sale of DECA II will reduce the expected net income contribution by approximately $2 million. 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 current contract level effective Sep. 14, 2010. The 2010 impact of the lower capacity payments and the loss of earnings from DECA II are included in the earnings outlook.

54

2011 Preliminary Outlook

The operating companies are in the process of developing detailed 2011 business plans and formal 2011 guidance will be provided at the time of TECO Energy’s fourth quarter earnings release in early February. Major business drivers that are expected to drive 2011 results are:

For 2011, the Florida utilities expect to continue to earn within their allowed ROE ranges of 10.25% to 12.25% for Tampa Electric and 9.75% and 11.75% for Peoples Gas. Tampa Electric expects customer growth to continue in line with the trends experienced in 2010; however, due to the unusual weather experienced in 2010 lower energy sales are expected in 2011 with normal weather. In the first nine months of 2010, weather added between $24.0 and $33.0 million to pretax base revenue at Tampa Electric compared to 2009 when weather was more normal. Also in 2010, Tampa Electric reduced base revenue $24.0 million as a one-time item under its regulatory agreement approved by the FPSC.

TECO Coal has approximately 90% of its expected sales of between 8.5 and 9.0 million tons in 2011 contracted or prices agreed to resulting in an average selling price across all products of more than $85 per ton. The product mix is expected to be about 35% specialty coal, which includes stoker, metallurgical and PCI coals, and the remainder utility steam coal. The cost of production is expected to increase to a range between $71 and $75 per ton due to expected higher contract miner costs, higher safety related costs and higher surface mining costs due to delays in the issuance of permits.

TECO Guatemala expects normal operations for the Alborada and San José power stations. The Alborada Power Station’s capacity payments will be at the new contract rate.

Covenants in Financing Agreements

In order to utilize their respective bank credit 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 other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2010, TECO Energy, TECO Finance, Tampa Electric Company and the other operating companies were in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Sep. 30, 2010. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants

(millions, unless otherwise indicated)     Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Sep. 30, 2010
Tampa Electric Company
Credit facility(2)	Debt/capital	Cannot exceed 65%	48.2%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%	48.2%
6.25% senior notes	Debt/capital	Cannot exceed 60%	48.2%
	Limit on liens(3)	Cannot exceed $700	$0 liens outstanding
Insurance agreement relating to certain pollution bonds	Limit on liens(3)	Cannot exceed $435 (7.5% of net assets)	$0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	EBITDA/interest(2)(4)	Minimum of 2.6 times	4.4 times
TECO Energy and TECO Finance 6.75% notes	Restrictions on secured debt(5)	(6)	(6)
CGESJ
Non-recourse project debt-dividend restriction	EBITDA/debt service(4)	Minimum of 1.3 times	4.1 times

(1) As defined in each applicable instrument.

(2) See description of credit facilities inNote 6 to the 2009 TECO Energy, Inc. Annual Report on Form 10-K.

(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 limitations would not include 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.

55

Off-Balance Sheet Financing

Unconsolidated affiliates have project debt balances as follows at Sep. 30, 2010. TECO Energy has no debt payment obligations with respect to these financings. Although the company is not directly obligated on the debt, the equity interest in those unconsolidated affiliates is at risk if those projects are not operated successfully. On Oct. 21, 2010, a TECO Energy subsidiary, TPSU, sold its interest in this unconsolidated affiliate to an unaffiliated third party.

(millions)	Long-term Debt		Ownership Interest
DECA II	$	175.8		24	%

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 inNote 13 to theTECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration, and whether the markets in which we transact have experienced dislocation. At Sep. 30, 2010 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 ourAnnual Report on Form 10-K for the year ended Dec. 31, 2009.

Environmental Matters

In October 2010, The U.S. Environmental Protection Agency (EPA) notified Tampa Electric Company that it is a potentially responsible party under the federal Superfund law 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, is not based upon any release of hazardous substances by Tampa Electric Company. Tampa Electric Company is in the process of responding to such matter, and the scope and extent of its potential liability, if any, and the costs of any required investigation and remediation have not been determined.

56

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 2010 is the potential effect of high natural gas prices on our cash flows. Prudently incurred costs for natural gas are recoverable through FPSC-approved cost recovery clauses, and therefore do not affect our earnings. However, higher than expected prices for natural gas can affect the timing of recovery and thus impact cash flows.

The change in fair value of derivatives is largely due to the decrease in the price of natural gas of approximately 28% from Dec. 31, 2009 to Sep. 30, 2010. For natural gas, the company maintains a similar volume hedged as of Sep. 30, 2010 from Dec. 31, 2009.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine months ended Sep. 30, 2010:

Changes in Fair Value of Derivatives(millions)
Net fair value of derivatives as of Dec. 31, 2009	$	(36.6	)
Additions and net changes in unrealized fair value of derivatives		(80.0	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		66.0
Net fair value of derivatives as of Sep. 30, 2010	$	(50.6	)
Roll-Forward of Derivative Net Assets (Liabilities)(millions)
Total derivative net liabilities as of Dec. 31, 2009	$	(36.6	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(80.0	)
Recorded in earnings		0.0
Realized net settlement of derivatives		66.0
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Sep. 30, 2010	$	(50.6	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sep. 30, 2010:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) at Sep. 30, 2010(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)		(45.0	)		(5.6	)		(50.6	)
Model prices(2)		0.0			0.0			0.0
Total	$	(45.0	)	$	(5.6	)	$	(50.6	)

(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.

57

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.

Item 5. OTHER

The following disclosures are provided pursuant to the recently enacted Dodd-Frank Act, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate coal mines regulated under the U.S. Federal Mine Safety and Health Act of 1977 (the Mine Act). Under the Dodd-Frank Act, the SEC is authorized to issue rules and regulations to carry out the purposes of these provisions, but has not done so as of the date of this report. While we believe the following disclosures meet the requirements of the Dodd-Frank Act, it is possible that future rule making by the SEC will require disclosures to be presented in a form that differs from the following.

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

The table that follows reflects citations and orders issued by MSHA either to (i) TECO Coal Corporation subsidiaries (TECO Coal), or (ii) third-party service providers operating on the site of a TECO Coal property, during the three months ended Sep. 30, 2010, as reported in MSHA’s Mine Data Retrieval System as of Oct. 28, 2010. As MSHA routinely updates its mine data, the data contained in the table below is accurate as of the date reported.

Additional information follows about MSHA references used in the table.

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

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

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

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

• Section 107(a) Orders: The total number of orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an imminent danger existed.

	For the three months ended Sep. 30, 2010
	Perry County		Clintwood Elkhorn		Premier Elkhorn		Total
Section 104(a) Citations(1)		151		25		9		185
Section 104(b) Orders(2)		1		0		0		1
Section 104(d) Citations and Orders(3)		2		0		3		5
Section 110(b)(2) Violations		0		0		0		0
Section 107(a) Orders		0		0		0		0
Proposed MSHA Assessments (in thousands)	$	130.1	$	35.2	$	1.7	$	167.0
Fatalities		0		0		0		0

1) 34 of the 187 Section 104 Citations were issued to third-party service providers at TECO Coal sites. A number of the remaining Citations are in the process of being contested.

2) This Section 104(b) Order was issued to a third-party service provider at a TECO Coal site.

3) Two of the three Section 104(d) Orders were issued to third-party service providers at a TECO Coal site. The remaining three Citations or Orders are in the process of being contested.

Pattern or Potential Pattern of Violations.During the three months ended Sep. 30, 2010, none of the mines operated by TECO Coal received written notice from MSHA of (a) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or (b) the potential to have such a pattern.

Pending Legal Actions.The Federal Mine Safety and Health Review Commission (the Commission) is an independent adjudicative agency that provides administrative trial and appellate review of legal disputes arising under the Mine Act. These cases may involve, among other questions, challenges by operators to citations, orders and penalties they have received from MSHA, or complaints of discrimination by miners under Section 105 of the Mine Act. The following is a brief description of the types of legal actions that may be brought before the Commission.

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

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

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

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

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

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

The table that follows presents information by mining company subsidiary regarding pending legal actions before the Commission at Sep. 30, 2010. Each legal action is assigned a docket number by the Commission and may have as its subject matter one or more citations, orders, penalties or complaints.

	For the three months ended Sep. 30, 2010
	Perry County Coal		Clintwood Elkhorn Mining		Premier Elkhorn Coal		Total
Pending Legal Actions		25		0		4		29

58

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)		(b)		(c)		(d)
	Total Number of Shares (or Units) Purchased(1)		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Jul. 1, 2010 – Jul. 31, 2010		1,810	$	15.77		0		0
Aug. 1, 2010 – Aug. 31, 2010		9,145	$	16.80		0		0
Sep. 1, 2010 – Sep. 30, 2010		507	$	17.13		0		0
Total 3rd Quarter 2010		11,462	$	16.65		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 61.

59

SIGNATURES

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

	TECO ENERGY, INC.
	(Registrant)
Date:     November 5, 2010	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)
	TAMPA ELECTRIC COMPANY
	(Registrant)
Date:     November 5, 2010	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)

60

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 Oct. 29, 2009 (Exhibit 3.1, Form 8-K dated Oct. 29, 2009 of TECO Energy, Inc.).	*
3.3	Articles of Incorporation of Tampa Electric Company (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.4	Bylaws of Tampa Electric Company, as amended effective Jan. 30, 2008 (Exhibit 3.4, Form 10-K for 2007 of TECO Energy, Inc. and Tampa Electric Company).	*
10.1	Employment Agreement between TECO Energy, Inc. and Sherrill W. Hudson dated Aug. 4, 2010 (Exhibit 10.1, Form 8-K dated Aug. 4, 2010 of TECO Energy, Inc.).	*
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)
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.

61

(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.

62