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, 2006                        

or

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

For the transition period from              to             

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on             which registered
TECO Energy, Inc.
Common Stock, $1.00 par value	New York Stock Exchange
Common Stock Purchase Rights	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

YES  [X]        NO  [   ]

Indicate by check mark whether TECO Energy, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  [X]        Accelerated filer  [   ]        Non-accelerated filer  [   ]

Indicate by check mark whether Tampa Electric Company is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  [   ]        Accelerated filer  [   ]        Non-accelerated filer  [X]

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

YES  [   ]        NO  [X]

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

YES  [   ]        NO  [X]

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Oct. 31, 2006 was 209,199,563. As of Oct. 31, 2006, 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 50

Index to Exhibits appears on page 50

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, 2006 and Dec. 31, 2005, and the results of their operations and cash flows for the periods ended Sep. 30, 2006 and 2005. The results of operations for the three month and nine month periods ended Sep. 30, 2006 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2006. References should be made to the explanatory notes affecting the consolidated condensed financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and to the notes on pages 9 through 25 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2006 and Dec. 31, 2005	3-4
Consolidated Condensed Statements of Income for the three month and nine month periods ended Sep. 30, 2006 and 2005	5-6
Consolidated Condensed Statements of Comprehensive Income for the three month and nine month periods ended Sep. 30, 2006 and 2005	7
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2006 and 2005	8
Notes to Consolidated Condensed Financial Statements	9-25

2

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets		Sep. 30,			Dec. 31,
(millions, except for share amounts)		2006			2005
Current assets
Cash and cash equivalents	$	561.8		$	345.7
Restricted cash		37.3			37.6
Receivables, less allowance for uncollectibles of $5.8 and $6.9 at Sep. 30, 2006 and Dec. 31, 2005, respectively		363.6			323.3
Inventories, at average cost
Fuel		86.9			84.9
Materials and supplies		75.4			68.9
Current regulatory assets		278.9			296.3
Current derivative assets		6.3			64.0
Prepayments and other current assets		42.2			51.5
Total current assets		1,452.4			1,272.2
Property, plant and equipment
Utility plant in service
Electric		4,958.8			4,892.3
Gas		864.1			839.5
Construction work in progress		306.1			200.0
Other property		831.5			822.7
Property, plant and equipment		6,960.5			6,754.5
Accumulated depreciation		(2,281.1	)		(2,187.6	)
Total property, plant and equipment (net)		4,679.4			4,566.9
Other assets
Deferred income taxes		703.4			735.7
Other investments		8.0			8.0
Long-term regulatory assets		101.9			101.1
Long-term derivative assets		0.2			4.9
Investment in unconsolidated affiliates		287.6			297.1
Goodwill		59.4			59.4
Deferred charges and other assets		106.1			116.8
Assets held for sale		-			8.0
Total other assets		1,266.6			1,331.0
Total assets	$	7,398.4		$	7,170.1

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		Sep. 30,			Dec. 31,
(millions, except for share amounts)		2006			2005
Current liabilities
Long-term debt due within one year
Recourse	$	566.6		$	5.9
Non-recourse		1.3			1.3
Jr. subordinated notes		71.5			-
Notes payable		-			215.0
Accounts payable		299.0			354.7
Customer deposits		125.7			115.2
Current regulatory liabilities		116.6			146.8
Current derivative liabilities		72.7			0.3
Interest accrued		89.9			50.0
Taxes accrued		79.2			34.9
Liabilities associated with assets held for sale		-			1.8
Total current liabilities		1,422.5			925.9
Other liabilities
Investment tax credits		15.3			17.3
Long-term regulatory liabilities		560.5			543.1
Long-term derivative liabilities		6.7			-
Deferred credits and other liabilities		384.6			382.9
Long-term debt, less amount due within one year
Recourse		3,202.1			3,519.8
Non-recourse		10.4			11.7
Junior subordinated		106.2			177.7
Total other liabilities		4,285.8			4,652.5
Commitments and contingencies (see Note 11)
Capital
Common equity (400.0 million shares authorized; par value $1; 209.1 million shares and 208.2 million shares outstanding at Sep. 30, 2006 and Dec. 31, 2005, respectively)		209.1			208.2
Additional paid in capital		1,457.8			1,527.0
Retained earnings (deficit)		74.6			(83.1	)
Accumulated other comprehensive (loss)		(51.4	)		(51.1	)
Common equity		1,690.1			1,601.0
Unearned compensation		-			(9.3	)
Total capital		1,690.1			1,591.7
Total liabilities and capital	$	7,398.4		$	7,170.1

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

4

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

(millions, except per share amounts)	Three months ended Sep. 30,
			2006			2005
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $28.3 in 2006 and $24.2 in 2005)		$	733.2		$	663.2
Unregulated			189.7			173.2
Total revenues			922.9			836.4
Expenses
Regulated operations
Fuel			226.3			120.4
Purchased power			79.4			104.6
Cost of natural gas sold			84.4			96.7
Other			70.9			68.6
Other operations			164.5			170.2
Maintenance			41.5			52.4
Depreciation			70.1			71.2
Taxes, other than income			55.5			51.7
Sale of previously impaired assets / Asset impairments			(5.0	)		-
Total expenses			787.6			735.8
Income from operations			135.3			100.6
Other income (expense)
Allowance for other funds used during construction			0.8			-
Other income			35.9			64.9
Income from equity investments			14.5			14.8
Total other income (expense)			51.2			79.7
Interest charges
Interest expense			70.5			68.3
Allowance for borrowed funds used during construction			(0.4	)		-
Total interest charges			70.1			68.3
Income before provision for income taxes			116.4			112.0
Provision for income taxes			42.7			39.2
Income from continuing operations before minority interest			73.7			72.8
Minority interest			6.0			21.7
Income from continuing operations			79.7			94.5
Discontinued operations
Loss from discontinued operations			-			(2.0	)
Income tax benefit			-			(2.1	)
Total discontinued operations			-			0.1
Net income		$	79.7		$	94.6
Average common shares outstanding – Basic			207.9			207.1
– Diluted			208.7			209.3
Earnings per share from continuing operations – Basic		$	0.38		$	0.46
– Diluted		$	0.38		$	0.45
Earnings per share from discontinued operations – Basic		$	-		$	-
– Diluted		$	-		$	-
Earnings per share – Basic		$	0.38		$	0.46
– Diluted		$	0.38		$	0.45
Dividends paid per common share outstanding		$	0.19		$	0.19

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

5

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

(millions, except per share amounts)	Nine months ended Sep. 30,
			2006			2005
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $79.1 in 2006 and $65.5 in 2005)		$	2,045.7		$	1,723.0
Unregulated			576.2			517.1
Total revenues			2,621.9			2,240.1
Expenses
Regulated operations
Fuel			609.6			362.8
Purchased power			169.7			190.4
Cost of natural gas sold			295.3			246.6
Other			213.8			195.1
Other operations			496.3			485.8
Maintenance			136.4			128.5
Depreciation			211.0			211.2
Taxes, other than income			165.7			146.5
Sale of previously impaired assets / Asset impairments			(15.7	)		-
Total expenses			2,282.1			1,966.9
Income from operations			339.8			273.2
Other income (expense)
Allowance for other funds used during construction			1.4			-
Other income			66.8			136.3
Loss on debt extinguishment			-			(71.5	)
Income from equity investments			42.9			43.7
Total other income (expense)			111.1			108.5
Interest charges
Interest expense			209.7			220.2
Allowance for borrowed funds used during construction			(0.6	)		-
Total interest charges			209.1			220.2
Income before provision for income taxes			241.8			161.5
Provision for income taxes			92.7			71.0
Income from continuing operations before minority interest			149.1			90.5
Minority interest			46.9			67.9
Income from continuing operations			196.0			158.4
Discontinued operations
Income from discontinued operations			2.3			88.2
Income tax provision			0.9			24.1
Total discontinued operations			1.4			64.1
Net income		$	197.4		$	222.5
Average common shares outstanding – Basic			207.7			206.0
– Diluted			208.6			207.8
Earnings per share from continuing operations – Basic		$	0.94		$	0.77
– Diluted		$	0.94		$	0.76
Earnings per share from discontinued operations – Basic		$	0.01		$	0.31
– Diluted		$	0.01		$	0.31
Earnings per share – Basic		$	0.95		$	1.08
– Diluted		$	0.95		$	1.07
Dividends paid per common share outstanding		$	0.57		$	0.57

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

(millions)	Three months ended Sep. 30,						Nine months ended Sep. 30,
			2006			2005			2006			2005
Net income		$	79.7		$	94.6		$	197.4		$	222.5
Other comprehensive income (loss), net of tax
Net unrealized gains (losses) on cash flow hedges, net of tax			(1.4	)		0.1			(0.3	)		0.6
Other comprehensive income (loss), net of tax			(1.4	)		0.1			(0.3	)		0.6
Comprehensive income		$	78.3		$	94.7		$	197.1		$	223.1

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

(millions)	Nine months ended Sep. 30,
			2006			2005
Cash flows from operating activities
Net income		$	197.4		$	222.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation			211.0			211.2
Deferred income taxes			89.6			84.6
Investment tax credits, net			(2.0	)		(2.0	)
Allowance for funds used during construction			(2.0	)		-
Non-cash stock compensation			9.3			4.1
Gain on sales of business/assets			(46.5	)		(232.9	)
Non-cash debt extinguishment charge			-			17.2
Equity in earnings of unconsolidated affiliates, net of cash distributions on earnings			8.1			(22.3	)
Minority interest			(46.9	)		(67.9	)
Deferred recovery clause			62.1			(61.0	)
Receivables, less allowance for uncollectibles			(27.5	)		(66.5	)
Inventories			(8.4	)		(38.3	)
Prepayments and other deposits			10.1			3.8
Taxes accrued			41.6			27.3
Interest accrued			39.9			51.7
Accounts payable			(45.0	)		117.6
Other			27.7			(10.9	)
Cash flows from operating activities			518.5			238.2
Cash flows from investing activities
Capital expenditures			(301.7	)		(213.8	)
Allowance for funds used during construction			2.0			-
Net proceeds from sale of business/assets			41.7			269.7
Cash paid on disposition of business			-			(31.8	)
Restricted cash			0.3			27.7
Distributions from unconsolidated affiliates			1.1			0.1
Other non-current investments			-			4.2
Cash flows (used in) provided by investing activities			(256.6	)		56.1
Cash flows from financing activities
Dividends			(119.0	)		(118.2	)
Proceeds from the sale of common stock			6.3			194.7
Proceeds from long-term debt			327.5			311.9
Repayment of long-term debt			(93.1	)		(394.0	)
Minority interest			47.5			65.9
Decrease in short-term debt			(215.0	)		(95.0	)
Equity contract adjustment payments			-			(2.0	)
Cash flows used in financing activities			(45.8	)		(36.7	)
Net increase in cash and cash equivalents			216.1			257.6
Cash and cash equivalents at beginning of period			345.7			96.7
Cash and cash equivalents at end of period		$	561.8		$	354.3

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

8

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

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

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries, and the accounts of variable interest entities for which it is the primary beneficiary (TECO Energy or the company). All significant intercompany balances and intercompany transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy is not the primary beneficiary. 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, 2006 and Dec. 31, 2005, and the results of their operations and cash flows for the periods ended Sep. 30, 2006 and 2005. The results of operations for the three month and nine month periods ended Sep. 30, 2006 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2006.

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.

Revenues

As of Sep. 30, 2006 and Dec. 31, 2005, unbilled revenues of $50.9 million and $52.3 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Other Income and Minority Interest

TECO Energy earns a significant portion of its income indirectly through the synthetic fuel operations at TECO Coal. At Sep. 30, 2006 and 2005, TECO Coal had sold ownership interests in the synthetic fuel facilities to unrelated third-party investors equal to 98% and 90%, respectively. During the first half of 2005, TECO Coal allocated an additional 8% of the benefits associated with the synthetic fuel facilities to a third-party investor such that 98% of the nine month 2005 benefits were allocated to third parties. These investors pay for the purchase of the ownership interests as synthetic fuel is produced. The payments are based on the amount of production and sales of synthetic fuel and the related, underlying value of the tax credit, which is subject to potential limitation based on the price of domestic crude oil. These payments are recorded in “Other income” in the Consolidated Condensed Income Statement.

Additionally, the outside investors make payments towards the cost of producing synthetic fuel. These payments are reflected as a benefit under “Minority Interest” in the Consolidated Condensed Income Statement, and these benefits comprise the majority of that line item.

For the nine month period ended Sep. 30, 2006, “Other Income” reflected a phase-out of approximately 39% of the benefit of the underlying value of any 2006 tax credits based on an estimate of the average annual price of domestic crude oil during 2006. The decrease in the curtailment estimate from 63% to 39% at the end of the third quarter resulted in the pretax recognition of approximately $24.1 million of additional gain on the sale of the ownership interest. Should the Dec. 31, 2006 estimate of the average annual price of domestic crude oil be different than this estimate, the cash payments and the benefits recognized in “Other income” and “Minority interest” will be adjusted, either positively or negatively, as part of the year-end financial results. For the same period in 2005, no phase-out of the benefit was recognized.

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 $79.4 million and $169.7 million, respectively, for the three months and nine months ended Sep. 30, 2006, compared to $104.6 million and $190.4 million, respectively, for the three months and nine months ended Sep. 30, 2005. Prudently incurred purchased power costs at Tampa Electric have historically been recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities (Tampa Electric and Peoples Gas) are allowed to recover from customers certain costs, including franchisee fees and gross receipts taxes, through rates approved by the FPSC. These amounts totaled $28.3 million and $79.1 million, respectively, for the three months and nine months ended Sep. 30, 2006, compared to $24.2 million and $65.5 million, respectively, for the three months and nine months ended Sep. 30, 2005. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income.” These totaled $28.3 million and $79.0 million, respectively, for the three months and nine months ended Sep. 30, 2006, compared to $24.3 million and $65.4 million, respectively, for the three months and nine months ended Sep. 30, 2005.

9

Stock-Based Compensation

Effective Jan. 1, 2006, TECO Energy accounts for its stock-based compensation in accordance with Statement of Financial Accounting Standards (FAS) No. 123 (revised 2004), Share-Based Payment (FAS 123R). Under the provisions of FAS 123R, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). Prior to this, the company accounted for its share-based payments under Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees and its related interpretations and the disclosure requirements of FAS 123, Accounting for Stock-Based Compensation, as amended by FAS 148, Accounting for Stock-Based Compensation – Transition and Disclosure. The company elected to adopt the modified-prospective transition method as provided under FAS 123R and, accordingly, results for prior periods have not been restated. See Note 8, Stock-Based Compensation, for more information on share-based payments.

2. New Accounting Pronouncements

Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the Financial Accounting Standards Board (FASB) issued FAS No.158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R). This statement of financial accounting standards requires the recognition in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, measured as the difference between the fair value of plan assets and the benefit obligation in the case of a defined benefit plan, or the accumulated postretirement benefit obligation in the case of other postretirement benefit plans. Compared to the current recognition of pension and other postretirement obligations on the balance sheet, this standard requires the recognition of: 1) the impact of future salary increases to the pension obligation and 2) the unamortized post-retirement benefit costs that are currently being expensed over the service lives of the participants. This standard also requires recognition in other comprehensive income certain benefit cost components that are not part of net periodic benefit cost, and that the defined benefit plan assets and obligations be measured as of the balance sheet date. For the regulated segments, the company is currently assessing whether the amounts required to be recorded in “Other comprehensive income” should be reflected as a regulatory asset, as pension obligations will be recovered through rates. FAS 158 is effective for publicly-held companies for fiscal years ending after Dec. 15, 2006. The company will adopt the balance sheet recognition provisions of FAS 158 at Dec. 31, 2006 and the year-end measurement date in 2008. The company estimates that this standard, using the plan assets and obligations reported as of Dec. 31, 2005, would increase benefit liabilities on the balance sheet by approximately $130 million and accumulated other comprehensive loss, net of estimated tax benefits, or regulatory assets by approximately $82 million. This standard does not affect the results of operations.

Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements (SAB 108). SAB 108 addresses the diversity in practice by registrants when quantifying the effect of an error on the financial statements and provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. The company will be required to adopt the provisions of SAB No. 108 effective Dec. 31, 2006 and believes that the adoption of SAB 108 will not have a material financial impact on the company’s consolidated condensed financial statements.

Fair Value Measurements

In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements. The effective date is for fiscal years ending after Nov. 15, 2007. The company does not believe implementation will be material to its results of operations, statement of position or cash flows.

Accounting for Uncertainty in Income Taxes

In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. The company does not believe implementation will be material to its results of operations, statement of position or cash flows.

10

Income Statement Presentation of Taxes Collected on Behalf of Governmental Authorities

In June 2006, the FASB ratified EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (EITF 06-3). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. EITF 06-3 will be effective for the company as of Jan. 1, 2007. As EITF 06-3 provides only disclosure requirements, the adoption of this standard will not have an impact on the results of operations, statement of position or cash flows.

Determining the Variability of Variable Interest Entities

In April 2006, the FASB issued FASB Staff Position (FSP) FIN 46(R)-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R). In this FSP, the FASB addresses how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. The FASB describes a number of risks that should be considered as well as the purpose for which the entities were created, in order to determine the variability of these entities. The company has reviewed this FSP and has incorporated it into its process for determining the variability for current and future entities. This FSP is not expected to materially impact the company.

Amendment to Derivatives Accounting

In February 2006, the FASB issued FAS No. 155, Accounting for Certain Hybrid Financial Instruments (FAS 155), which amends FAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and FAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. FAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by permitting fair value re-measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after Sep. 15, 2006 and is not expected to materially impact the company.

3. Regulatory

Cost Recovery – Tampa Electric and Peoples Gas

Tampa Electric and Peoples Gas recover the cost of fuel, purchased power, eligible environmental expenditures, and conservation through cost recovery clauses that are adjusted on an annual basis. As part of the regulatory process, it is reasonably likely that third parties may intervene in various matters related to fuel, purchased power, environmental and conservation cost recovery.

SO₂ Emission Allowances

The Clean Air Act Amendments of 1990 established SO₂ allowances to manage the achievement of SO₂ emissions requirements. The legislation also established a market-based SO₂ allowance trading component.

An allowance authorizes a utility to emit one ton of SO₂ during a given year. The Environmental Protection Agency (EPA) allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use currently or in future years. In addition, the EPA withholds a small percentage of the annual SO₂ allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause.

Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO₂ allowances unneeded and sold in 2006 resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.

In January 2006, Tampa Electric sold approximately 40,000 allowances, resulting in proceeds of $40.8 million, the majority of which is included as a cost recovery clause regulatory liability as of Sep. 30, 2006. During the quarter ended Sep. 30, 2006, another 4,500 allowances were sold resulting in proceeds of $2.9 million compared to 100,000 allowances and $79.7 million in proceeds for the third quarter of 2005. Proceeds for the first two quarters of 2005 were immaterial.

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Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting treatment permitted by FAS No. 71, Accounting for the Effects of Certain Types of Regulation. 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 deferral of costs as regulatory assets, when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Sep. 30, 2006 and Dec. 31, 2005 are presented in the following table:

Regulatory Assets and Liabilities

(millions)		Sep. 30, 2006		Dec. 31, 2005
Regulatory assets:
Regulatory tax asset (1)	$	52.4	$	79.5
Other:
Cost recovery clauses		276.9		264.1
Deferred bond refinancing costs (2)		27.6		28.8
Environmental remediation		13.9		14.2
Competitive rate adjustment		5.2		5.6
Other		4.8		5.2
		328.4		317.9
Total regulatory assets		380.8		397.4
Less current portion		278.9		296.3
Long-term regulatory assets	$	101.9	$	101.1
Regulatory liabilities:
Regulatory tax liability (1)	$	51.9	$	23.4
Other:
Deferred allowance auction credits		0.9		1.3
Cost recovery clauses		69.9		136.9
Environmental remediation		13.9		14.2
Deferred gain on property sales (3)		7.3		7.7
Accumulated cost of removal		517.8		493.8
Transmission and delivery storm reserve		15.3		12.5
Other		0.1		0.1
		625.2		666.5
Total regulatory liabilities		677.1		689.9
Less current portion		116.6		146.8
Long-term regulatory liabilities	$	560.5	$	543.1

(1) Related primarily to plant life and derivative positions.

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

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

4. Income Tax Expense

During the nine months ended Sep. 30, 2006 and Sep. 30, 2005, the company experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included permanent reinvestment of foreign income, APB No. 23, Accounting for Taxes – Special Areas, adjustment of deferred tax assets for the effect of an enacted change in state rates, depletion, repatriation of foreign source income to the United States and reduction of income tax expense under the new “tonnage tax” regime.

5. Employee Postretirement Benefits

Included in the table below is the periodic pension expense for pension and other postretirement benefits offered by the company. No significant changes have been made to these benefit plans since Dec. 31, 2003.

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Pension Expense

(millions)		Pension Benefits					Other Postretirement Benefits
Three months ended Sep. 30,		2006			2005				2006		2005
Components of net periodic benefit expense
Service cost	$	4.0		$	4.1			$	1.5	$	1.6
Interest cost on projected benefit obligations		7.6			8.1				2.9		2.8
Expected return on assets		(8.9	)		(9.3	)			-		-
Amortization of:
Transition obligation		-			(0.1	)			0.6		0.6
Prior service (benefit) cost		(0.1	)		(0.1	)			0.8		0.8
Actuarial loss		2.2			1.1				0.1		-
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	4.8		$	3.8			$	5.9	$	5.8
Nine months ended Sep. 30,
Components of net periodic benefit expense
Service cost	$	11.9		$	12.2			$	4.5	$	4.9
Interest cost on projected benefit obligations		23.0			24.5				8.5		8.4
Expected return on assets		(26.8	)		(27.9	)			-		-
Amortization of:
Transition obligation		-			(0.2	)			2.0		2.0
Prior service (benefit) cost		(0.4	)		(0.4	)			2.3		2.3
Actuarial loss		6.6			3.2				0.4		-
Pension expense		14.3			11.4				17.7		17.6
Settlement		-			1.4				-		-
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$	14.3		$	12.8			$	17.7	$	17.6

For the fiscal 2006 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.5% and a discount rate of 5.5% at its Sep. 30, 2005 measurement date. The company’s policy is to fund the pension plan based on the amount determined by the company’s actuaries within the guidelines set by Employee Retirement Income Security Act (ERISA). In January 2006, the company contributed $6.3 million to the pension plan. Although the company is not required to nor has it expressed the intent to make additional contributions to the pension plan in 2006, it may elect to make such additional contributions within the ERISA guidelines.

6. Short-Term Debt

At Sep. 30, 2006 and Dec. 31, 2005, the following credit facilities and related borrowings existed:

Credit Facilities		Sep. 30, 2006						Dec. 31, 2005
(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	$	-	$	-	$	325.0	$	120.0	$	-
1-year accounts receivable facility		150.0		-		-		150.0		95.0		-
TECO Energy:
5-year facility		200.0		-		9.5		200.0		-		14.3
Total	$	675.0	$	-	$	9.5	$	675.0	$	215.0	$	14.3

(1) Borrowings outstanding are reported as notes payable.

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These credit facilities require commitment fees ranging from 12.5 to 37.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2005 was 4.45%. There were no outstanding balances under the credit facilities other than letters of credit at Sep. 30, 2006.

7. Long-Term Debt

Issuance of Tampa Electric Company 6.55% Notes due 2036

On May 12, 2006, Tampa Electric Company issued $250 million aggregate principal amount of 6.55% Notes due May 15, 2036. The 6.55% Notes were sold at 99.375% of par to yield 6.598%. The offering resulted in net proceeds to Tampa Electric Company (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $246.0 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Tampa Electric Company may redeem all or any part of the 6.55% 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 6.55% Notes to be redeemed or (ii) the present value of the remaining payments of principal and interest on the 6.55% Notes to be redeemed, discounted at an applicable treasury rate (as defined in the applicable indenture), plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

Current portions of long-term debt

Long-term debt classified as current liabilities at Sep. 30, 2006 includes the following debt issues maturing in 2007: Tampa Electric Company and Peoples Gas 5.375% notes due August 2007, TECO Energy’s 5.93% junior subordinated notes due January 2007 and 6.125% senior notes due May 2007, and TECO Bulk Terminal’s 5% dock and wharf bonds due September 2007.

8. Stock-Based Compensation

On Jan. 1, 2006, TECO Energy adopted FAS 123R, requiring the company to recognize expense related to the fair value of its stock-based compensation awards. Prior to this, the company accounted for its share-based payments under APB 25 and related interpretations. The company adopted FAS 123R using the modified-prospective transition method. Under this transition method, compensation cost recognized beginning Jan. 1, 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of, Dec. 31, 2005 (based on the grant-date fair market value estimated in accordance with the original provisions of FAS 123), and compensation cost for all share-based payments granted on or after Jan. 1, 2006 (based on the grant date fair market value estimated in accordance with the provisions of FAS 123R). Results for prior periods have not been restated.

TECO Energy has two share-based compensation plans (the Equity Plan and the Director Equity Plan), which are described below. The types of awards granted under these Plans include stock options, stock grants, time-vested restricted stock and performance-based restricted stock. Stock options are granted with an exercise price greater than or equal to the fair market value on the date of grant and have a 10-year contractual term. Stock options for the Director Equity Plan vest immediately and stock options for the Equity Plan have graded vesting over a three year period, with the first 33% becoming exercisable one year after the date of grant. Stock grants and time-vested restricted stock are granted at a price equal to the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Beginning in 2006, we granted time-vested restricted stock to directors that vests one-third each year. Performance-based restricted stock is granted at a price equal to the fair market value on the date of grant, with shares vesting after three years at 0% to 200% of the original grant, based on the total return of TECO Energy common stock compared to a peer group of utility stocks. Dividends are paid on all time-vested and performance-based restricted stock awards.

TECO Energy recognized total stock compensation expense for the three months ended Sep. 30, 2006 of $2.2 million pretax, or $1.4 million after-tax and, for the nine months ended Sep. 30, 2006 of $9.3 million pretax, or $5.7 million after-tax. For the nine months ended Sep. 30, 2006, cash received from option exercises under all share-based payment arrangements was $2.5 million and the aggregate intrinsic value of stock options exercised was $0.9 million. The total fair market value of awards vesting during the nine months ending Sep. 30, 2006 was $4.7 million, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Sep. 30, 2006, there was $12.8 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted average period of two years. Prior to the adoption of FAS 123R, TECO Energy presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Condensed Statement of Cash Flows. Beginning on Jan. 1, 2006, the company changed its cash flow presentation in accordance with FAS 123R, which requires the cash flows resulting from excess tax deductions on share-based payments to be classified as financing cash flows.

Previously under APB 25, the company recognized or disclosed expenses for retirement-eligible employees over the nominal vesting period. Beginning Jan. 1, 2006 under FAS 123R, any new awards made to retirement-eligible employees are recognized immediately or over the period from the grant date to the date of retirement eligibility (non-substantive approach). The impact on net income for the nine months ended Sep. 30, 2006 and 2005 of applying the nominal vesting period approach versus the non-substantive vesting period approach to awards granted prior to Jan. 1, 2006, for retirement-eligible employees would not have been material.

The fair market value of stock options is determined using the Black-Scholes valuation model and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on the Staff Accounting Bulletin No. 107 (SAB 107) simplified method of averaging

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the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.

The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.

The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant. The following table illustrates the effect on net income and earnings per share as if the company had applied the fair-value recognition provisions of FAS 123 to all share-based payments, prior to the adoption of FAS 123R.

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Pro Forma Stock-Based Compensation Expense

	Three months ended Sep. 30,					Nine months ended Sep. 30,
(millions, except per share amounts)			2006(3)		2005			2006(3)		2005
Net income from continuing operations
As reported		$	79.7	$	94.5		$	196.0	$	158.4
Add: Unearned compensation expense (1)			-		0.2			-		2.5
Less: Pro forma expense (2)			-		0.9			-		4.9
Pro forma		$	79.7	$	93.8		$	196.0	$	156.0
Net income
As reported		$	79.7	$	94.6		$	197.4	$	222.5
Add: Unearned compensation expense (1)			-		0.2			-		2.5
Less: Pro forma expense (2)			-		0.9			-		4.9
Pro forma		$	79.7	$	93.9		$	197.4	$	220.1
Net income from continuing operations – EPS, basic
As reported		$	0.38	$	0.46		$	0.94	$	0.77
Pro forma		$	0.38	$	0.45		$	0.94	$	0.76
Net income from continuing operations – EPS, diluted
As reported		$	0.38	$	0.45		$	0.94	$	0.76
Pro forma		$	0.38	$	0.44		$	0.94	$	0.75
Net income – EPS, basic
As reported		$	0.38	$	0.46		$	0.95	$	1.08
Pro forma		$	0.38	$	0.45		$	0.95	$	1.07
Net income – EPS, diluted
As reported		$	0.38	$	0.45		$	0.95	$	1.07
Pro forma		$	0.38	$	0.44		$	0.95	$	1.06
Assumptions applicable to stock options
Risk-free interest rate			4.92%		4.02%			4.92%		4.02%
Expected lives (in years)			6		7			6		7
Expected stock volatility			27.00%		34.12%			27.00%		34.12%
Dividend yield			4.66%		4.66%			4.66%		4.66%
Assumptions applicable to performance- based restricted stock
Risk-free interest rate			4.92%		3.74%			4.92%		3.74%
Expected lives (in years)			3		3			3		3
Expected stock volatility			18.22%		45.31%			18.22%		45.31%
Dividend yield			4.66%		4.49%			4.66%		4.49%

(1) Unearned compensation expense reflects the compensation expense of time-vested and performance-based restricted stock awards, after-tax.

(2) Includes compensation expense for stock options and performance-based restricted stock, determined using a fair-value based method, after-tax, plus compensation expense associated with time-vested restricted stock awards, determined based on fair market value at the time of grant, after-tax.

(3) Effective Jan. 1, 2006, stock-based compensation expense is reflected in “as reported” earnings, as a result of the adoption of FAS 123R.

Equity Plans

In April 2004, the company’s shareholders approved the 2004 Equity Incentive Plan (2004 Plan). The 2004 Plan superseded the 1996 Equity Incentive Plan (1996 Plan), and no additional grants will be made under the 1996 Plan. Under the 2004 Plan, the Compensation Committee of the Board of Directors may award stock grants, stock options and/or stock equivalents to officers, key employees and consultants of TECO Energy and its subsidiaries. The Compensation Committee has discretion to determine the terms and conditions of each award, which may be subject to conditions relating to continued employment, restrictions on transfer or performance criteria.

Under the 2004 Plan and the 1996 Plan (collectively referred to as the “Equity Plans”), 455,582 shares of restricted stock were granted and 17,962 unrestricted shares of stock were granted with weighted average fair values of $16.84 and $17.54, respectively, during the nine months ended Sep. 30, 2006. In addition, options to purchase 1.1 million shares were granted to employees during the nine months ended Sep. 30, 2006, with a weighted average fair value of $3.26. A summary of nonvested shares of restricted stock and stock options during the nine months ended Sep. 30, 2006 under the Equity Plans are shown as follows:

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Nonvested Restricted Stock and Stock Options-Equity Plans

	Nonvested Restricted Stock (1)		Nonvested Stock Options
	Number of Shares (thousands)	Weighted Avg. Grant Date Fair Value (per share)	Number of Shares (thousands)	Weighted Avg. Grant Date Fair Value (per share)
Nonvested balance at Dec. 31, 2005	801	$18.16	2,712	$2.97
Granted	456	$16.84	1,089	$3.26
Vested	(269)	$14.18	(1,501)	$2.67
Forfeited	(7)	$21.18	(26)	$2.91
Nonvested balance at Sep. 30, 2006	981	$18.62	2,274	$3.30

(1)    The weighted average remaining contractual term of restricted stock is 2 years.

Stock option transactions during the nine months ended Sep. 30, 2006 under the Equity Plans are summarized as follows:

Stock Options – Equity Plans

	Number of Shares (thousands)	Weighted Avg. Option Price (per share)	Weighted Avg. Remaining Contractual Term (years)	Aggregate Intrinsic Value (millions)
Outstanding balance at Dec. 31, 2005	9,694	$20.33
Granted	1,089	$16.30
Exercised	(211)	$11.72
Forfeited/Expired	(299)	$23.22
Outstanding balance at Sep. 30, 2006 (1)	10,273	$19.99	6	$10.3
Exercisable at Sep. 30, 2006 (2)	2,623	$12.31	7	$8.8
Available for future grant at Sep. 30, 2006	7,455
(1)    Option prices range from $11.09 to $31.58. (2)    Option prices range from $11.09 to $13.50.
Director Equity Plan
In April 1997, the company’s shareholders approved the 1997 Director Equity Plan (1997 Plan), as an amendment and restatement of the 1991 Director Stock Option Plan (1991 Plan). The 1997 Plan superseded the 1991 Plan, and no additional grants will be made under the 1991 Plan. The purpose of the 1997 Plan is to attract and retain highly qualified non-employee directors of the company and to encourage them to own shares of TECO Energy common stock. The 1997 Plan is administered by the Board of Directors, and awards may include stock grants, stock options and/or stock equivalents. Under the 1997 Plan, 25,000 shares of restricted stock were awarded for the nine month period ended Sep. 30, 2006, with a weighted average fair value of $16.30. Restricted stock transactions for the nine months ended Sep. 30, 2006 under the 1997 Plan are summarized as follows:
Nonvested Restricted Stock — Director Equity Plans
	Number of Shares (thousands)	Weighted Avg. Grant Date Fair Value (per share)
Nonvested balance at Dec. 31, 2005	-	$      -
Granted	25	$16.30
Vested	-	$      -
Forfeited	-	$      -
Nonvested balance at Sep. 30, 2006 (1)	25	$16.30

(1) The weighted average remaining contractual term is 3 years.

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Stock option transactions during the nine months ended Sep. 30, 2006 under the 1997 Plan are summarized as follows:

Stock Options – Director Equity Plans ⁽¹⁾ 

	Number of Shares (thousands)			Weighted Avg. Option Price (per share)	Weighted Avg. Remaining Contractual Term (years)		Aggregate Intrinsic Value (millions)
Outstanding balance at Dec. 31, 2005	253		$	20.93
Granted	-		$	-
Exercised	-		$	-
Expired	(20	)	$	23.63
Outstanding balance at Sep. 30, 2006 (2)	233		$	20.70	5	$	0.2
Exercisable at Sep. 30, 2006 (3)	70		$	12.92	7	$	0.2
Available for future grant at Sep. 30, 2006	189

(1)    Stock options granted under the Director Equity Plans vest immediately.

(2)    Option prices range from $11.09 to $31.58.

(3)    Option prices range from $11.09 to $15.21.

9. Other Comprehensive Income

TECO Energy reported the following other comprehensive income (loss) for the three months and nine months ended Sep. 30, 2006 and 2005, related to changes in the fair value of cash flow hedges:

Other Comprehensive Income (Loss)		Three months ended Sep. 30,									Nine months ended Sep. 30,
(millions)		Gross			Tax			Net			Gross			Tax			Net
2006
Unrealized gain (loss) on cash flow hedges	$	(1.9	)	$	(0.7	)	$	(1.2	)	$	0.1		$	-		$	0.1
Less: Gain reclassified to net income		(0.3	)		(0.1	)		(0.2	)		(0.6	)		(0.2	)		(0.4	)
Loss on cash flow hedges		(2.2	)		(0.8	)		(1.4	)		(0.5	)		(0.2	)		(0.3	)
Total other comprehensive loss	$	(2.2	)	$	(0.8	)	$	(1.4	)	$	(0.5	)	$	(0.2	)	$	(0.3	)
2005
Unrealized gain on cash flow hedges	$	1.2		$	0.4		$	0.8		$	7.2		$	3.6		$	3.6
Less: Gain reclassified to net income		(1.0	)		(0.3	)		(0.7	)		(4.6	)		(1.6	)		(3.0	)
Gain on cash flow hedges		0.2			0.1			0.1			2.6			2.0			0.6
Total other comprehensive income	$	0.2		$	0.1		$	0.1		$	2.6		$	2.0		$	0.6

Accumulated Other Comprehensive Income (Loss)
(millions)	Sep. 30, 2006		Dec. 31, 2005
Minimum pension liability adjustment (1)	$      (51.5	)	$      (51.5	)
Net unrealized gains from cash flow hedges (2)	0.1		0.4
Total accumulated other comprehensive loss	$      (51.4	)	$      (51.1	)

(1) Net of tax benefit of $32.5 million as of Sep. 30, 2006 and Dec. 31, 2005.

(2) Net of tax provision (benefit) of $0.2 million and $(0.4) million, as of Sep. 30, 2006 and Dec. 31, 2005, respectively.

10. Earnings Per Share

For each of the three and nine month periods ended Sep. 30, 2006, stock options for 7.1 million shares were excluded from the computation of diluted earnings per share due to their antidilutive effect, compared to 5.5 million shares for the same periods in 2005.

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(millions, except per share amounts)	Three months ended Sep. 30,							Nine months ended Sep. 30,
			2006			2005				2006			2005
Numerator
Net income from continuing operations, basic		$	79.7		$	94.5			$	196.0		$	158.4
Effect of contingent performance shares			-			(1.2	)			-			(1.2)
Net income from continuing operations, diluted			79.7			93.3				196.0			157.2
Discontinued operations, net of tax			-			0.1				1.4			64.1
Net income, diluted		$	79.7		$	93.4			$	197.4		$	221.3
Denominator
Average number of shares outstanding – basic			207.9			207.1				207.7			206.0
Plus:  Incremental shares for assumed conversions:
Stock options and contingent performance shares			3.7			5.5				3.7			5.4
Less: Treasury shares which could be purchased			(2.9	)		(3.3	)			(2.8	)		(3.6)
Average number of shares outstanding - diluted			208.7			209.3				208.6			207.8
Earnings per share from continuing operations
Basic		$	0.38		$	0.46			$	0.94		$	0.77
Diluted		$	0.38		$	0.45			$	0.94		$	0.76
Earnings per share from discontinued operations, net
Basic		$	-		$	0.00			$	0.01		$	0.31
Diluted		$	-		$	0.00			$	0.01		$	0.31
Earnings per share
Basic		$	0.38		$	0.46			$	0.95		$	1.08
Diluted		$	0.38		$	0.45			$	0.95		$	1.07

11. Commitments and Contingencies

Legal Contingencies

At Sep. 30, 2006, the ultimate resolution of the following specific proceedings is uncertain and no liability has been reserved or can be estimated. At this time, the ultimate outcome of these proceedings is not expected to have a material adverse effect on the company’s results of operations or financial condition.

Tampa Electric Transmission Litigation

The Shaw, Acosta and Alvarez cases, the three pending cases related to the location of the “Juneau Loop” 95-foot and 125-foot transmission structures and upgrades to the existing substation, located in or near the Egypt Lake subdivision in Tampa, Florida, remain in various stages of activity. The Shaw case is set for trial on the Jan. 3, 2007 docket, and is currently second on that docket. There were separate motions for partial summary judgment that were granted affecting eleven parcels that were not located adjacent to or in close proximity to the transmission structures. Forty parcels remain in this suit. The Judge also granted summary judgment in favor of the company on the issue of the availability of injunctive relief as a remedy. The plaintiffs have appealed this summary judgment; the appeal has been fully briefed by both sides and the appeal remains pending before the Second District Court of Appeal (2nd DCA).

The Acosta plaintiffs are made up of approximately 107 parcels. The Judge denied their renewed motion for class action status. If the 2nd DCA affirms the summary judgment in the Shaw case, the company would likely file similar motions in the Acosta case. Currently, there is no activity in the Alvarez (substation) case.

Grupo Litigation and Arbitration

On Aug. 11, 2006, TPS International Power, Inc. (TPSI) received a favorable ruling from the Bogotá Chamber of Commerce Arbitration Tribunal in the Grupo-financed arbitration on behalf of itself and the Colombian trade union regarding a 1996 transaction that was never consummated related to the potential purchase and financing of a power plant. The Tribunal found no liability on the part of TPSI and found that it had no jurisdiction over TECO Energy or any of its subsidiaries. Accordingly, it did not become necessary to address the issue of damages. TPSI had chosen not to pay its share of the arbitration fees based on its counterclaim. The tribunal ordered TPSI to pay one-half of the arbitration fees with interest on its counterclaim which amounted to $0.5 million and was paid on Sep. 6, 2006. On Aug. 31, 2006 the Union, with new Colombian counsel, filed an annulment proceeding in the Ordinary Courts citing the general statutory grounds for annulment. The Union was ordered to file its detailed petition citing the record to substantiate its claim on Oct. 12, 2006 but it failed to do so. According to Colombian procedure, the Union’s failure to file ends the process. TPSI will likely seek confirmation from the

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court’s Tribunal that the matter is closed. As previously reported, the U.S. case was decided favorably by summary judgment which was appealed and affirmed by the Second District Court of Appeal.

Class Action and Derivative Suits

Class Action Suit

After the consolidated Class Action Complaint brought by the “TECO Lead Plaintiff Group” was dismissed without prejudice by the Court on Mar. 31, 2006, plaintiffs filed their further amended complaint to which TECO Energy and defendants, Fagan and Gillette, filed their motion to dismiss on Jul. 7, 2006 based on the same ground as raised in the prior motion, failure to plead loss causation. Defendants filed a renewed motion to dismiss, and on Oct. 10, 2006, the Court granted defendant’s motion to dismiss in part, leaving only one remaining issue dealing with public statements relating to the status of the contracting plan for the approximately 6,000 MWs of merchant power then under construction in several states outside of Florida. On Oct. 30, 2006, the plaintiffs filed a Rule 54(b) motion asking the Court to enter a final judgement on the matters that were dismissed by its Oct. 10th Order. If the motion is granted, the plaintiffs would be free to appeal that portion of the Judge’s order immediately, while maintaining the balance of the action in the district Court. The defendants do not believe that this is an appropriate case for the entry of a Rule 54(b) order and intend to vigorously oppose the motion in their response to be filed by Nov. 13th as required.

Derivative Suit

On Apr. 5, 2006, the Hillsborough Circuit Court dismissed the derivative complaint filed against two named officers and the named directors without prejudice. Subsequently, the parties stipulated to dismiss with prejudice directors Penn and Whiting who were not members of the board during the relevant time period. The first status report of the Special Litigation Committee was filed on Aug. 1, 2006. The federal district Court dismissed in part the plaintiff’s complaint in the class action suit on Oct. 10, 2006, and counsel for the Special Litigation Committee has been notified.

Other Issues

From time to time, TECO Energy and its subsidiaries are involved in various other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2006, Tampa Electric Company has estimated its ultimate financial liability to be approximately $13.9 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

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Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Sep. 30, 2006 is as follows:

Letters of Credit and Guarantees

(millions)
Letters of Credit and Guarantees for the Benefit of:		2006		2007-2010		After 2010		Total	Liabilities Recognized at Sep. 30, 2006
Tampa Electric
Letters of credit	$	-	$	-	$	2.4	$	2.4	$        -
Guarantees:
Fuel purchase/energy management (1)(2)		-		-		20.0		20.0	2.6
		-		-		22.4		22.4	2.6
TECO Transport
Letters of credit		-		-		2.5		2.5	-
TECO Coal
Letters of credit		-		-		6.7		6.7	-
Guarantees: Fuel purchase related (2)		-		-		1.4		1.4	2.1
		-		-		8.1		8.1	2.1
Other subsidiaries
Guarantees:
Fuel purchase/energy management (1)(2)(3)		48.7		-		1.0		49.7	-
Total	$	48.7	$	-	$	34.0	$	82.7	$        4.7

(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2010.

(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, 2006. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) These represent guarantees of agreements between TECO Energy Source and various counterparties, primarily financial institutions, to enable the execution of transactions for hedging activities on behalf of TECO Energy, TECO Transport and TECO Coal.

Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, Tampa Electric and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sep. 30, 2006, TECO Energy, Tampa Electric and the other operating companies are in compliance with all applicable financial covenants.

12. 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 FAS No. 131, Disclosures about Segments of an Enterprise and Related Information. All significant intercompany transactions are eliminated in the consolidated condensed financial statements of TECO Energy, but are included in determining reportable segments.

The information presented in the following table excludes all discontinued operations. See Note 13, Discontinued Operations and Assets Held for Sale, for additional details of the components of discontinued operations.

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Segment Information (1)
(millions) Three months ended Sep. 30,		Tampa Electric		Peoples Gas		TECO Coal		TECO Transport			TECO (2) Guatemala			TWG (3) Merchant			Other & Eliminations			TECO Energy
2006
Revenues - external	$	601.8	$	131.3	$	137.1	$	50.8		$	1.8		$	-		$	0.1		$	922.9
Sales to affiliates		0.5		-		-		24.3			-			-			(24.8	)		-
Total revenues		602.3		131.3		137.1		75.1			1.8			-			(24.7	)		922.9
Equity earnings of unconsolidated affiliates		-		-		-		(0.4	)		14.9			-			-			14.5
Depreciation		46.6		9.1		8.7		5.5			0.1			-			0.1			70.1
Total interest charges(1)		27.4		4.0		2.8		0.7			3.8			-			31.4			70.1
Internally allocated interest (1)		-		-		2.5		(0.5	)		3.7			-			(5.7	)		-
Provision (benefit) for taxes		34.4		2.7		9.1		3.5			2.8			-			(9.8	)		42.7
Net income (loss) from continuing operations	$	57.0	$	4.2	$	21.4	$	3.4		$	9.3		$	-		$	(15.6	)	$	79.7
2005
Revenues - external	$	524.0	$	139.2	$	127.0	$	42.6		$	1.9		$	0.1		$	1.6		$	836.4
Sales to affiliates		0.6		-		-		22.2			-			-			(22.8	)		-
Total revenues		524.6		139.2		127.0		64.8			1.9			0.1			(21.2	)		836.4
Equity earnings of unconsolidated affiliates		-		-		-		(0.1	)		14.9			-			-			14.8
Depreciation		46.7		8.8		9.9		5.4			0.2			0.1			0.1			71.2
Total interest charges(1)		24.0		3.7		3.2		1.3			3.6			-			32.5			68.3
Internally allocated interest (1)		-		-		3.1		(0.2	)		3.6			-			(6.5	)		-
Provision (benefit) for taxes		38.1		2.6		16.5		(1.7	)		(3.7	)		(0.2	)		(12.4	)		39.2
Net income (loss) from continuing operations	$	62.7	$	4.1	$	34.6	$	0.9		$	14.0		$	(0.3	)	$	(21.5	)	$	94.5
(millions) Nine months ended Sep. 30,		Tampa Electric		Peoples Gas		TECO Coal		TECO Transport			TECO (2) Guatemala			TWG (3) Merchant			Other & Eliminations			TECO Energy
2006
Revenues - external	$	1,590.6	$	455.0	$	421.9	$	148.6		$	5.6		$	-		$	0.2		$	2,621.9
Sales to affiliates		1.7		-		-		79.0			-			-			(80.7	)		-
Total revenues		1,592.3		455.0		421.9		227.6			5.6			-			(80.5	)		2,621.9
Equity earnings of unconsolidated affiliates		-		-		-		(0.2	)		43.1			-			-			42.9
Depreciation		139.7		27.3		26.9		16.5			0.4			-			0.2			211.0
Total interest charges(1)		80.7		11.8		7.8		3.3			11.2			-			94.3			209.1
Internally allocated interest (1)		-		-		7.3		(1.0	)		10.9			-			(17.2	)		-
Provision (benefit) for taxes		69.3		14.3		22.1		8.2			5.2			-			(26.4	)		92.7
Net income (loss) from continuing operations	$	116.5	$	22.7	$	59.5	$	15.0		$	26.6		$	-		$	(44.3	)	$	196.0
2005
Revenues - external	$	1,328.1	$	394.9	$	365.0	$	136.7		$	5.8		$	0.5		$	9.1		$	2,240.1
Sales to affiliates		2.0		-		-		66.0			-			-			(68.0	)		-
Total revenues		1,330.1		394.9		365.0		202.7			5.8			0.5			(58.9	)		2,240.1
Equity earnings of unconsolidated affiliates		-		-		-		(0.1	)		43.9			-			(0.1	)		43.7
Depreciation		139.9		26.1		27.8		16.2			0.5			0.4			0.3			211.2
Total interest charges(1)		72.1		11.3		9.6		3.9			10.7			10.2			102.4			220.2
Internally allocated interest (1)		-		-		9.4		(0.4	)		10.6			10.2			(29.8	)		-
Provision (benefit) for taxes		74.6		14.4		50.9		2.5			(2.8	)		(8.2	)		(60.4	)		71.0
Net income (loss) from continuing operations	$	123.5	$	22.9	$	90.5	$	10.3		$	33.4		$	(14.6	)	$	(107.6	)	$	158.4

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(millions)		Tampa Electric		Peoples Gas		TECO Coal		TECO Transport		TECO Guatemala		TWG (3) Merchant		Other & Eliminations		TECO Energy
At Sep. 30, 2006
Goodwill	$	-	$	-	$	-	$	-	$	59.4	$	-	$	-	$	59.4
Investment in unconsolidated affiliates		-		-		-		3.0		264.4		-		20.2		287.6
Other non-current investments		-		-		-				-		-		8.0		8.0
Total Assets	$	4,669.7	$	711.6	$	408.8	$	313.4	$	420.2	$	-	$	874.7	$	7,398.4
At Dec. 31, 2005
Goodwill	$	-	$	-	$	-	$	-	$	59.4	$	-	$	-	$	59.4
Investment in unconsolidated affiliates		-		-				2.9		274.0				20.2		297.1
Other non-current investments		-		-				-		-				8.0		8.0
Total Assets	$	4,554.0	$	721.5	$	385.6	$	322.4	$	408.4	$	233.0	$	545.2	$	7,170.1

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2006 and 2005 were at pretax rates of 7.5% and 8%, respectively, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) Revenues are exclusive of entities deconsolidated as a result of FIN 46R. Total revenues for unconsolidated affiliates, attributable to TECO Guatemala based on ownership percentages, were $26.1 million and $25.8 million for the three months ended Sep. 30, 2006 and 2005, respectively, and $76.8 million and $73.1 million for the nine months ended Sep. 30, 2006 and 2005, respectively.

(3) Effective with 2006 results, only historical data is presented for TWG Merchant as all merchant assets have been divested. Any residual amounts from 2006 are included in “Other & Eliminations.”

13. Discontinued Operations and Assets Held for Sale

Union and Gila River Project Companies

On Jun. 1, 2005, subsidiaries of the company completed the sale and transfer of the Union and Gila River project companies. As a result of the transaction, the company recorded a non-cash, pretax gain of $117.7 million ($76.5 million after-tax), which is reflected in discontinued operations for the nine months ended Sep. 30, 2005.

The following table provides selected components of discontinued operations for the Union and Gila River project companies:

Components of income from discontinued operations – Union and Gila River Project Companies

(millions)	Three months ended Sep. 30,						Nine months ended Sep. 30,
			2006		2005				2006		2005
Revenues		$	-	$	-			$	-	$	109.1
Income (loss) from operations			-		-				-		(19.4	)
Gain on sale before tax			-		-				-		117.7
Income (loss) before provision for income taxes			-		-				-		90.0
Provision (benefit) for income taxes			-		(0.7	)			-		24.9
Net income (loss) from discontinued operations		$	-	$	0.7			$	-	$	65.1

Other discontinued operations

Components of income from other discontinued operations include: TECO Thermal (sold in May 2006), Commonwealth Chesapeake Company, LLC (sold in April 2005), and BCH Mechanical (sold in January 2005). For all periods presented, the results from operations of each of these entities are presented as discontinued operations on the income statement. The following table provides selected components of other discontinued operations:

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Components of income from discontinued operations-Other

(millions)	Three months ended Sep. 30,						Nine months ended Sep. 30,
			2006		2005				2006		2005
Revenues		$	—	$	0.7			$	0.8	$	9.9
Income (loss) from operations			—		—				1.5		(0.2	)
(Loss) gain on sale before tax			—		(2.1	)			0.8		(2.1	)
Income (loss) before provision for income taxes			—		(2.0	)			2.3		(1.8	)
Provision (benefit) for income taxes			—		(1.4	)			0.9		(0.8	)
Net income (loss) from discontinued operations		$	—	$	(0.6	)		$	1.4	$	(1.0	)

At Dec. 31, 2005, assets and liabilities held for sale included TECO Thermal, an investment of TECO Solutions. In May of 2006, TECO Solutions sold the assets of TECO Thermal for $8.0 million. This transaction resulted in a net after-tax gain of $0.5 million. The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items for all transactions described above:

Assets held for sale - Other

(millions)	Sep. 30, 2006			Dec. 31, 2005
Net property, plant and equipment		$	—		$	6.4
Other non-current assets			—			1.6
Total assets held for sale		$	—		$	8.0
Liabilities associated with assets held for sale
(millions)	Sep. 30, 2006			Dec. 31, 2005
Current liabilities		$	—		$	1.8
Total liabilities associated with assets held for sale		$	—		$	1.8

14. Derivatives and Hedging

At Sep. 30, 2006, TECO Energy and its affiliates had total derivative assets and liabilities (current and non-current) of $6.5 million and $79.4 million, respectively, compared to total derivative assets and liabilities (current and non-current) of $68.9 million and $0.3 million, respectively, at Dec. 31, 2005. The decrease in net derivative assets and increase in net derivative liabilities primarily reflects the changes in natural gas prices. At Sep. 30, 2006 and Dec. 31, 2005, accumulated other comprehensive income (AOCI) included after-tax gains of $0.1 million and $0.4 million, respectively, representing the fair value of cash flow hedges whose transactions will occur in the future. Amounts recorded in AOCI reflect the estimated fair value of derivative instruments designated as hedges, based on market prices as of the balance sheet date. These amounts are expected to fluctuate with movements in market prices and may or may not be realized as a gain upon future reclassification from AOCI.

For the three months and nine months ended Sep. 30, 2006, TECO Energy and its affiliates reclassified amounts from AOCI and recognized net pretax gains of $0.3 million and $0.6 million, respectively, compared to net pretax gains of $1.0 million and $4.6 million, respectively, for the same periods in 2005. Amounts reclassified from AOCI were primarily related to cash flow hedges of physical purchases of fuel oil. For these types of hedge relationships, the loss on the derivative reclassified from AOCI to earnings is offset by the reduced expense arising from lower prices paid for spot purchases of fuel oil. Conversely, reclassification of a gain from AOCI to earnings is offset by the increased cost of spot purchases of natural gas and fuel oil.

As a result of applying the provisions of FAS 71, the changes in value of derivatives of Tampa Electric and PGS are recorded as regulatory assets or liabilities to reflect the impact of the fuel recovery clause on the risks of hedging activities (see Note 3, Regulatory). Based on the fair value of cash flow hedges at Sep. 30, 2006, net pretax losses of $72.7 million are expected to be reclassified from regulatory assets or liabilities, and pretax gains of $0.1 million are expected to be reversed from AOCI, to the Consolidated Condensed Statements of Income, within the next twelve months. However, these gains and other future reclassifications from regulatory assets and AOCI will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2008.

For the three months and nine months ended Sep. 30, 2006, the company recognized a pretax loss of $7.0 million and a gain of $0.7 million, respectively, relating to derivatives that were not designated as either a cash flow or fair value hedge, compared to pretax gains of $6.3 million and $2.7 million for the three months and nine months ended Sep. 30, 2005, respectively.

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15. Mergers, Acquisitions and Dispositions

Sale of Steam Turbines

On Jul. 14, 2006, the company sold a steam turbine generator located in Maricopa County, Arizona to a third party for a net after-tax gain of $2.6 million.

Sale of TPS McAdams, LLC

On Jun. 23, 2006, TPS McAdams, LLC, an indirect subsidiary of TECO Energy, Inc., was sold to Von Boyett Corporation for $1.2 million in cash. The assets of TPS McAdams, LLC had been impaired in 2004 to an estimate of salvage value, which included allowances for potential future site restoration costs. In the first quarter of 2006, TPS McAdams, LLC sold the combustion turbines at the site to Tampa Electric Company at the book value contemplated in the salvage estimate. The sale and transfer of TPS McAdams, LLC, including its remaining assets and any potential site restoration costs at terms better than contemplated in the salvage estimate, resulted in a pretax gain of $10.7 million ($8.1 million after-tax) being recognized in continuing operations.

16. Subsequent Events

In October 2006 the company entered into hedge agreements to purchase 8.0 million barrels of crude oil call spreads at a total premium of $7.8 million. The purpose of the call spreads is to protect the breakeven point of synthetic fuel production costs and the related synthetic fuel benefits for the first nine months of 2007.

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TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company as of Sep. 30, 2006 and Dec. 31, 2005, and the results of operations and cash flows for the periods ended Sep. 30, 2006 and 2005. The results of operations for the three month and nine month periods ended Sep. 30, 2006 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2006. References should be made to the explanatory notes affecting the consolidated condensed financial statements contained in Tampa Electric Company’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and to the notes on pages 32 to 37 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sep. 30, 2006 and Dec. 31, 2005	27-28
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and nine month periods ended Sep. 30, 2006 and 2005	29-30
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sep. 30, 2006 and 2005	31
Notes to Consolidated Condensed Financial Statements	32-37

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)		Sep. 30, 2006			Dec. 31,   2005
Property, plant and equipment
Utility plant in service
Electric	$	4,951.0		$	4,889.0
Gas		864.1			839.6
Construction work in progress		292.5			164.0
Property, plant and equipment, at original costs		6,107.6			5,892.6
Accumulated depreciation		(1,731.3	)		(1,658.7)
		4,376.3			4,233.9
Other property		8.4			7.4
Total property, plant and equipment (net)		4,384.7			4,241.3
Current assets
Cash and cash equivalents		40.2			17.4
Receivables, less allowance for uncollectibles of $2.7 and $1.3 at Sep. 30, 2006 and Dec. 31, 2005, respectively		262.7			232.5
Inventories
Fuel, at average cost		60.6			68.3
Materials and supplies		50.9			45.5
Current regulatory assets		278.9			296.3
Current derivative assets		—			58.2
Taxes receivable		—			35.1
Prepayments and other current assets		14.2			7.9
Total current assets		707.5			761.2
Deferred debits
Unamortized debt expense		21.5			17.4
Long-term regulatory assets		101.9			101.1
Long-term derivative assets		0.2			4.9
Other		22.0			30.3
Total deferred debits		145.6			153.7
Total assets	$	5,237.8		$	5,156.2

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)		Sep. 30, 2006		Dec. 31, 2005
Capital
Common stock	$	1,376.8	$	1,376.8
Retained earnings		320.3		288.7
Total capital		1,697.1		1,665.5
Long-term debt, less amount due within one year		1,601.3		1,508.5
Total capitalization		3,298.4		3,174.0
Current liabilities
Long-term debt due within one year		156.1		5.9
Notes payable		—		215.0
Accounts payable		198.1		231.2
Customer deposits		125.7		115.2
Current regulatory liabilities		116.6		146.8
Current derivative liabilities		72.7		0.3
Current deferred income taxes		33.2		116.8
Interest accrued		34.6		25.5
Taxes accrued		49.9		15.2
Total current liabilities		786.9		871.9
Deferred credits
Non-current deferred income taxes		386.5		372.9
Investment tax credits		15.2		17.1
Long-term derivative liabilities		6.7		—
Long-term regulatory liabilities		560.5		543.1
Other		183.6		177.2
Total deferred credits		1,152.5		1,110.3
Total liabilities and capital	$	5,237.8	$	5,156.2

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

(millions)	Three months ended Sep. 30,
			2006			2005
Revenues
Electric (includes franchise fees and gross receipts taxes of $23.7 in 2006 and $21.2 in 2005)		$	602.2		$	524.4
Gas (includes franchise fees and gross receipts taxes of $4.6 in 2006 and $3.0 in 2005)			131.3			139.2
Total revenues			733.5			663.6
Expenses
Operations
Fuel			250.6			142.6
Purchased power			79.4			104.6
Cost of natural gas sold			84.4			96.7
Other			70.8			68.4
Maintenance			23.7			22.5
Depreciation			55.7			55.5
Taxes, federal and state income			36.4			40.3
Taxes, other than income			44.6			40.5
Total expenses			645.6			571.1
Income from operations			87.9			92.5
Other income (expense)
Allowance for other funds used during construction			0.8			—
Taxes, non-utility federal and state			(0.7	)		(0.4	)
Other income, net			4.6			2.4
Total other income			4.7			2.0
Interest charges
Interest on long-term debt			28.0			24.5
Other interest			3.8			3.2
Allowance for borrowed funds used during construction			(0.4	)		—
Total interest charges			31.4			27.7
Net income		$	61.2		$	66.8
Comprehensive income		$	61.2		$	66.8

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

(millions)	Nine months ended Sep. 30,
			2006			2005
Revenues
Electric (includes franchise fees and gross receipts taxes of $61.7 in 2006 and $53.4 in 2005)		$	1,591.9		$	1,329.6
Gas (includes franchise fees and gross receipts taxes of $17.4 in 2006 and $12.1 in 2005)			455.0			394.9
Total revenues			2,046.9			1,724.5
Expenses
Operations
Fuel			688.6			428.8
Purchased power			169.7			190.4
Cost of natural gas sold			295.3			246.6
Other			213.4			194.6
Maintenance			80.4			67.2
Depreciation			167.0			166.0
Taxes, federal and state income			81.9			88.1
Taxes, other than income			131.5			116.1
Total expenses			1,827.8			1,497.8
Income from operations			219.1			226.7
Other income (expense)
Allowance for other funds used during construction			1.4			—
Taxes, non-utility federal and state			(1.7	)		(0.9	)
Other income, net			12.9			4.0
Total other income			12.6			3.1
Interest charges
Interest on long-term debt			78.7			73.8
Other interest			14.4			9.6
Allowance for borrowed funds used during construction			(0.6	)		—
Total interest charges			92.5			83.4
Net income		$	139.2		$	146.4
Comprehensive income		$	139.2		$	146.4

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

(millions)	Nine months ended Sep. 30,
			2006			2005
Cash flows from operating activities
Net income		$	139.2		$	146.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation			167.0			166.0
Deferred income taxes			(14.5	)		23.8
Investment tax credits, net			(1.9	)		(2.0	)
Allowance for funds used during construction			(2.0	)		—
Deferred recovery clause			62.1			(61.0	)
Receivables, less allowance for uncollectibles			(27.2	)		(53.6	)
Inventories			2.3			(26.1	)
Prepayments			(6.3	)		—
Taxes accrued			70.1			96.7
Interest accrued			9.1			4.5
Accounts payable			(33.9	)		78.4
Other regulatory assets and liabilities			(2.8	)		0.5
Other			35.2			13.9
Cash flows from operating activities			396.4			387.5
Cash flows from investing activities
Capital expenditures			(287.2	)		(170.5	)
Allowance for funds used during construction			2.0			—
Other			(1.4	)		5.2
Cash flows used in investing activities			(286.6	)		(165.3	)
Cash flows from financing activities
Proceeds from long-term debt			327.4			—
Repayment of long-term debt			(91.8	)		(5.5	)
Decrease in short-term debt			(215.0	)		(95.0	)
Dividends			(107.6	)		(104.2	)
Cash flows used in financing activities			(87.0	)		(204.7	)
Net increase in cash and cash equivalents			22.8			17.5
Cash and cash equivalents at beginning of period			17.4			1.3
Cash and cash equivalents at end of period		$	40.2		$	18.8

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies are as follows:

Principles of Consolidation and Basis of Presentation

Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS). All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of Tampa Electric Company and subsidiaries as of Sep. 30, 2006 and Dec. 31, 2005, and the results of their operations and cash flows for the periods ended Sep. 30, 2006 and 2005. The results of operations for the three month and nine month periods ended Sep. 30, 2006 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2006.

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.

Revenues

As of Sep. 30, 2006 and Dec. 31, 2005, unbilled revenues of $50.9 million and $52.3 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Purchased Power

Tampa Electric purchases power on a regular basis to meet the needs of its customers. Tampa Electric purchased power from entities not affiliated with TECO Energy at a cost of $79.4 million and $169.7 million, respectively, for the three months and nine months ended Sep. 30, 2006, compared to $104.6 million and $190.4 million, respectively, for the three months and nine months ended Sep. 30, 2005. Prudently incurred purchased power costs at Tampa Electric are recoverable through Florida Public Service Commission (FPSC)-approved cost recovery clauses.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities (Tampa Electric and Peoples Gas) are allowed to recover from customers certain costs, including franchisee fees and gross receipts taxes, through prices approved by the FPSC. These amounts totaled $28.3 million and $79.1 million, respectively, for the three months and nine months ended Sep. 30, 2006, compared to $24.2 million and $65.5 million, respectively, for the three months and nine months ended Sep. 30, 2005. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income.” These totaled $28.3 million and $79.0 million, respectively, for the three months and nine months ended Sep. 30, 2006, compared to $24.3 million and $65.4 million, respectively, for the three months and nine months ended Sep. 30, 2005.

2. Regulatory

Cost Recovery – Tampa Electric and Peoples Gas

Tampa Electric and Peoples Gas recover the cost of fuel, purchased power, eligible environmental expenditures, and conservation through cost recovery clauses that are adjusted on an annual basis. As part of the regulatory process, it is reasonably likely that third parties may intervene in various matters related to fuel, purchased power, environmental and conservation cost recovery.

SO₂ Emission Allowances

The Clean Air Act Amendments of 1990 established SO₂ allowances to manage the achievement of SO₂ emissions requirements. The legislation also established a market-based SO₂ allowance trading component.

An allowance authorizes a utility to emit one ton of SO₂ during a given year. The Environmental Protection Agency allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use currently or in future years. In addition, the EPA withholds a small percentage of the annual SO₂ allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause.

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Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO₂ allowances unneeded and sold in 2006 resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.

In January 2006, Tampa Electric sold approximately 40,000 allowances, resulting in proceeds of $40.8 million, the majority of which is included as a cost recovery clause regulatory liability as of Sep. 30, 2006. During the quarter ended Sep. 30, 2006, another 4,500 allowances were sold resulting in proceeds of $2.9 million compared to 100,000 allowances and $79.7 million in proceeds for the third quarter of 2005. Proceeds for the first two quarters of 2005 were immaterial.

Regulatory Assets and Liabilities

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

Tampa Electric and PGS apply the accounting treatment permitted by Financial Accounting Stantards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. 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 deferral of costs as regulatory assets, when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Sep. 30, 2006 and Dec. 31, 2005 are presented in the following table:

Regulatory Assets and Liabilities

(millions)		Sep. 30, 2006		Dec. 31, 2005
Regulatory assets:
Regulatory tax asset (1)	$	52.4	$	79.5
Other:
Cost recovery clauses		276.9		264.1
Deferred bond refinancing costs (2)		27.6		28.8
Environmental remediation		13.9		14.2
Competitive rate adjustment		5.2		5.6
Other		4.8		5.2
		328.4		317.9
Total regulatory assets		380.8		397.4
Less current portion		278.9		296.3
Long-term regulatory assets	$	101.9	$	101.1
Regulatory liabilities:
Regulatory tax liability (1)	$	51.9	$	23.4
Other:
Deferred allowance auction credits		0.9		1.3
Cost recovery clauses		69.9		136.9
Environmental remediation		13.9		14.2
Deferred gain on property sales (3)		7.3		7.7
Accumulated cost of removal		517.8		493.8
Transmission and delivery storm reserve		15.3		12.5
Other		0.1		0.1
		625.2		666.5
Total regulatory liabilities		677.1		689.9
Less current portion		116.6		146.8
Long-term regulatory liabilities	$	560.5	$	543.1

(1) Related primarily to plant life and derivative positions.

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

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

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3. Income Tax Expense

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 rates for the nine months ended Sep. 30, 2006 differ from the statutory rate principally due to state income taxes and amortization of investment tax credits.

4. Employee Postretirement Benefits

Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy. Effective Jan. 1, 2004, Tampa Electric Company adopted FAS 132R (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB Statements No. 87, 88 and 106, with no material effect. No significant changes have been made to these benefit plans since Dec. 31, 2003.

Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. Tampa Electric Company’s portion of the net pension expense for the three months and nine months ended Sep. 30, 2006 and 2005, respectively, was $3.3 million, $10.0 million, $2.4 million and $7.3 million for pension benefits, and $3.5 million, $10.5 million, $3.4 million and $10.1 million for other postretirement benefits.

For the fiscal 2006 plan year, TECO Energy assumed an expected long-term return on plan assets of 8.5% and a discount rate of 5.5% at its Sep. 30, 2005 measurement date. TECO Energy’s policy is to fund the pension plan based on the amount determined by TECO Energy’s actuaries within the guidelines set by ERISA. In January 2006, TECO Energy contributed $6.3 million to the pension plan, of which Tampa Electric Company’s portion was $4.3 million. Although TECO Energy has not expressed the intent to make additional contributions to the pension plan in 2006, it may elect to make such additional contributions within the ERISA guidelines.

5. Short-term Debt

At Sep. 30, 2006 and Dec. 31, 2005, the following credit facilities and related borrowings existed:

Credit Facilities		Sep. 30, 2006				Dec. 31, 2005
(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	$      —	$      —	$	325.0	$        120.0	$      —
1-year accounts receivable facility		150.0	—	—		150.0	95.0	—
Total	$	475.0	$      —	$      —	$	475.0	$        215.0	$      —

(1) Borrowings outstanding are reported as notes payable.

These credit facilities require commitment fees ranging from 12.5 to 17.5 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2005 was 4.45%. There were no outstanding balances under the credit facilities at Sep. 30, 2006.

6. Long-Term Debt

Issuance of Tampa Electric Company 6.55% Notes due 2036

On May 12, 2006, Tampa Electric Company issued $250 million aggregate principal amount of 6.55% Notes due May 15, 2036. The 6.55% Notes were sold at 99.375% of par to yield 6.598%. The offering resulted in net proceeds to Tampa Electric Company (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $246.0 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Tampa Electric Company may redeem all or any part of the 6.55% 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 6.55% Notes to be redeemed or (ii) the present value of the remaining payments of principal and interest on the 6.55% Notes to be redeemed, discounted at an applicable treasury rate (as defined in the applicable indenture), plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.

Current portions of long-term debt

Long-term debt classified as current liabilities at Sep. 30, 2006 includes the Tampa Electric Company and Peoples Gas 5.375% notes due in August 2007.

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7. Commitments and Contingencies

Legal Contingencies

At Sep. 30, 2006, the ultimate resolution of the following proceeding is uncertain and no liability has been reserved or can be estimated. At this time, the ultimate outcome of this proceeding is not expected to have a material adverse effect on the company’s results of operations or financial condition.

Tampa Electric Transmission Litigation

The Shaw, Acosta and Alvarez cases, the three pending cases related to the location of the “Juneau Loop” 95-foot and 125-foot transmission structures and upgrades to the existing substation, located in or near the Egypt Lake subdivision in Tampa, Florida, remain in various stages of activity. The Shaw case is set for trial in the Jan. 3, 2007 docket, and is currently second on that docket. There were separate motions for partial summary judgment that were granted affecting eleven parcels that were not located adjacent to or in close proximity to the transmission structures. Forty parcels remain in this suit. The Judge also granted summary judgment in favor of the company on the issue of the availability of injunctive relief as a remedy. The plaintiffs have appealed this summary judgment; the appeal has been fully briefed by both sides and the appeal remains pending before the Second District Court of Appeal (2nd DCA).

The Acosta plaintiffs are made up of approximately 107 parcels. The Judge denied their renewed motion for class action status. If the 2nd DCA affirms the summary judgment in the Shaw case, the company would likely file similar motions in the Acosta case. Currently, there is no activity in the Alvarez (substation) case.

Other Issues

From time to time Tampa Electric Company and its subsidiaries are involved in various other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.

Superfund and Former Manufactured Gas Plant Sites

Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sep. 30, 2006, Tampa Electric Company has estimated its ultimate financial liability to be approximately $13.9 million and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Guarantees and Letters of Credit

At Sep. 30, 2006, Tampa Electric Company was not obligated under guarantees or letters of credit for the benefit of third parties, including entities under common control. At Sep. 30, 2006, TECO Energy had provided a fuel purchase guarantee on behalf of Tampa Electric Company and had outstanding letters of credit on behalf of Tampa Electric Company in the face amount of $20.0 million and $2.4 million, respectively.

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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, 2006, Tampa Electric Company was in compliance with applicable financial covenants.

8. Related Parties

In January 2006, Tampa Electric purchased two 150-megawatt combustion turbines and other ancillary equipment from TPS McAdams for $20.6 million. This has been included in capital expenditures on the Tampa Electric Company Consolidated Condensed Statements of Cash Flows for the period ended Sep. 30, 2006.

In October 2003, Tampa Electric signed a five-year contract renewal with an affiliate company, TECO Transport, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008. For the three and nine months ended September 30, 2006, Tampa Electric paid TECO Transport $24.3 million and $79.0 million, respectively.

9. Segment Information

(millions) Three months ended Sep. 30,		Tampa Electric		Peoples(1) Gas		Other & Eliminations			Tampa Electric Company
2006
Revenues - external	$	601.8	$	131.3	$	(0.1	)	$	733.0
Sales to affiliates		0.5		—		—			0.5
Total revenues		602.3		131.3		(0.1	)		733.5
Depreciation		46.6		9.1		—			55.7
Total interest charges		27.4		4.0		—			31.4
Provision for taxes		34.4		2.7		—			37.1
Net Income	$	57.0	$	4.2		—		$	61.2
2005
Revenues - external	$	524.0	$	139.2	$	—		$	663.2
Sales to affiliates		0.6		—		(0.2	)		0.4
Total revenues		524.6		139.2		(0.2	)		663.6
Depreciation		46.7		8.8		—			55.5
Total interest charges		24.0		3.7		—			27.7
Provision for taxes		38.1		2.6		—			40.7
Net Income	$	62.7	$	4.1		—		$	66.8
Nine months ended Sep. 30,
2006
Revenues - external	$	1,590.6	$	455.0	$	(0.4	)	$	2,045.2
Sales to affiliates		1.7		—		—			1.7
Total revenues		1,592.3		455.0		(0.4	)		2,046.9
Depreciation		139.7		27.3		—			167.0
Total interest charges		80.7		11.8		—			92.5
Provision for taxes		69.3		14.3		—			83.6
Net Income	$	116.5	$	22.7		—		$	139.2
Total assets at Sep. 30, 2006	$	4,669.7	$	711.6	$	(143.5	)	$	5,237.8
2005
Revenues - external	$	1,328.1	$	394.9	$	—		$	1,723.0
Sales to affiliates		2.0		—		(0.5	)		1.5
Total revenues		1,330.1		394.9		(0.5	)		1,724.5
Depreciation		139.9		26.1		—			166.0
Total interest charges		72.1		11.3		—			83.4
Provision for taxes		74.6		14.4		—			89.0
Net Income	$	123.5	$	22.9		—		$	146.4
Total assets at Dec. 31, 2005	$	4,554.0	$	721.5	$	(119.3	)	$	5,156.2

(1) Results for Peoples Gas in 2006 include certain other non-regulatory subsidiaries.

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10. Derivatives and Hedging

At Sep. 30, 2006 and Dec. 31, 2005, the company had net derivative (liabilities) assets of $(79.2) million and $62.8 million, respectively. The decrease in net derivative assets and the increase in net derivative liabilities reflects the changes in natural gas prices. As a result of applying the provisions of FAS 71, the changes in value of these derivatives are recorded as regulatory assets or liabilities as of Sep. 30, 2006 and Dec. 31, 2005, respectively, to reflect the impact of the fuel recovery clause on the risks of hedging activities.

Based on the fair values of derivatives at Sep. 30, 2006, net pretax losses of $72.7 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months. However, these gains and other future reclassifications from regulatory assets or liabilities will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2008.

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

This Form 10-Q contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Form 10-Q. Factors that could impact actual results include: unforeseen regulatory actions by federal, state or local authorities that could impact operations; an adverse outcome in the previously disclosed litigation; additional debt extinguishment costs or premiums associated with the early retirement of TECO Energy debt; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; oil prices in excess of the annual reference price, which would reduce or eliminate synthetic fuel tax credits and reduce or eliminate the earnings and cash flow from the sale of membership interests in the synthetic fuel production facilities at TECO Coal; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; general economic conditions in Tampa Electric’s service area affecting energy sales; economic conditions, both national and international, affecting the demand for TECO Transport’s waterborne transportation services; weather variations affecting sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions or hurricanes, which are common during the summer months; commodity price and operating cost changes affecting the margins at TECO Coal and TECO Transport, fuel cost recoveries and cash at Tampa Electric or natural gas demand at Peoples Gas; the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures; changes in electric tariffs or contract terms affecting TECO Guatemala’s operations; and TECO Coal’s exposure to any changes in law, regulation or administration that would retroactively impact the federal income tax credits from the production of synthetic fuel or the related benefits that have been recognized to date. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2005.

TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management’s Discussion and Analysis, “we,” “our,” “ours” and “us” refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.

Earnings Summary - Unaudited

	Three months ended Sep. 30,					Nine months ended Sep. 30,
(millions, except per share amounts)			2006		2005			2006		2005
Consolidated revenues		$	922.9	$	836.4		$	2,621.9	$	2,240.1
Net income from continuing operations		$	79.7	$	94.5		$	196.0	$	158.4
Discontinued operations			—		0.1			1.4		64.1
Net income		$	79.7	$	94.6		$	197.4	$	222.5
Average common shares outstanding
Basic			207.9		207.1			207.7		206.0
Diluted			208.7		209.3			208.6		207.8
Earnings per share - basic
Continuing operations		$	0.38	$	0.46		$	0.94	$	0.77
Discontinued operations			—		—			0.01		0.31
Earnings per share - basic		$	0.38	$	0.46		$	0.95	$	1.08
Earnings per share - diluted
Continuing operations		$	0.38	$	0.45		$	0.94	$	0.76
Discontinued operations			—		—			0.01		0.31
Earnings per share - diluted		$	0.38	$	0.45		$	0.95	$	1.07

Operating Results

Three Months Ended Sep. 30, 2006:

Third quarter net income was $79.7 million, compared to $94.6 million in the third quarter of 2005. Earnings per share for the quarter were $0.38, compared to $0.46 per share in the third quarter of 2005. Third quarter 2006 net income includes a $2.6 million after-tax gain on the sale of an unused steam turbine and a $0.2 million after-tax charge related to ongoing repairs for Hurricane Katrina related damages at TECO Bulk Terminal in Louisiana.

Nine Months Ended Sep. 30, 2006:

Year-to-date net income and earnings per share were $197.4 million, or $0.95 per share, in 2006, compared to $222.5 million, or $1.08 per share, in the same period in 2005. Year-to-date net income and earnings per share from continuing operations were $196.0 million, or $0.94 per share, in 2006, compared to $158.4 million, or $0.77 per share, in the same period in 2005. In 2005, results from continuing operations included a $45 million after-tax, or $0.22 per share, charge

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primarily for early debt retirement.

Net income for the third quarter reflected a $13.8 million, or $0.06 per share, net benefit to earnings from the production of synthetic fuel and the sale of the ownership interests in the synthetic fuel production facilities, compared to $24.7 million, or $0.12 per share, in the third quarter of 2005. Year-to-date net income reflects a $23.1 million, or $0.11 per share, benefit to earnings from synthetic fuel production, compared to $68.5 million, or $0.33 per share, in the 2005 period. Results for the 2006 third quarter and year-to-date periods reflected an estimated 39% reduction in synthetic fuel-related benefits due to estimated average annual oil prices above the phase-out threshold level at Sep. 30, compared to no reduction of benefits in 2005. The potential benefits from the production of synthetic fuel are reduced by oil prices that are above the threshold level for the phase-out of the tax credits from synthetic fuel.

Tampa Electric Company – Electric division (Tampa Electric)

Net income for the third quarter was $57.0 million, compared with $62.7 million for the same period in 2005. Results for the quarter reflect 2.8% average customer growth and increased income from sales to other utilities, but lower retail energy sales. Operations and maintenance expense increased, as expected, driven by additional spending on system reliability and coal-fired unit performance improvements and other higher costs.

Tampa Electric’s retail energy sales decreased 2.6% in the third quarter as strong customer growth was offset by more normal weather than the same period in 2005. Total heating and cooling degree-days for the Tampa area in the third quarter were only 1% below normal, but 8% below actual levels in 2005, when total degree days were almost 7% above normal.

Year-to-date net income was $116.5 million, compared to $123.5 million in the 2005 period. These results reflect retail energy sales that were almost 1.0% higher and off-system energy sales that were almost 11.0% higher than in the same period last year. The positive effects of 2.9% average customer growth and actual heating and cooling degree days 1% above 2005, but more than 4% below normal, were offset by higher operating and maintenance expenses. Non-fuel operations and maintenance expense increased, as expected, primarily due to additional spending on system reliability and coal-fired unit performance improvements and other higher costs. A summary of Tampa Electric’s operating statistics for the three months and nine months ended Sep. 30, 2006 and 2005 follows:

(in millions, except average customers)		Operating Revenues						Kilowatt-hour sales
		2006		2005		% Change		2006	2005	% Change
Three months ended Sep. 30,
Residential	$	295.9	$	270.7		9.3		2,733.2	2,813.5	(2.9	)
Commercial		167.6		147.7		13.5		1,787.9	1,811.0	(1.3	)
Industrial – Phosphate		16.1		16.3		(1.3	)	247.0	284.5	(13.2	)
Industrial – Other		29.5		25.7		14.8		352.4	352.8	(0.1	)
Other sales of electricity		43.7		38.7		12.9		456.6	464.4	(1.7	)
		552.8		499.1		10.8		5,577.1	5,726.2	(2.6	)
Deferred and other revenues(1)		19.4		(78.9	)	*		—	—	—
Sales for resale		16.7		14.4		16.0		206.0	232.7	(11.5	)
Other operating revenue		10.5		10.3		1.0		—	—	—
SO2 allowance sales		2.9		79.7		(96.4	)	—	—	—
	$	602.3	$	524.6		14.8		5,783.1	5,958.9	(3.0	)
Average customers (thousands)		654.8		637.1		2.8
Retail output to line (kilowatt hours)								5,908.6	6,058.1	(2.5	)
Nine months ended Sep. 30,
Residential	$	735.4	$	640.5		14.8		6,715.5	6,552.1	2.5
Commercial		452.8		388.0		16.7		4,783.5	4,688.1	2.0
Industrial – Phosphate		45.0		49.4		(8.9	)	684.6	896.7	(23.7	)
Industrial – Other		85.0		72.2		17.7		1,014.5	996.8	1.8
Other sales of electricity		120.7		104.5		15.5		1,242.4	1,223.5	1.5
		1,438.9		1,254.6		14.7		14,440.5	14,357.2	0.6
Deferred and other revenues(1)		23.7		(72.0	)	*		—	—	—
Sales for resale		55.1		38.9		41.6		676.3	610.2	10.8
Other operating revenue		29.6		28.9		2.4		—	—	—
SO2 allowance sales		45.0		79.7		(43.5	)	—	—	—
	$	1,592.3	$	1,330.1		19.7		15,116.8	14,967.4	1.0
Average customers (thousands)		651.8		633.3		2.9
Retail output to line (kilowatt hours)								15,447.3	15,265.5	1.2

* Not a meaningful calculation

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

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Tampa Electric is currently evaluating its options to meet the need for new intermediate or base-load capacity after 2012 and for peaking purchases and/or capacity additions before that time. Florida has a requirement that utilities put out for bid any new generation with more than 75 megawatts of steam turbine capacity, and meeting this requirement may influence the timing and need for capital spending. In addition, the technology chosen would dictate the magnitude and timing of spending for an intermediate or base-load unit. The choices being considered for new generation range from an integrated gasification combined-cycle (“IGCC”) facility to a combined-cycle natural gas plant. If IGCC is the chosen option, the capital cost is considerably higher and the lead time is longer. The construction of new base-load generation would increase the company’s previously estimated 2006-2010 capital expenditures, primarily during the latter part of that period.

Tampa Electric Company – Natural gas division (Peoples Gas System)

Peoples Gas reported net income of $4.2 million for the third quarter, compared to $4.1 million in the same period in 2005. Quarterly results reflect average customer growth of 3.2%, increased sales to all retail customer classes and strong off-system sales and gas transportation for power generation customers, partially offset by higher non-fuel operations and maintenance costs. Results in 2006 included $0.3 million from the small remaining energy services operating companies, which provide marketing, sales support and gas management services.

Year-to-date net income was $22.7 million, compared to $22.9 million in the 2005 period. Higher non-fuel operations and maintenance expenses and mild winter weather more than offset 3.2% average customer growth, as well as higher energy sales to residential customers and strong off-system sales and gas transportation for power generation customers. Results in 2006 included $1.3 million from the energy services operating companies described above.

A summary of PGS’ regulated operating statistics for the three months and nine months ended Sep. 30, 2006 and 2005 follows:

(in millions, except average customers)		Operating revenues					Therms
		2006		2005	% Change		2006	2005	% Change
Three months ended Sep. 30,
By Customer Segment:
Residential	$	22.6	$	21.5	5.1		10.2	9.6	6.3
Commercial		33.0		33.5	(1.5	)	82.5	79.2	4.2
Industrial		3.5		3.2	9.4		47.6	45.4	4.8
Off system sales		54.0		68.4	(21.1	)	68.6	64.7	6.0
Power generation		4.4		4.4	(0.0	)	142.7	107.5	32.7
Other revenues		12.6		8.2	53.7		—	—	—
	$	130.1	$	139.2	(6.5	)	351.6	306.4	14.8
By Sales Type:
System supply	$	96.6	$	110.8	(12.8	)	95.2	90.5	5.2
Transportation		20.9		20.2	3.5		256.4	215.9	18.8
Other revenue		12.6		8.2	53.7		—	—	—
	$	130.1	$	139.2	(6.5	)	351.6	306.4	14.8
Average customers (thousands)		328.8		318.5	3.2
(in millions, except average customers)		Operating revenues					Therms
		2006		2005	% Change		2006	2005	% Change
Nine months ended Sep. 30,
By Customer Segment:
Residential	$	113.2	$	98.1	15.4		54.7	53.4	2.4
Commercial		128.0		124.6	2.7		280.7	287.6	(2.4	)
Industrial		8.9		8.4	6.0		160.4	157.0	2.2
Off system sales		156.3		128.9	21.3		194.8	152.1	28.1
Power generation		11.0		10.0	10.0		323.3	227.6	42.0
Other revenues		33.4		24.9	34.1		—	—	—
	$	450.8	$	394.9	14.2		1,013.9	877.7	15.5
By Sales Type:
System supply	$	350.1	$	305.1	14.7		302.7	267.7	13.1
Transportation		67.3		64.9	3.7		711.2	610.0	16.6
Other revenue		33.4		24.9	34.1		—	—	—
	$	450.8	$	394.9	14.2		1,013.9	877.7	15.5
Average customers (thousands)		328.4		318.2	3.2

TECO Coal

TECO Coal achieved third quarter net income of $21.4 million, compared to $34.6 million in the same period in 2005. TECO Coal’s 2006 third quarter results included the $13.8 million in net benefits related to synthetic fuel, in addition to adjustments for prior quarters based on current oil prices. Third quarter net benefits from synthetic fuel in 2005 were $24.7 million.

Total sales were 2.3 million tons in the third quarter, including 0.6 million tons of synthetic fuel, compared to 2.3 million tons, including 1.6 million tons of synthetic fuel, in the 2005 period. Compared to the third quarter in 2005, results reflect a 10% higher average net selling price per ton across all products, which excludes transportation allowances. Premiums for quality and sulfur content contributed to the higher selling prices. Synthetic fuel sales volumes were lower than 2005 due to idling of the production facilities from late July through mid-September, which resulted from estimated average annual oil prices above the

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break-even level. Total coal sales were not impacted due to the substitution of conventional coal in lieu of synthetic fuel while the synthetic fuel production was idled.

TECO Coal recorded year-to-date net income of $59.5 million in 2006, compared to $90.5 million in the 2005 period. TECO Coal’s 2006 year-to-date results included the $23.1 million benefit associated with the production of synthetic fuel, while $68.5 million was included in the results for the 2005 period.

Year-to-date 2006 total sales were 7.2 million tons, including 3.6 million tons of synthetic fuel, compared to 7.2 million tons, including 4.9 million tons of synthetic fuel, in the 2005 period. Compared to 2005, results reflect a 16% higher average net per-ton selling price across all products, excluding transportation allowances.

In 2006, the third-quarter cash cost of production increased 14%, compared to the 2005 period. This increase was due in part to additional exploration expenses incurred to optimize future mine plans, and the continued relocation of mining equipment from high cost of production locations to locations that are expected to have lower future costs of production. Higher production costs also reflect increased contract miner costs, continued higher diesel fuel costs, higher explosives costs and higher costs for steel-related products than in 2005. For the 2006 year-to-date period, the cash cost of production increased 10%, compared to 2005’s full-year cash cost of production. The full-year 2006 average cash cost of production is also expected to average about 10% above the 2005 levels.

Net income for the quarter reflected a net $13.8 million after-tax benefit to third-quarter earnings from the production of synthetic fuel. The benefit reflects the estimated 39% reduction in synthetic fuel benefits based on estimated average annual oil prices of $67/Bbl at Sep. 30, compared to estimated oil prices of approximately $71/Bbl and a 63% phase out at Jun. 30. The $13.8 million benefit from synthetic fuel represents $3.6 million of net income from third quarter production at the 39% phase-out level; a $4.3 million after-tax mark-to-market loss on oil price hedges placed in 2005; and a $14.5 million positive adjustment to prior period production when the phase-out range was estimated at 63% versus the 39% phase-out estimate as of Sep. 30, 2006. The decrease in the phase-out of benefits from synthetic fuel production as a result of lower estimated average annual oil prices increased net income from synthetic fuel in the quarter, which more than offset the loss of synthetic fuel proceeds while production was idled in the third quarter.

Year-to-date net income reflected a net $23.1 million after-tax benefit from the production of synthetic fuel. The year-to-date net benefit reflected a $28.1 million after-tax reduction in benefits due to the 39% reduction and a $0.4 million after-tax mark-to-market gain on the oil price hedges previously placed.

Based on the year-to-date actual difference of $7 per barrel between the Producer First Purchase Price reported by the U.S. Department of Energy and NYMEX settled prices, TECO Coal estimates the initial phase-out level for 2006 to begin at $62/Bbl on a NYMEX basis, and that the tax credits would be fully phased-out at $76/Bbl on a NYMEX basis. Changes in oil prices may cause adjustments to results, either positive or negative, at the end of the year when estimates of the actual average oil prices have more certainty.

TECO Transport

TECO Transport recorded third quarter 2006 net income of $3.4 million, compared to $0.9 million in the same period in 2005. TECO Transport’s third quarter 2006 results included $0.2 million of after-tax direct costs associated with the restoration and recovery efforts for Hurricane Katrina damage at TECO Bulk Terminal, compared to the same period in 2005, which include $2.9 million of direct Hurricane Katrina costs. Third quarter results in 2006 reflect higher river barge rates and equipment utilization, more than offset by lower oceangoing vessel utilization, lower Tampa Electric movements and higher fuel costs.

Year-to-date net income was $15.0 million in 2006, compared to $10.3 million in the 2005 period. Year-to-date results included $2.3 million of after-tax direct costs associated with damage from Hurricane Katrina at TECO Bulk Terminal and TECO Barge Line, net of the second quarter insurance recovery at TECO Barge Line, compared to 2005 results, which included $2.9 million of direct Hurricane Katrina costs. The 2006 results reflect fewer shipyard days on oceangoing vessels, higher river barge rates and equipment utilization, higher Tampa Electric movements, and lower repair costs, partially offset by higher fuel costs.

TECO Guatemala

TECO Guatemala reported third quarter net income of $9.3 million in 2006, compared to $14.0 million in the 2005 period. The 2006 results reflect customer growth and lower operating and interest expenses, which were more than offset by higher tax rates compared to 2005. Results in 2005 included the one-year benefit of the 5% tax rate on dividends under the Jobs Creation Act, while 2006 reflects the normal 35% tax rate. Year-to-date 2006 net income of $26.6 million, compared to $33.4 million in the 2005 period, was driven primarily by the items described for the quarter, with the higher tax rate having the largest impact.

Other and Eliminations

The cost for “Parent/other” in the third quarter was $15.6 million, compared to a cost of $21.5 million in the same period in 2005. Third quarter results in 2006 include a $2.6 million after-tax gain on the sale of an unused steam turbine that had been previously written off. Third quarter results in 2005 include a $1.9 million after-tax benefit associated with the sale of the Dell Power Station, offset by the recognition of additional liabilities relating to both the Dell and McAdams power stations.

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The year-to-date “Parent/other” cost was $44.3 million in 2006, compared to $107.6 million in the 2005 period. In addition to the third quarter item noted above, the 2006 year-to-date results in Parent/other included the $8.1 million after-tax gain on the sale of the remaining assets of the unfinished McAdams Power Station, which had been previously impaired. Results in 2005 included a $45.0 million after-tax charge associated with the early retirement of $380 million of debt. Total parent interest expense declined by $20.5 million pretax in the 2006 year-to-date period due to the debt redemption and refinancing actions initiated in mid-2005. This was offset, in part, by no longer allocating interest to TWG Merchant.

Interest Expense

Total interest expense for the three months and nine months ended Sep. 30, 2006 were $70.5 million and $209.7 million, respectively, compared to $68.3 million and $220.2 million for the same periods in 2005. The increase for the quarter relative to last year resulted primarily from the issuance by Tampa Electric of $250 million of 6.55% notes in May 2006 offset by the December 2005 retirement of $100 million of 8.5% trust preferred securities. On a year-to-date basis, interest expense was lower in 2006 than in 2005 due to the parent debt redemption and refinancing plan initiated in mid-2005. In addition to the items impacting the quarter, year-to-date interest expense was also impacted by the redemption in June 2005 of $380 million of 10.5% notes by TECO Energy and the issuance of $200 million of 6.75% notes and $100 million of floating rate notes in mid-2005 by TECO Energy.

Income Taxes

The provision for income taxes from continuing operations for the 2006 third quarter and year-to-date periods were an expense of $42.7 million and $92.7 million, respectively, compared to an expense of $39.2 million and $71.0 million, respectively, for the same periods in 2005. Income tax expense is higher for both periods in 2006, compared to 2005, due to higher pretax income from continuing operations. The 2005 provision includes the provision for U.S. income taxes on cash repatriated from Guatemala and tax expense related to an enacted change in state income tax rates in Kentucky. Both 2006 and 2005 include a tax benefit related to the application of the “tonnage tax” to qualified vessels.

During the nine months ended Sep. 30, 2006 and Sep. 30, 2005 the company experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included a permanent reinvestment of foreign income under APB 23, reduction of income tax expense under the new “tonnage tax” regime, adjustment of deferred tax assets for the effect of an enacted change in state rates, depletion and repatriation of foreign source income to the United States.

Discontinued Operations

There were no results from discontinued operations in the quarter, compared to net income of $0.1 million in the same period of 2005. Results from discontinued operations in 2005 reflect true-up amounts from the small energy services companies that had been sold. Net income from discontinued operations in the 2006 year-to-date period was $1.4 million, compared to $64.1 million in the 2005 period. The 2006 results reflect primarily the recovery of amounts that had been previously written off at the small energy services companies. The 2005 results reflect the operating results from the Union and Gila River power stations through the end of May 2005 and the $76.5 million after-tax gain recorded upon their transfer to the lending bank group at the end of May 2005. Results in 2005 also included the results for the Commonwealth Chesapeake Power Station until its sale in April 2005.

Liquidity and Capital Resources

Cash and Liquidity

Cash flow from operations for the nine months ended Sep. 30, 2006 were $518.5 million compared to $238.2 million for the same period in 2005. Factors contributing to the increase include: $62 million of net favorable recoveries of fuel and gas costs at Tampa Electric and Peoples Gas in 2006 under cost recovery clauses, compared with $61 million of under-recoveries under these clauses in the 2005 period, $21 million lower synfuel cash operating losses in 2006 compared with the 2005 period due to favorable margins and idling the synthetic fuel facilities at TECO Coal in the third quarter of 2006; the recovery through insurance of $17.5 million of storm damage costs at TECO Transport in the first quarter of 2006; the estimated $20.0 million reduction in operating cash outflows due to the disposition of merchant operations, compared with approximately $31 million of cash outflows due to merchant operations in the 2005 period; and no debt extinguishment costs in 2006, compared with $54.4 million of cash debt extinguishment costs in the 2005 period.

TECO Energy’s consolidated cash and cash equivalents, excluding all restricted cash, totaled $561.8 million at Sep. 30, 2006. Restricted cash of $37.3 million includes $30.0 million held in escrow until the end of 2007 related to the sale of an interest in the synthetic coal production facilities. As of Sep. 30, 2006, unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash balances of $14.8 million and restricted cash of $8.2 million.

In addition, at Sep. 30, 2006, aggregate availability under bank credit facilities was $665.5 million, net of letters of credit of $9.5 million outstanding under these facilities. At the end of the quarter, total liquidity, including cash plus credit facilities, was $1.2 billion, which included $515.2 million at Tampa Electric Company, consisting of $475.0 million of credit facilities, all of which were undrawn at Sep. 30, 2006, and $40.2 million of cash.

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TECO Energy parent had total liquidity of $667.9 million at Sep. 30, 2006, consisting of $477.4 million of cash and availability of $190.5 million under its credit facility.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. TECO Energy, Tampa Electric Company and the other operating companies are in compliance with all applicable financial covenants. The table that follows lists the covenants and the performance relative to them at Sep. 30, 2006. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants

(millions, unless otherwise indicated)		Requirement/Restriction	Calculation at Sep. 30, 2006
Instrument	Financial Covenant (1)
Tampa Electric Company
PGS senior notes	EBIT/interest (2)	Minimum of 2.0 times	3.20 times
	Restricted payments	Shareholder equity at least $500	$1,697
	Funded debt/capital	Cannot exceed 65%	52.0%
	Sale of assets	Less than 20% of total assets	0%
Credit facility (3)	Debt/capital	Cannot exceed 65%	50.9%
Accounts receivable credit facility (3)	Debt/capital EBITDA/interest (2)	Cannot exceed 60% Minimum of 2.0 times	50.9% 5.16 times
6.25% senior notes	Debt/capital	Cannot exceed 60%	50.9%
	Limit on liens (5)	Cannot exceed $701	$201 liens outstanding
Insurance agreement relating to pollution bonds	Limit on liens (5)	Cannot exceed $342 (7.5 % of net assets)	$0 liens outstanding
TECO Energy
Credit facility (3)	Debt/EBITDA (2)	Cannot exceed 5.25 times	4.03 times
	EBITDA/interest (2)	Minimum of 2.60 times	3.57 times
	Limit on additional indebtedness	Cannot exceed $112	$0
	Dividend restriction (4)	Cannot exceed $50 per quarter	$40
$300 million note indenture	Limit on liens (5)	Cannot exceed $302 (5.0 % of tangible assets)	$0 outstanding
$100 million and $200 million note indentures	Restrictions on secured debt (5)	(6)	(6)
TECO Diversified
Coal supply agreement guarantee	Dividend restriction	Net worth not less than $413 (40% of tangible net assets)	$576

(1) As defined in each applicable instrument.

(2) EBIT generally represents earnings before interest and taxes. EBITDA generally represents EBIT before depreciation and amortization. However, in each circumstance, the term is subject to the definition prescribed under the relevant agreements.

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(3) See description of credit facilities in Note 6, Short-Term Debt, to the TECO Energy, Inc. Consolidated Condensed Financial Statements.

(4) TECO Energy cannot declare quarterly dividends in excess of the restricted amount unless liquidity projections, demonstrating sufficient cash or cash equivalents to make each of the next three quarterly dividend payments, are delivered to the Administrative Agent.

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

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

Off-Balance Sheet Financing

Unconsolidated affiliates have project debt balances as follows at Sep. 30, 2006. TECO Energy has no debt payment obligations with respect to these financings. Although we are not directly obligated on the debt, our equity interest in those unconsolidated affiliates and our commitments with respect to those projects are at risk if those projects are not operated successfully.

(millions)	Long-term Debt	Ownership Interest
San José Power Station	$       88.7	100%
Alborada Power Station	$       15.2	96%
EEGSA	$     220.9	24%

Outlook

Earnings

In July, the company modified the form of its guidance to assume that synthetic fuel production was at breakeven and updated its previous 2006 guidance to reflect strong year-to-date performance in the five core businesses. The per-share results from the five core businesses assuming synthetic fuel production is at the breakeven point are currently forecast to be in a range of $0.90 to $1.00, which is consistent with the expectations provided in July. This 2006 forecast excludes any additional charges or gains that might occur, such as any additional hurricane restoration costs.

Potential Effects of Synthetic Fuel Production on Earnings

Due to the recent decline in oil prices, an affiliate of TECO Coal resumed synthetic fuel production in mid-September. At Sep. 30, 2006, year-to-date settled oil prices plus the remaining months’ futures prices averaged approximately $67/Bbl on a NYMEX basis, which resulted in a 39% reduction in the value of the synthetic fuel tax credits for 2006 through the first nine months. If oil prices were to remain at a level resulting in a 39% reduction in net synthetic fuel benefits for the year, there would be a synthetic fuel-related upside to the company’s core business guidance range of $0.90 to $1.00 per share, which assumes that synthetic fuel is at breakeven. The following table illustrates estimates of the impacts on synthetic fuel earnings and the 2006 earnings range at oil prices different than the breakeven level for the 5.1 million tons of production now projected to be produced for the full year of 2006.

Potential 2006 Synthetic Fuel Impact (5.1 million tons production)
Average annual NYMEX oil price	Phase-out %	Synthetic Fuel     Earnings*	2006 Earnings   Range
<$62	0	$0.32	$1.22	$1.32
$65	20	$0.22	$1.12	$1.22
$67	39	$0.17	$1.07	$1.17
$69	50	$0.11	$1.01	$1.11
$71	65	$0.06	$0.96	$1.06
$73**	78	--	$0.90	$1.00
$76***	100	$(0.10)	$0.80	$0.90

* Includes expected benefits from oil price hedges.

** Breakeven point, including the effects of oil price hedges previously placed.

*** Assumes 5.1 million tons of production costs with no offsetting benefits from investors and includes $20 million cash / $0.05 per share benefit from oil price hedges.

The actual benefits from the year-to-date synthetic fuel production could be adjusted in the fourth quarter results, depending on changes in the estimate of actual average annual oil prices. This may result in either positive or negative adjustments

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to the results from synthetic fuel production recorded in the first three quarters. Final calculations will be made in 2007, when the Internal Revenue Service publishes the actual reference price.

The cost of producing synthetic fuel is estimated to be approximately $55 million for the 5.1 million tons of production. As shown in the table, if production continues for the remainder of 2006 and the tax credit is completely phased-out, there would be a $0.10 per share negative impact, net of hedges, to the expected results of $0.90 to $1.00 per share.

Cash

TECO Energy previously provided a forecast of its parent net cash accumulation, and year-end parent cash, including synthetic fuel results at various oil prices. The forecast of parent cash accumulation and year-end parent cash balance includes retirement of the remaining $100 million of 8.5% trust preferred securities due in 2041 and a $50 million equity contribution to Tampa Electric in 2006, both of which are discretionary and could be accomplished at other times. Even under a full phase-out of synthetic fuel benefits, TECO Energy expects to retire, at or before maturity, the full $357 million of parent-level debt maturing in 2007 without refinancing. At Sep. 30, 2006, TECO Energy parent had a cash balance of $477 million.

The table below illustrates the estimates for these measures of cash at various average annual oil prices at the expected level of synthetic fuel production in 2006.

2006 Cash Estimates Including Synthetic Fuel (5.1 million tons of production)
Average annual NYMEX oil price	Phase-out -     %	Cash from Operations - $*	Parent     cash - $	Year-end parent     cash - $
<$62	0	550	145	455
$65	20	550	105	420
$67	39	555	85	400
$69	50	560	65	380
$71	65	565	45	360
$73**	78	570	25	340
$76***	100	570	(10)	305

* Includes expected benefits from oil price hedges.

** Breakeven point, including the effects of oil price hedges previously placed.

*** Assumes 5.1 million tons of production costs with no offsetting benefits from investors and includes $20 million cash / $0.05 per share benefit from oil price hedges

Critical Accounting Policies and Estimates

There have been no significant changes to the critical accounting policies and estimates since Dec. 31. 2005, other than the accounting estimate that was recorded during the first three quarters of 2006 for synthetic fuel tax credit related benefits. This estimate is discussed more fully in Note 1, Summary of Significant Accounting Policies, to the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements under the heading, Other Income and Minority Interest.

New Accounting Pronouncements

Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the Financial Accounting Standards Board (FASB) issued FAS No.158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R). This statement of financial accounting standards requires the recognition in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, measured as the difference between the fair value of plan assets and the benefit obligation in the case of a defined benefit plan, or the accumulated postretirement benefit obligation in the case of other postretirement benefit plans. This pronouncement is discussed more fully in Note 2, New Accounting Pronouncements, to the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements.

Fair Value Measurements

In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements. The effective date is for fiscal years ending after Nov. 15, 2007. The company does not believe implementation will be material to its results of operations, statement of position or cash flows.

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. As of Sep. 30, 2006, there

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was no significant change in our exposure to interest rate risk since Dec. 31, 2005.

Credit Risk

We are exposed to credit risk as a result of our purchases and sales of energy commodities and related hedging activities. As of Sep. 30, 2006, there was no significant change in our exposure to credit risk since Dec. 31, 2005.

Commodity Risk

We face varying degrees of exposure to commodity risks—including coal, natural gas, fuel oil and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services and do affect the net fair value of derivatives. We assess and monitor risk using a variety of measurement tools based on the degree of exposure of each operating company to commodity risk. Our most significant commodity risk exposure in 2006 is the potential effect of high oil prices on our earnings and cash flows from synthetic fuel operations, as discussed more fully in the Operating Results – TECO Coal section of Management’s Discussion and Analysis of Financial Condition & Results of Operations.

The following tables summarize the changes in and the fair value balances of energy derivative assets (liabilities) for the nine months ended Sep. 30, 2006:

Changes in Fair Value of Energy Derivatives (millions)

Net fair value of derivatives as of Dec. 31, 2005	$	68.6
Net change in unrealized fair value of derivatives		(183.1	)
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		41.6
Net fair value of energy derivatives as of Sep. 30, 2006	$	(72.9	)
Roll-Forward of Energy Derivative Net Assets (Liabilities) (millions)
Total energy derivative net assets (liabilities) as of Dec. 31, 2005	$	68.6
Change in fair value of net derivative assets (liabilities):
Recorded in Other Comprehensive Income		(142.2	)
Recorded in earnings		0.7
Net option premium payments		—
Net purchase (sale) of existing contracts		—
Net fair value of energy derivatives as of Sep. 30, 2006	$	(72.9	)

Below is a summary table of sources of fair value, by maturity period, for energy derivative contracts at Sep. 30, 2006:

Maturity and Source of Energy Derivative Contracts Net Assets (Liabilities) at Sep. 30, 2006

Contracts Maturing in		Current		Non-current				Total Fair Value
Source of fair value (millions)
Actively quoted prices	$	(72.6	)		$	(6.5	)		$	(79.1	)
Other external sources (1)		—				—				—
Model prices (2)		6.2				—				6.2
Total	$	(66.4	)		$	(6.5	)		$	(72.9	)

(1) Information from external sources includes information obtained from OTC brokers, industry price services or surveys and multiple-party on-line platforms.

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

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Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

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

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

Tampa Electric Company

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

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See Commitments and Contingencies, Note 11 to the TECO Energy, Inc. Consolidated Condensed Financial Statements, and Note 7 to the Tampa Electric Company Consolidated Condensed Financial Statements for updates to legal proceedings previously disclosed in the company’s quarterly report on Form 10-Q for the period ended Jun. 30, 2006.

Item 1A. RISK FACTORS

Information regarding risk factors appears in Item 1A to the Annual Report on Form 10-K for the year ended Dec. 31, 2005 of TECO Energy and Tampa Electric Company.

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

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

	(a)     Total Number of     Shares (or Units) Purchased (1)	(b) Average Price     Paid per Share (or     Unit)	(c) Total Number of Shares (or Units) Purchased as Part of     Publicly Announced     Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Jul. 1, 2006 – Jul. 31, 2006	1,231	$15.68	—	—
Aug. 1, 2006 – Aug 31, 2006	9,890	$15.68	—	—
Sep. 1, 2006 – Sep. 30, 2006	2,201	$15.66	—	—
Total 3rd Quarter 2006	13,322	$15.68	—	—

(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 50.

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SIGNATURES

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

	TECO ENERGY, INC.
	(Registrant)
Date:     November 6, 2006	By:	/s/ G. L. GILLETTE
		G. L. GILLETTE
		Executive Vice President
		and Chief Financial Officer
		(Principal Financial Officer)
	TAMPA ELECTRIC COMPANY
	(Registrant)
Date:     November 6, 2006	By:	/s/ G. L. GILLETTE
		G. L. GILLETTE
		Senior Vice President - Finance
		and Chief Financial Officer
		(Principal Financial Officer)

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INDEX TO EXHIBITS

Exhibit No.		Description
3.1	*	Articles of Incorporation of TECO Energy, Inc., as amended on Apr. 20, 1993 (Exhibit 3, Form 10-Q for the quarter ended Mar. 31, 1993 of TECO Energy, Inc.).
3.2	*	Bylaws of TECO Energy, Inc., as amended effective Jul. 6, 2004 (Exhibit 3.2, Registration Statement on Form S-4 No. 333-117701 of TECO Energy, Inc.).
3.3	*	Articles of Incorporation of Tampa Electric Company (Exhibit 3, Registration Statement No. 2-70653 of Tampa Electric Company).
3.4	*	Bylaws of Tampa Electric Company, as amended effective Apr. 16, 1997 (Exhibit 3, Form 10-Q for the quarter ended Jun. 30, 1997 of Tampa Electric Company).
12.1		Ratio of Earnings to Fixed Charges – TECO Energy, Inc.
12.2		Ratio of Earnings to Fixed Charges – Tampa Electric Company.
31.1		Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3		Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4		Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
32.2		Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)

(1) This certification accompanies the Quarterly Report on Form 10-Q and is not filed as part of it.

* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

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