TECO Energy 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period endedMarch 31, 2012

OR

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

For the transition period from            to            

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

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

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

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

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

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

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

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

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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of April 27, 2012 was $215,679,828. As of April 27, 2012, 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 47

Index to Exhibits appears on page 47.

DEFINITIONS

Acronyms and defined terms used in this and other filings with the U.S. Securities and Exchange Commission include the following:

Term	Meaning
ABS	asset-backed security
ADR	American depository receipt
AFUDC	allowance for funds used during construction
AFUDC - debt	debt component of allowance for funds used during construction
AFUDC - equity	equity component of allowance for funds used during construction
AOCI	accumulated other comprehensive income
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
capacity clause	capacity cost-recovery clause, as established by the FPSC
CGESJ	Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala
CMO	collateralized mortgage obligation
CO2	carbon dioxide
CT	combustion turbine
DECA II	Distribución Eléctrica Centro Americana, II, S.A.
DOE	U.S. Department of Energy
EEGSA	Empresa Eléctrica de Guatemala, S.A., the largest private distribution company in Central America
EEI	Edison Electric Institute
EPA	U.S. Environmental Protection Agency
EPS	earnings per share
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company
FPSC	Florida Public Service Commission
fuel clause	fuel and purchased power cost-recovery clause, as established by the FPSC
GAAP	generally accepted accounting principles
GHG	greenhouse gas(es)
HCIDA	Hillsborough County Industrial Development Authority
HPP	Hardee Power Partners
IFRS	International Financial Reporting Standards
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISO	independent system operator
ITCs	investment tax credits
KW	kilowatt
KWH	kilowatt-hour(s)
LIBOR	London Interbank Offered Rate
MARN	Ministry of Environment, Guatemala
MBS	mortgage-backed securities
MD&A	Management’s Discussion and Analysis
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MM&A	Marshall Miller & Associates
MMBTU	one million British Thermal Units
MRV	market-related value

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MSHA	Mine Safety and Health Administration
MW	megawatt(s)
MWH	megawatt-hour(s)
NAESB	North American Energy Standards Board
NAV	net asset value
NERC	North American Electric Reliability Corporation
NOL	net operating loss
Note	Note    to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
o&m expenses	operations and maintenance expenses
OATT	open access transmission tariff
OCI	other comprehensive income
OTC	over-the-counter
OTTI	other than temporary impairment
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PCIDA	Polk County Industrial Development Authority
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
REIT	real estate investment trust
REMIC	real estate mortgage investment conduit
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
RPS	renewable portfolio standards
RTO	regional transmission organization
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SERP	Supplemental Executive Retirement Plan
SPA	stock purchase agreement
STIF	short-term investment fund
TCAE	Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TEC	Tampa Electric Company, the principal subsidiary of TECO Energy, Inc.
TECO Diversified	TECO Diversified, Inc., a subsidiary of TECO Energy, Inc. and parent of TECO Coal Corporation
TECO Coal	TECO Coal Corporation, a coal producing subsidiary of TECO Diversified
TECO Finance	TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.
TEMSA	Tecnología Marítima, S.A., a provider of dry bulk and coal unloading services located in Guatemala
TRC	TEC Receivables Company
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

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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 March 31, 2012 and Dec. 31, 2011, and the results of their operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 and to the notes on pages 10 through 23 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, March 31, 2012 and Dec. 31, 2011		5-6
Consolidated Condensed Statements of Income for the three month periods ended March 31, 2012 and 2011		7
Consolidated Condensed Statements of Comprehensive Income for the three month periods ended March  31, 2012 and 2011		8
Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2012 and 2011		9
Notes to Consolidated Condensed Financial Statements		10-23

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Mar. 31, 2012			Dec. 31, 2011
Current assets
Cash and cash equivalents	$	59.0		$	44.0
Restricted cash		8.7			8.7
Receivables, less allowance for uncollectibles of $2.6 at Mar. 31, 2012 and Dec. 31, 2011		278.4			327.7
Inventories, at average cost
Fuel		146.6			136.8
Materials and supplies		87.0			87.3
Derivative assets		2.1			0.9
Regulatory assets		107.0			87.3
Deferred income taxes		33.2			72.7
Prepayments and other current assets		29.7			31.9
Income tax receivables		0.1			0.6
Total current assets		751.8			797.9
Property, plant and equipment
Utility plant in service
Electric		6,767.0			6,731.7
Gas		1,184.7			1,169.9
Construction work in progress		274.0			247.4
Other property		435.3			432.3
Property, plant and equipment, at original costs		8,661.0			8,581.3
Accumulated depreciation		(2,675.4	)		(2,613.5	)
Total property, plant and equipment, net		5,985.6			5,967.8
Other assets
Regulatory assets		359.2			364.5
Goodwill		55.4			55.4
Deferred charges and other assets		134.8			136.6
Total other assets		549.4			556.5
Total assets	$	7,286.8		$	7,322.2

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

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)	Mar. 31, 2012			Dec. 31, 2011
Current liabilities
Long-term debt due within one year
Recourse	$	374.8		$	374.9
Non-recourse		11.2			11.2
Notes payable		44.0			0.0
Accounts payable		244.5			252.3
Customer deposits		160.9			159.5
Regulatory liabilities		72.3			86.2
Derivative liabilities		70.0			58.4
Interest accrued		59.9			39.3
Taxes accrued		34.1			20.7
Other current liabilities		17.2			17.2
Total current liabilities		1,088.9			1,019.7
Other liabilities
Deferred income taxes		137.3			150.8
Investment tax credits		10.0			10.0
Regulatory liabilities		644.8			647.8
Derivative liabilities		6.6			8.6
Deferred credits and other liabilities		525.8			530.8
Long-term debt, less amount due within one year
Recourse		2,579.1			2,665.0
Non-recourse		19.6			22.3
Total other liabilities		3,923.2			4,035.3
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 215.8 million shares outstanding at Mar. 31, 2012 and Dec. 31, 2011)		215.8			215.8
Additional paid in capital		1,556.2			1,553.4
Retained earnings		522.5			519.4
Accumulated other comprehensive loss		(20.4	)		(22.0	)
TECO Energy stockholders’ equity		2,274.1			2,266.6
Noncontrolling interest		0.6			0.6
Total capital		2,274.7			2,267.2
Total liabilities and capital	$	7,286.8		$	7,322.2

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

	Three months ended Mar. 31,
(millions, except per share amounts)	2012			2011
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $26.1 in 2012 and $28.4 in 2011)	$	556.3		$	587.1
Unregulated		173.7			209.0
Total revenues		730.0			796.1
Expenses
Regulated operations
Fuel		157.5			144.9
Purchased power		28.2			27.2
Cost of natural gas sold		41.6			82.0
Other		83.3			78.3
Operation other expense
Mining related costs		89.4			124.0
Guatemalan power generation		19.2			20.1
Other		2.6			1.4
Maintenance		44.0			48.8
Depreciation and amortization		83.0			79.8
Taxes, other than income		56.0			58.7
Total expenses		604.8			665.2
Income from operations		125.2			130.9
Other income
Allowance for other funds used during construction		0.4			0.3
Other income		2.0			1.5
Total other income		2.4			1.8
Interest charges
Interest expense		50.6			52.8
Allowance for borrowed funds used during construction		(0.2	)		(0.2	)
Total interest charges		50.4			52.6
Income before provision for income taxes		77.2			80.1
Provision for income taxes		26.6			28.4
Net income	$	50.6		$	51.7
Less: Net income attributable to noncontrolling interest		(0.1	)		0.0
Net income attributable to TECO Energy	$	50.5		$	51.7
Average common shares outstanding– Basic		213.9			213.0
– Diluted		215.3			215.0
Earnings per share attributable to TECO Energy– Basic	$	0.24		$	0.24
– Diluted	$	0.23		$	0.24
Dividends paid per common share outstanding	$	0.220		$	0.205

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2012			2011
Net income	$	50.6		$	51.7
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges		1.5			2.3
Amortization of unrecognized benefit costs		0.1			0.4
Other comprehensive income, net of tax		1.6			2.7
Comprehensive income		52.2			54.4
Comprehensive income attributable to noncontrolling interest		(0.1	)		0.0
Comprehensive income attributable to TECO Energy	$	52.1		$	54.4

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2012			2011
Cash flows from operating activities
Net income	$	50.6		$	51.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		83.0			79.8
Deferred income taxes		24.8			27.2
Investment tax credits		0.0			(0.1	)
Allowance for funds used during construction		(0.4	)		(0.3	)
Non-cash stock compensation		2.5			2.0
Deferred recovery clauses		(20.5	)		26.9
Receivables, less allowance for uncollectibles		49.3			36.1
Inventories		(9.5	)		4.1
Prepayments and other current assets		2.2			1.9
Taxes accrued		13.9			9.7
Interest accrued		20.6			21.9
Accounts payable		1.7			(51.1	)
Other		5.7			20.1
Cash flows from operating activities		223.9			229.9
Cash flows from investing activities
Capital expenditures		(117.4	)		(92.9	)
Allowance for funds used during construction		0.4			0.3
Other investing activities		0.0			17.0
Cash flows used in investing activities		(117.0	)		(75.6	)
Cash flows from financing activities
Dividends		(47.5	)		(44.1	)
Proceeds from the sales of common stock		0.3			1.8
Repayment of long-term debt/Purchase in lieu of redemption		(88.7	)		(78.0	)
Net increase (decrease) in short-term debt		44.0			(12.0	)
Cash flows used in financing activities		(91.9	)		(132.3	)
Net increase in cash and cash equivalents		15.0			22.0
Cash and cash equivalents at beginning of period		44.0			67.5
Cash and cash equivalents at end of period	$	59.0		$	89.5

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

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

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

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries and the accounts of VIEs for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE (seeNote 14).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy is not the primary beneficiary, but is able to exert significant influence. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of March 31, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012.

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

Revenues

As of March 31, 2012 and Dec. 31, 2011, unbilled revenues of $51.1 million and $50.2 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TECO Coal incurs most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $26.1 million and $28.4 million for the three months ended March 31, 2012 and 2011, respectively.

Cash Flows Related to Derivatives and Hedging Activities

The company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of diesel fuel swaps, which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

2. New Accounting Pronouncements

There have been no accounting pronouncements issued applicable to TECO Energy, Inc. or its subsidiaries since Dec. 31, 2011.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC under the PUHCA 2005. However, pursuant to a waiver granted in accordance with the FERC’s regulations, TECO Energy is not subject to certain accounting, record-keeping and reporting requirements prescribed by the FERC’s regulations under PUHCA 2005. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The

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FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $45.6 million and $43.6 million as of March 31, 2012 and Dec. 31, 2011, respectively.

Regulatory Assets and Liabilities

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

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

Details of the regulatory assets and liabilities as of March 31, 2012 and Dec. 31, 2011 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2012		Dec. 31, 2011
Regulatory assets:
Regulatory tax asset(1)	$	63.0	$	63.6
Other:
Cost-recovery clauses		92.6		73.3
Postretirement benefit asset		248.9		252.4
Deferred bond refinancing costs(2)		10.1		11.1
Environmental remediation		30.6		30.5
Competitive rate adjustment		3.4		3.5
Other		17.6		17.4
Total other regulatory assets		403.2		388.2
Total regulatory assets		466.2		451.8
Less: Current portion		107.0		87.3
Long-term regulatory assets	$	359.2	$	364.5
Regulatory liabilities:
Regulatory tax liability(1)	$	15.7	$	16.0
Other:
Cost-recovery clauses		47.8		61.4
Environmental remediation		28.4		28.4
Transmission and delivery storm reserve		45.6		43.6
Deferred gain on property sales(3)		4.5		5.0
Provision for stipulation and other		0.9		0.8
Accumulated reserve - cost of removal		574.2		578.8
Total other regulatory liabilities		701.4		718.0
Total regulatory liabilities		717.1		734.0
Less: Current portion		72.3		86.2
Long-term regulatory liabilities	$	644.8	$	647.8

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

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

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

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

Regulatory Assets
(millions)	Mar.  31, 2012		Dec 31, 2011
Clause recoverable(1)	$	96.0	$	76.8
Components of rate base(2)		261.8		264.9
Regulatory tax assets(3)		63.0		63.6
Capital structure and other(3)		45.4		46.5
Total	$	466.2	$	451.8

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

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

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

4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2010 consolidated federal income tax return during 2011. The U.S. federal statute of limitations remains open for years 2008 and onward. Years 2011 and 2012 are currently under examination by the IRS under their Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2012. Foreign and U.S. state jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2006 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense-Other” on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. During the first quarter of 2012, the company recorded $0.1 million of pretax charges for interest only and an immaterial amount for penalties.

The effective tax rate decreased to 34.5% for the three months ended March 31, 2012 from 35.4% for the same period in 2011. The decrease is principally due to state income taxes.

5. Employee Postretirement Benefits

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Mar. 31,	2012			2011			2012		2011
Components of net periodic benefit expense
Service cost	$	4.4		$	4.2		$	0.7	$	0.6
Interest cost on projected benefit obligations		7.4			7.8			2.5		2.8
Expected return on assets		(9.6	)		(9.7	)		0.0		0.0
Amortization of:
Transition obligation		0.0			0.0			0.4		0.6
Prior service (benefit) cost		(0.1	)		(0.1	)		0.2		0.2
Actuarial loss		3.7			2.8			0.0		0.1
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	5.8		$	5.0		$	3.8	$	4.3

For the fiscal 2012 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.797% for pension benefits under its qualified pension plan, and a discount rate of 4.744% for its other postretirement benefits as of their Jan. 1, 2012 measurement dates. Additionally, TECO Energy made contributions of $12.4 million to its pension plan in the first quarter of 2012.

For the three months ended March 31, 2012, TECO Energy and its subsidiaries reclassed $0.7 million pretax of unamortized transition obligation, prior service cost and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended March 31, 2012, TEC reclassed $3.5 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

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6. Short-Term Debt

At March 31, 2012 and Dec. 31, 2011, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2012						Dec. 31, 2011
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	0.0	$	0.7
1-year accounts receivable facility		150.0		34.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility(2)(3)		200.0		10.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	44.0	$	0.7	$	675.0	$	0.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Oct. 25, 2016.

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

At March 31, 2012, these credit facilities require commitment fees ranging from 17.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2012 was 0.65%. There were no outstanding borrowings at Dec. 31, 2011.

Tampa Electric Company Accounts Receivable Facility

On Feb. 17, 2012, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 10 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 15, 2013, (ii) provides that TRC will pay program and liquidity fees, which will total 60 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

7. Long-Term Debt

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) and Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the HCIDA Bonds). On March 19, 2008, the HCIDA remarketed the HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the HCIDA Bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation.

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

On March 26, 2008, TEC purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the March 15, 2012 purchase of the HCIDA Bonds, $181.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of March 31, 2012 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

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Fair Value of Long-Term Debt

At March 31, 2012, total long-term debt had a carrying amount of $2,987.0 million and an estimated fair market value of $3,363.4 million. At Dec. 31, 2011, total long-term debt had a carrying amount of $3,075.8 million and an estimated fair market value of $3,435.3 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are level 2 instruments.

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended March 31, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

Other Comprehensive Income
	Three months ended Mar. 31,
(millions)	Gross			Tax			Net
2012
Unrealized gain on cash flow hedges	$	2.5		$	(0.9	)	$	1.6
Less: Gain reclassified to net income		(0.2	)		0.1			(0.1	)
Gain on cash flow hedges		2.3			(0.8	)		1.5
Amortization of unrecognized benefit costs		0.7			(0.6	)		0.1
Total other comprehensive income	$	3.0		$	(1.4	)	$	1.6
2011
Unrealized gain on cash flow hedges	$	4.1		$	(1.5	)	$	2.6
Less: Gain reclassified to net income		(0.5	)		0.2			(0.3	)
Gain on cash flow hedges		3.6			(1.3	)		2.3
Amortization of unrecognized benefit costs		0.6			(0.2	)		0.4
Total other comprehensive income	$	4.2		$	(1.5	)	$	2.7

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2012			Dec. 31, 2011
Unrecognized pension loss and prior service credit(1)	$	(31.1	)	$	(31.2	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		14.2			14.2
Net unrealized losses from cash flow hedges(3)		(3.5	)		(5.0	)
Total accumulated other comprehensive loss	$	(20.4	)	$	(22.0	)

(1) Net of tax benefit of $19.1 million and $19.6 million as of March 31, 2012 and Dec. 31, 2011, respectively.

(2) Net of tax expense of $6.2 million and $6.2 million as of March 31, 2012 and Dec. 31, 2011, respectively.

(3) Net of tax benefit of $2.3 million and $3.2 million as of March 31, 2012 and Dec. 31, 2011, respectively.

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9. Earnings Per Share

Earnings Per Share
	Three months ended Mar. 31,
(millions, except per share amounts)	2012			2011
Basic earnings per share
Net income	$	50.6		$	51.7
Less: Income attributable to noncontrolling interest		(0.1	)		0.0
Less: Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	50.3		$	51.4
Average common shares outstanding - Basic		213.9			213.0
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.24		$	0.24
Diluted earnings per share
Net income	$	50.6		$	51.7
Less: Income attributable to noncontrolling interest		(0.1	)		0.0
Less: Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	50.3		$	51.4
Average common shares outstanding - Basic		213.9			213.0
Assumed conversions of stock options, unvested restricted stock and contingent performance shares, net		1.4			2.0
Average common shares outstanding - Diluted		215.3			215.0
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.23		$	0.24
Anti-dilutive shares		1.4			2.4

10. Commitments and Contingencies

Legal Contingencies

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

Merco Group at Aventura Landings v. Peoples Gas System

In a Florida district court case pending in Miami, Merco Group at Aventura Landings I, II and III (Merco) alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, the court will consider PGS’s counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and the parties are awaiting a ruling by the Judge. Co-defendant Continental Holdings, Inc. reached a settlement with Merco but still remains as a defendant in PGS’s third-party complaint.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2012, TEC has estimated its ultimate financial liability to be $28.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in “Long-term regulatory liabilities” on the company’s Consolidated Condensed Balance Sheet. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

The estimated amounts represent only the estimated portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’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.

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

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

Potentially Responsible Party Notification

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

Environmental Protection Agency Administrative Order

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s and TEC’s letters of credit and guarantees as of March 31, 2012 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2012		2013-2016		After(1) 2016		Total		Liabilities Recognized at Mar. 31, 2012
TECO Coal
Fuel purchase related(2)	$	0.0	$	0.0	$	5.4	$	5.4	$	1.2
Other subsidiaries
Fuel purchase/energy management(2)		0.0		10.0		94.7		104.7		0.4
Total	$	0.0	$	10.0	$	100.1	$	110.1	$	1.6

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2012		2013-2016		After(1) 2016		Total		Liabilities Recognized at Mar. 31, 2012
Tampa Electric(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2016.

(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 March 31, 2012. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At March 31, 2012, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

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11. Segment Information

TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.

Segment Information(1)
(millions) Three months ended Mar. 31,	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala		Other & Eliminations			TECO Energy
2012
Revenues - external	$	446.3	$	110.0	$	138.4	$	32.9	$	2.4		$	730.0
Sales to affiliates		0.3		0.2		0.0		0.0		(0.5	)		0.0
Total revenues		446.6		110.2		138.4		32.9		1.9			730.0
Depreciation and amortization		57.4		12.6		10.8		1.8		0.4			83.0
Total interest charges(1)		30.0		4.4		1.8		2.1		12.1			50.4
Internally allocated interest(1)		0.0		0.0		1.7		1.8		(3.5	)		0.0
Provision (benefit) for income taxes		18.9		6.9		3.1		2.7		(5.0	)		26.6
Net income (loss) attributable to
TECO Energy	$	31.4	$	11.0	$	9.8	$	6.6	($	8.3	)	$	50.5
2011
Revenues - external	$	432.9	$	154.2	$	173.7	$	33.6	$	1.7		$	796.1
Sales to affiliates		0.3		1.9		0.0		0.0		(2.2	)		0.0
Total revenues		433.2		156.1		173.7		33.6		(0.5	)		796.1
Depreciation and amortization		54.9		11.8		10.9		1.8		0.4			79.8
Total interest charges(1)		30.9		4.5		1.7		1.9		13.6			52.6
Internally allocated interest(1)		0.0		0.0		1.6		1.5		(3.1	)		0.0
Provision (benefit) for income taxes		20.0		9.3		1.6		2.8		(5.3	)		28.4
Net income (loss) attributable to
TECO Energy	$	31.6	$	14.7	$	8.2	$	6.3	($	9.1	)	$	51.7
At Mar. 31, 2012
Goodwill		0.0		0.0		0.0		55.4		0.0			55.4
Total assets	$	5,932.3	$	947.7	$	363.8	$	314.2	($	271.2	)	$	7,286.8
At Dec. 31, 2011
Goodwill		0.0		0.0		0.0		55.4		0.0			55.4
Total assets	$	5,940.9	$	932.0	$	385.2	$	304.1	($	240.0	)	$	7,322.2

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2012 through March 2012 were at a pretax rate of 6.00% and for 2011 were at a pretax rate of 6.25% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending

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

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

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of March 31, 2012, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at March 31, 2012 and Dec. 31, 2011:

Total Derivatives(1)
(millions)	Mar. 31, 2012		Dec. 31, 2011
Current assets	$	2.1	$	0.9
Long-term assets		0.0		0.0
Total assets	$	2.1	$	0.9
Current liabilities	$	70.0	$	58.4
Long-term liabilities		6.6		8.6
Total liabilities	$	76.6	$	67.0

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

The following table presents the derivative hedges of diesel fuel contracts at March 31, 2012 and Dec. 31, 2011 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Mar. 31, 2012		Dec. 31, 2011
Current assets	$	2.1	$	0.9
Long-term assets		0.0		0.0
Total assets	$	2.1	$	0.9
Current liabilities	$	0.0	$	0.0
Long-term liabilities		0.4		1.2
Total liabilities	$	0.4	$	1.2

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The following table presents the derivative hedges of natural gas contracts at March 31, 2012 and Dec. 31, 2011 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Mar. 31, 2012		Dec. 31, 2011
Current assets	$	0.0	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.0	$	0.0
Current liabilities	$	70.0	$	58.4
Long-term liabilities		6.2		7.4
Total liabilities	$	76.2	$	65.8

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at March 31, 2012 is a net loss of $3.5 million after tax and accumulated amortization. This compares to a net loss of $5.0 million in AOCI after tax and accumulated amortization at Dec. 31, 2011.

The following table presents the fair values and locations of derivative instruments recorded on the balance sheet at March 31, 2012:

Derivatives Designated as Hedging Instruments
	Asset Derivatives				Liability Derivatives
(millions) Mar. 31, 2012	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	2.1		Derivative liabilities	$	0.0
Long-term		Derivative assets		0.0		Derivative liabilities		0.4
Natural gas derivatives:
Current		Derivative assets		0.0		Derivative liabilities		70.0
Long-term		Derivative assets		0.0		Derivative liabilities		6.2
Total derivatives designated as hedging instruments			$	2.1			$	76.6

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of March 31, 2012:

Energy Related Derivatives
	Asset Derivatives				Liability Derivatives
(millions) Mar. 31, 2012	Balance Sheet Location(1)		Fair Value		Balance Sheet Location(1)		Fair Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	0.0		Regulatory assets	$	70.0
Long-term		Regulatory liabilities		0.0		Regulatory assets		6.2
Total			$	0.0			$	76.2

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

Based on the fair value of the instruments at March 31, 2012, net pretax losses of $70.0 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

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The following table presents the effect of hedging instruments on OCI and income for the three months ended March 31:

(millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion(1)			Effective Portion(1)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.1	)
Commodity contracts:
Diesel fuel derivatives		1.6	Mining related costs		0.2
Total	$	1.6		$	0.1
2011
Interest rate contracts	$	0.0	Interest expense	($	0.1	)
Commodity contracts:
Diesel fuel derivatives		2.6	Mining related costs		0.4
Total	$	2.6		$	0.3

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2012 and 2011, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the three months ended March 31:

(millions)	Fair Value Asset/ (Liability)		Amount of Gain/(Loss) Recognized in OCI(1)		Amount of Gain/ (Loss) Reclassified From AOCI Into Income
2012
Interest rate swaps	$	0.0	$	0.0	($	0.1	)
Diesel fuel derivatives		1.7		1.6		0.2
Total	$	1.7	$	1.6	$	0.1
2011
Interest rate swaps	$	0.0	$	0.0	($	0.1	)
Diesel fuel derivatives		5.1		2.6		0.4
Total	$	5.1	$	2.6	$	0.3

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for both financial natural gas and financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2012, are expected to settle during the 2012, 2013 and 2014 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2012		0.0		7.4		0.0		30.8
2013		0.0		2.7		0.0		10.7
2014		0.0		1.5		0.0		1.0
Total		0.0		11.6		0.0		42.5

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

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of March 31, 2012, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance in valuing counterparty positions. The company monitors counterparties’ credit standings, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties, forward-looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2012, all positions with counterparties are net liabilities.

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

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at March 31, 2012:

Contingent Features
(millions) At Mar. 31, 2012	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	76.6	)	($	76.6	)	$	0.0

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and Dec. 31, 2011. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

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Recurring Fair Value Measures
	At fair value as of Mar. 31, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Diesel fuel swaps		0.0		2.1		0.0		2.1
Total	$	0.0	$	2.1	$	0.0	$	2.1
Liabilities
Natural gas swaps	$	0.0	$	76.2	$	0.0	$	76.2
Diesel fuel swaps		0.0		0.4		0.0		0.4
Total	$	0.0	$	76.6	$	0.0	$	76.6

	At fair value as of Dec. 31, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Diesel fuel swaps		0.0		0.9		0.0		0.9
Total	$	0.0	$	0.9	$	0.0	$	0.9
Liabilities
Natural gas swaps	$	0.0	$	65.8	$	0.0	$	65.8
Diesel fuel swaps		0.0		1.2		0.0		1.2
Total	$	0.0	$	67.0	$	0.0	$	67.0

Natural gas and diesel fuel swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (seeNote 12).

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At March 31, 2012, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were liability positions.

14. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.5 million and $15.8 million of capacity pursuant to PPAs for the three months ended March 31, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore,

22

the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $14.6 million and $7.1 million for the three months ended March 31, 2012 and 2011, respectively, under this PPA.

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

23

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 TEC and its subsidiaries as of March 31, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012. References should be made to the explanatory notes affecting the consolidated financial statements contained in TEC’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 and to the notes on pages 29 through 38 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, March 31, 2012 and Dec. 31, 2011		25-26
Consolidated Condensed Statements of Income and Comprehensive Income for the three month periods ended March 31, 2012 and 2011		27
Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2012 and 2011		28
Notes to Consolidated Condensed Financial Statements		29-38

All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.

24

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Mar. 31, 2012			Dec. 31, 2011
Property, plant and equipment
Utility plant in service
Electric	$	6,549.8		$	6,516.0
Gas		1,128.3			1,113.5
Construction work in progress		266.2			239.2
Utility plant in service, at original costs		7,944.3			7,868.7
Accumulated depreciation		(2,284.9	)		(2,230.3	)
		5,659.4			5,638.4
Other property, net		6.4			6.5
Total property, plant and equipment, net		5,665.8			5,644.9
Current assets
Cash and cash equivalents		10.5			13.9
Receivables, less allowance for uncollectibles of $1.3 at Mar. 31, 2012 and Dec. 31, 2011		204.2			216.8
Inventories, at average cost
Fuel		83.4			97.9
Materials and supplies		67.0			67.7
Regulatory assets		107.0			87.3
Taxes receivable		0.0			14.6
Deferred income taxes		28.2			30.4
Prepayments and other current assets		9.6			10.5
Total current assets		509.9			539.1
Deferred debits
Unamortized debt expense		13.3			14.1
Regulatory assets		359.2			364.5
Other		5.5			8.8
Total deferred debits		378.0			387.4
Total assets	$	6,553.7		$	6,571.4

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

25

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital (millions)	Mar. 31, 2012			Dec. 31, 2011
Capital
Common stock	$	1,852.4		$	1,852.4
Accumulated other comprehensive loss		(4.5	)		(4.6	)
Retained earnings		296.6			305.7
Total capital		2,144.5			2,153.5
Long-term debt, less amount due within one year		1,530.5			1,616.3
Total capitalization		3,675.0			3,769.8
Current liabilities
Long-term debt due within one year		374.9			374.9
Notes payable		34.0			0.0
Accounts payable		187.2			191.3
Customer deposits		160.9			159.5
Regulatory liabilities		72.3			86.2
Derivative liabilities		70.0			58.4
Interest accrued		44.1			25.6
Taxes accrued		21.2			11.9
Other		11.6			11.6
Total current liabilities		976.2			919.4
Deferred credits
Deferred income taxes		861.6			833.0
Investment tax credits		10.0			10.0
Derivative liabilities		6.2			7.4
Regulatory liabilities		644.8			647.8
Other		379.9			384.0
Total deferred credits		1,902.5			1,882.2
Total liabilities and capital	$	6,553.7		$	6,571.4

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

26

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2012			2011
Revenues
Electric (includes franchise fees and gross receipts taxes of $19.9 in 2012 and $19.3 in 2011)	$	446.5		$	433.1
Gas (includes franchise fees and gross receipts taxes of $6.2 in 2012 and $9.1 in 2011)		110.0			154.2
Total revenues		556.5			587.3
Expenses
Operations
Fuel		157.5			144.9
Purchased power		28.2			27.2
Cost of natural gas sold		41.6			82.0
Other		83.1			78.2
Maintenance		29.0			31.5
Depreciation and amortization		70.0			66.7
Taxes, federal and state		25.6			29.1
Taxes, other than income		45.4			46.6
Total expenses		480.4			506.2
Income from operations		76.1			81.1
Other income
Allowance for other funds used during construction		0.4			0.3
Taxes, non-utility federal and state		(0.2	)		(0.2	)
Other income, net		0.5			0.5
Total other income		0.7			0.6
Interest charges
Interest on long-term debt		31.7			32.7
Other interest		2.9			2.9
Allowance for borrowed funds used during construction		(0.2	)		(0.2	)
Total interest charges		34.4			35.4
Net income		42.4			46.3
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges		0.1			0.1
Total other comprehensive income, net of tax		0.1			0.1
Comprehensive income	$	42.5		$	46.4

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

27

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2012			2011
Cash flows from operating activities
Net income	$	42.4		$	46.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		70.0			66.7
Deferred income taxes		31.0			27.3
Investment tax credits		0.0			(0.1	)
Allowance for funds used during construction		(0.4	)		(0.3	)
Gain on sale of business/assets, pretax		(0.1	)		(0.1	)
Deferred recovery clauses		(20.5	)		26.9
Receivables, less allowance for uncollectibles		11.2			58.4
Inventories		15.1			5.9
Prepayments		0.9			1.3
Taxes accrued		23.9			37.3
Interest accrued		18.5			18.8
Accounts payable		6.6			(60.4	)
Other		5.3			12.4
Cash flows from operating activities		203.9			240.4
Cash flows from investing activities
Capital expenditures		(104.6	)		(78.1	)
Allowance for funds used during construction		0.4			0.3
Net proceeds from sale of assets		0.3			2.6
Cash flows used in investing activities		(103.9	)		(75.2	)
Cash flows from financing activities
Repayment of long-term debt/Purchase in lieu of redemption		(86.0	)		(75.2	)
Net increase (decrease) in short-term debt		34.0			(12.0	)
Dividends		(51.4	)		(54.5	)
Cash flows used in financing activities		(103.4	)		(141.7	)
Net (decrease) increase in cash and cash equivalents		(3.4	)		23.5
Cash and cash equivalents at beginning of period		13.9			3.7
Cash and cash equivalents at end of period	$	10.5		$	27.2

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

28

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

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

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of March 31, 2012 and Dec. 31, 2011, and the results of operations and cash flows for the periods ended March 31, 2012 and 2011. The results of operations for the three month period ended March 31, 2012 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2012.

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

Revenues

As of March 31, 2012 and Dec. 31, 2011, unbilled revenues of $51.1 million and $50.2 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $26.1 million and $28.4 million for the three months ended March 31, 2012 and 2011, respectively.

Cash Flows Related to Derivatives and Hedging Activities

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Condensed Statements of Cash Flows.

2. New Accounting Pronouncements

There have been no accounting pronouncements issued applicable to TEC or its subsidiaries since Dec. 31, 2011.

3. Regulatory

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

29

Storm Damage Cost Recovery

Tampa Electric accrues $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $45.6 million and $43.6 million as of March 31, 2012 and Dec. 31, 2011, respectively.

Regulatory Assets and Liabilities

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

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

Details of the regulatory assets and liabilities as of March 31, 2012 and Dec. 31, 2011 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2012		Dec. 31, 2011
Regulatory assets:
Regulatory tax asset(1)	$	63.0	$	63.6
Other:
Cost-recovery clauses		92.6		73.3
Postretirement benefit asset		248.9		252.4
Deferred bond refinancing costs(2)		10.1		11.1
Environmental remediation		30.6		30.5
Competitive rate adjustment		3.4		3.5
Other		17.6		17.4
Total other regulatory assets		403.2		388.2
Total regulatory assets		466.2		451.8
Less: Current portion		107.0		87.3
Long-term regulatory assets	$	359.2	$	364.5
Regulatory liabilities:
Regulatory tax liability(1)	$	15.7	$	16.0
Other:
Cost-recovery clauses		47.8		61.4
Environmental remediation		28.4		28.4
Transmission and delivery storm reserve		45.6		43.6
Deferred gain on property sales(3)		4.5		5.0
Provision for stipulation and other		0.9		0.8
Accumulated reserve - cost of removal		574.2		578.8
Total other regulatory liabilities		701.4		718.0
Total regulatory liabilities		717.1		734.0
Less: Current portion		72.3		86.2
Long-term regulatory liabilities	$	644.8	$	647.8

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

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

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

30

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

Regulatory Assets
(millions)	Mar. 31, 2012		Dec. 31, 2011
Clause recoverable(1)	$	96.0	$	76.8
Components of rate base(2)		261.8		264.9
Regulatory tax assets(3)		63.0		63.6
Capital structure and other(3)		45.4		46.5
Total	$	466.2	$	451.8

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

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

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

4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the three months ended March 31, 2012 and 2011 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of the company’s 2010 consolidated federal income tax return during 2011. The U.S. federal statute of limitations remains open for the year 2008 and onward. Years 2011 and 2012 are currently under examination by the IRS under the Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2012. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2008 and onward.

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found inNote 5,Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended March 31, 2012 and 2011, respectively, was $4.2 million and $3.6 million for pension benefits, and $3.1 million and $3.5 million for other postretirement benefits.

For the fiscal 2012 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.797% for pension benefits under its qualified pension plan, and a discount rate of 4.744% for its other postretirement benefits as of their Jan. 1, 2012 measurement dates. Additionally, TECO Energy made contributions of $12.4 million to its pension plan in the first quarter of 2012. TEC’s portion of the contributions was $9.7 million.

Included in the benefit expenses discussed above, for the three months ended March 31, 2012, TEC reclassed $3.5 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

31

6. Short-Term Debt

At March 31, 2012 and Dec. 31, 2011, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2012						Dec. 31, 2011
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	0.0	$	0.7	$	325.0	$	0.0	$	0.7
1-year accounts receivable facility		150.0		34.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	34.0	$	0.7	$	475.0	$	0.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Oct. 25, 2016.

At March 31, 2012, these credit facilities require commitment fees ranging from 17.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2012 was 0.65%. There were no outstanding borrowings at Dec. 31, 2011.

Tampa Electric Company Accounts Receivable Facility

On Feb. 17, 2012, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 10 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 15, 2013, (ii) provides that TRC will pay program and liquidity fees, which will total 60 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

7. Long-Term Debt

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) and Polk County Industrial Development Authority Solid Waste Disposal Facility Revenue Refunding Bonds (Tampa Electric Company Project), Series 2010

On March 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the HCIDA Bonds). On March 19, 2008, the HCIDA had remarketed the HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The HCIDA Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. TEC is responsible for payment of the interest and principal associated with the HCIDA Bonds. Regularly scheduled principal and interest when due are insured by Ambac Assurance Corporation.

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

On March 26, 2008, TEC purchased in lieu of redemption $20.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C. After the March 15, 2012 purchase of the HCIDA Bonds, $181.0 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of March 31, 2012 (the “Held Bonds”) to provide an opportunity to evaluate refinancing alternatives. The Held Bonds effectively offset the outstanding debt balances and are presented net on the balance sheet.

Fair Value of Long-Term Debt

At March 31, 2012, TEC’s total long-term debt had a carrying amount of $1,906.3 million and an estimated fair market value of $2,197.2 million. At Dec. 31, 2011, total long-term debt had a carrying amount of $1,992.3 million and an estimated fair market value of $2,291.5 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are level 2 instruments.

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8. Commitments and Contingencies

Legal Contingencies

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

Merco Group at Aventura Landings v. Peoples Gas System

In a Florida district court case pending in Miami, Merco Group at Aventura Landings I, II and III (Merco) alleged that coal tar from a certain former PGS manufactured gas plant site had been deposited in the early 1960s onto property now owned by Merco. Merco alleged that it incurred approximately $3.9 million in costs associated with the removal of such coal tar and provided testimony claiming approximately $110.0 million plus interest in damages from out-of-pocket development expenses and lost profits due to the delay in its condominium development project allegedly caused by the presence of the coal tar. PGS maintains that it is not liable because the coal tar did not originate from its manufactured gas plant site and filed a third-party complaint against Continental Holdings, Inc., which Merco also added as a defendant in its suit, as the owner at the relevant time of the site that PGS believes was the source of the coal tar on Merco’s property. In addition, the court will consider PGS’s counterclaim against Merco which claims that, because Merco purchased the property with actual knowledge of the presence of coal tar on the property, Merco should contribute toward any damages resulting from the presence of coal tar. The bench trial in this matter was concluded in February 2012 and the parties are awaiting a ruling by the Judge. Co-defendant Continental Holdings, Inc. reached a settlement with Merco but still remains as a defendant in PGS’s third-party complaint.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2012, TEC has estimated its ultimate financial liability to be $28.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in “Long-term regulatory liabilities” on TEC’s Consolidated Condensed Balance Sheet. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Potentially Responsible Party Notification

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

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Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of March 31, 2012 are as follows:

Letters of Credit -Tampa Electric Company
(millions)	2012		2013-2016		After(1) 2016		Total		Liabilities Recognized at Mar. 31, 2012
Letters of Credit for the Benefit of:
Tampa Electric(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.2

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2016.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at March 31, 2012. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At March 31, 2012, TEC was in compliance with all applicable financial covenants.

9. Segment Information

(millions) Three months ended Mar. 31,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2012
Revenues - external	$	446.4	$	110.1	$	0.0		$	556.5
Sales to affiliates		0.2		0.1		(0.3	)		0.0
Total revenues		446.6		110.2		(0.3	)		556.5
Depreciation and amortization		57.4		12.6		0.0			70.0
Total interest charges		30.0		4.4		0.0			34.4
Provision for income taxes		18.9		6.9		0.0			25.8
Net income	$	31.4	$	11.0	$	0.0		$	42.4
2011
Revenues - external	$	431.3	$	156.0	$	0.0		$	587.3
Sales to affiliates		1.9		0.1		(2.0	)		0.0
Total revenues		433.2		156.1		(2.0	)		587.3
Depreciation and amortization		54.9		11.8		0.0			66.7
Total interest charges		30.9		4.5		0.0			35.4
Provision for income taxes		20.0		9.3		0.0			29.3
Net income	$	31.6	$	14.7	$	0.0		$	46.3
Total assets at Mar. 31, 2012	$	5,676.0	$	904.8	($	27.1	)	$	6,553.7
Total assets at Dec. 31, 2011	$	5,693.0	$	888.4	($	10.0	)	$	6,571.4

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

TEC applies the accounting standards for derivatives and hedging. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

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

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of March 31, 2012, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at March 31, 2012 and Dec. 31, 2011 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Mar. 31, 2012		Dec. 31, 2011
Current assets	$	0.0	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.0	$	0.0
Current liabilities(1)	$	70.0	$	58.4
Long-term liabilities		6.2		7.4
Total liabilities	$	76.2	$	65.8

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

The ending balance in AOCI related to previously settled interest rate swaps at March 31, 2012 is a net loss of $4.5 million after tax and accumulated amortization. This compares to a net loss of $4.6 million in AOCI after tax and accumulated amortization at Dec. 31, 2011.

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of March 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Mar. 31, 2012	Balance Sheet Location(1)	Fair Value		Balance Sheet Location(1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.0	Regulatory assets	$	70.0
Long-term	Regulatory liabilities		0.0	Regulatory assets		6.2
Total		$	0.0		$	76.2

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

Based on the fair value of the instruments at March 31, 2012, net pretax losses of $70.0 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next 12 months.

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The following table presents the effect of hedging instruments on OCI and income for the three months ended March 31:

(millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion(1)			Effective Portion(1)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.1	)
Total	$	0.0		($	0.1	)
2011
Interest rate contracts	$	0.0	Interest expense	($	0.1	)
Total	$	0.0		($	0.1	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2012 and 2011, all hedges were effective.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for the financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2012, are expected to settle during the 2012, 2013 and 2014 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2012		0.0		30.8
2013		0.0		10.7
2014		0.0		1.0
Total		0.0		42.5

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

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of March 31, 2012, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio are rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance in valuing counterparty positions. TEC monitors counterparties’ credit standings, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Net liability positions are generally not adjusted as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties, forward-looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2012, all positions with counterparties are net liabilities.

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

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The table below presents the fair value of the overall contractual contingent liability positions for TEC’s derivative activity at March 31, 2012:

Contingent Features
(millions) Mar. 31, 2012	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	76.2	)	($	76.2	)	$	0.0

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and Dec. 31, 2011. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below, the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Mar. 31, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Total	$	0.0	$	0.0	$	0.0	$	0.0
Liabilities
Natural gas swaps	$	0.0	$	76.2	$	0.0	$	76.2
Total	$	0.0	$	76.2	$	0.0	$	76.2

	At fair value as of Dec. 31, 2011
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.0	$	0.0	$	0.0
Total	$	0.0	$	0.0	$	0.0	$	0.0
Liabilities
Natural gas swaps	$	0.0	$	65.8	$	0.0	$	65.8
Total	$	0.0	$	65.8	$	0.0	$	65.8

Natural gas swaps are over-the-counter swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (seeNote 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At March 31, 2012, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions.

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12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2012
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Plus: Loss reclassified to net income		0.3		(0.2	)		0.1
Gain on cash flow hedges		0.3		(0.2	)		0.1
Total other comprehensive income (loss)	$	0.3	($	0.2	)	$	0.1
2011
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Plus: Loss reclassified to net income		0.3		(0.2	)		0.1
Gain on cash flow hedges		0.3		(0.2	)		0.1
Total other comprehensive income (loss)	$	0.3	($	0.2	)	$	0.1

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2012			Dec. 31, 2011
Net unrealized losses from cash flow hedges(1)	($	4.5	)	($	4.6	)
Total accumulated other comprehensive loss	($	4.5	)	($	4.6	)

(1) Net of tax benefit of $2.7 million and $2.9 million as of March 31, 2012 and Dec. 31, 2011, respectively.

13. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.5 million and $15.8 million of capacity pursuant to PPAs for the three months ended March 31, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $14.6 million and $7.1 million for the three months ended March 31, 2012 and 2011, respectively, under this PPA.

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

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; the availability of adequate rail transportation capacity for the shipment of TECO Coal’s production; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida economy and demand for TECO Coal’s production; costs for alternative fuels used for power generation affecting demand for TECO Coal’s thermal coal production; weather variations and changes in customer energy usage patterns affecting sales and operating costs at Tampa Electric and Peoples Gas and the effect of extreme weather conditions or hurricanes; operating conditions; commodity prices; operating cost and environmental or safety regulations affecting the production levels and margins at TECO Coal; fuel cost recoveries and related cash at Tampa Electric and natural gas demand at Peoples Gas; the ability to complete the scheduled 2012 outage at the San José Power Station on time and on budget; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2011.

Earnings Summary-Unaudited
	Three months ended Mar. 31,
(millions, except per share amounts)	2012		2011
Consolidated revenues	$	730.0	$	796.1
Net income attributable to TECO Energy	$	50.5	$	51.7
Average common shares outstanding
Basic		213.9		213.0
Diluted		215.3		215.0
Earnings per share - Basic	$	0.24	$	0.24
Earnings per share - Diluted	$	0.23	$	0.24

Operating Company Results

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

Tampa Electric – Electric Division

Net income for the first quarter was $31.4 million, compared with $31.6 million for the same period in 2011 reflecting slightly higher base revenues offset by higher depreciation expense. Energy sales were higher driven in part by higher industrial volumes. Residential sales were impacted by very mild winter weather in January and February offset by warmer than normal March weather, compared to 2011, when the weather was mild throughout the quarter.

Total heating and cooling degree days were 9% above normal in 2012 and 10% above 2011 levels, driven by warmer than normal March weather. The benefit of above-normal cooling degree days in March was partially offset by heating degree days approximately 50% below normal in the first quarter.

Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 3.4% in the first quarter of 2012, compared to the same period in 2011. The first quarter energy sales shown on the statistical summary that follows reflect the higher sales associated with the late December 2010 cold weather that were included in 2011 energy sales due to the timing of billing cycles, and year-to-year variations in the billing cycles. Higher sales to industrial-phosphate customers were driven by an outage on a phosphate customer’s own generating unit in the first quarter of 2012 and relocation of large electric-driven mining equipment to Tampa Electric’s system. Higher sales to commercial customers reflect improvements in the local economy, and lower sales to the weather-sensitive residential customers are a result of the mild winter weather.

Because the 3.4% increase in energy sales was driven primarily by higher sales to the lower margin interruptible customers, first quarter pretax base revenues were only $1.8 million higher than 2011, reflecting the effects of mild weather on the weather-sensitive residential and small commercial customers. The average number of customers increased 1.0% in the 2012 first quarter as a result of improvements in the Florida economy and Tampa area housing market. First quarter 2012 customer growth was the strongest customer growth since the fourth quarter of 2007.

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Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was essentially unchanged in the first quarter of 2012, compared to the same period in 2011, reflecting lower bad debt expense offset by higher other operating costs. Depreciation and amortization expense increased $1.5 million due to additions to facilities to serve customers.

A summary of Tampa Electric’s regulated operating statistics for the three months ended March 31, 2012 and 2011 follows:

(millions, except average customers)	Operating Revenues								Kilowatt-hour sales
Three months ended Mar. 31,	2012		2011			% Change			2012		2011		% Change
By Customer Type
Residential	$	197.3	$	225.3			(12.4	)		1,725.1		1,973.9		(12.6	)
Commercial		139.9		138.8			0.8			1,393.9		1,391.2		0.2
Industrial – Phosphate		18.4		15.5			18.7			222.7		184.3		20.8
Industrial – Other		24.1		23.3			3.4			258.3		251.4		2.7
Other sales of electricity		42.6		43.1			(1.2	)		416.1		420.2		(1.0	)
Deferred and other revenues(1)		7.5		(33.8	)		(122.2	)
Total energy sales	$	429.8	$	412.2			4.3			4,016.1		4,221.0		(4.9	)
Sales for resale		3.1		6.2			(50.0	)		64.7		105.0		(38.4	)
Other operating revenue		13.7		14.8			(7.4	)		0.0		0.0		0.0
Total revenues	$	446.6	$	433.2			3.1			4,080.8		4,326.0		(5.7	)
Average customers (thousands)		680.8		674.2			1.0
Retail net energy for load (kilowatt hours)										4,256.8		4,115.2		3.4

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

Tampa Electric Company – Natural Gas Division (PGS)

PGS reported net income of $11.0 million for the first quarter, compared to $14.7 million in the same period in 2011. The significantly below normal heating degree days in January and February reduced sales to the weather-sensitive residential customers in the first quarter. In 2011, base revenues included a benefit due to the late December 2010 cold weather due to the timing of billing cycles. Quarterly results reflect a 0.9% higher average number of customers due to improvements in the Florida economy and housing markets. Total therm sales increased 12.3%, driven by a 54.1% increase in gas transported for power generation customers as low natural gas prices made it the more attractive fuel for power generation. This increase was partially offset by a 26.2% decrease in sales to weather-sensitive residential customers due to the very mild winter weather in 2012. Lower therm sales to commercial and industrial customers reflect outages at certain large customers partially offset by a previously idled customer returning to service. Off-system sales decreased in 2012 due to the mild winter weather. Non-fuel operations and maintenance expense increased slightly compared to 2011 levels due to higher outside services costs. Results also reflect slightly higher depreciation expense due to routine plant additions.

A summary of PGS’s regulated operating statistics for the three months ended March 31, 2012 and 2011 follows:

(millions, except average customers)	Operating Revenues							Therms
Three months ended Mar. 31,	2012		2011		% Change			2012		2011		% Change
By Customer Type
Residential	$	40.7	$	56.0		(27.3	)		27.0		36.6		(26.2	)
Commercial		38.6		45.0		(14.2	)		118.3		122.4		(3.3	)
Industrial		2.4		2.5		(4.0	)		55.7		55.7		0.0
Off system sales		13.2		33.7		(60.8	)		44.0		72.7		(39.5	)
Power generation		3.4		2.5		36.0			208.6		116.3		79.4
Other revenues		10.0		13.6		(26.5	)		0.0		0.0		0.0
Total	$	108.3	$	153.3		(29.4	)		453.6		403.7		12.4
By Sales Type
System supply	$	68.6	$	110.8		(38.1	)		82.7		124.6		(33.6	)
Transportation		29.7		28.9		2.8			370.9		279.1		32.9
Other revenues		10.0		13.6		(26.5	)		0.0		0.0		0.0
Total	$	108.3	$	153.3		(29.4	)		453.6		403.7		12.4
Average customers (thousands)		342.0		338.9		0.9

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TECO Coal

TECO Coal reported first quarter net income of $9.8 million on sales of 1.4 million tons, compared to $8.2 million, on sales of 2.1 million tons in the same period of 2011. Results reflected an average net per-ton selling price, excluding transportation allowances, of almost $96 per ton, compared to more than $81 per ton in 2011. TECO Coal’s pretax margin increased $4 per ton in 2012, compared to 2011.

In the first quarter of 2012, the all-in total per-ton cost of production was $87, compared to $76 per ton in the 2011 period. Costs in the first quarter reflect costs associated with idling a section of a mine and other costs associated with reducing production in January, and thus are at the high end of the 2012 cost range. Compared to 2011, costs also reflect higher surface mining costs due to increased diesel fuel usage as a result of trucking coal and overburden further due to the lack of new surface mine permits; higher royalty and severance fees, which are related to selling costs; and spreading fixed costs over fewer tons. TECO Coal’s effective income tax rate in the first quarter of 2012 was 24%, compared to 16% in the 2011 period.

TECO Guatemala

TECO Guatemala reported first quarter net income of $6.6 million in 2012, compared to $6.3 million in 2011. Results reflect lower contract and spot energy sales due to unit availability at the San José Power Station more than offset by higher power prices and lower operating expenses.

Parent / Other

Parent/other cost in the first quarter was $8.3 million, compared to a cost of $9.1 million for the 2011 period. Results in 2012 reflect $0.7 million lower interest expense as a result of the 2011 debt retirement in May of that year.

2012 Guidance and Business Drivers

TECO Energy is maintaining its 2012 earnings per share guidance range between $1.30 and $1.40, excluding charges and gains, and its business drivers are discussed below.

Tampa Electric and Peoples Gas expect to earn within their respective allowed return ranges from customer growth in line with the trends experienced in 2011, and a continued focus on cost management. The guidance assumes normal weather for the remainder of the year for both utilities.

TECO Coal remains at the more than 90% contracted level for its expected 2012 sales of between 7.0 and 7.3 million tons. The average selling price across all products is expected to be more than $96 per ton, which reflects substantially all of the planned 2012 metallurgical sales contracted and priced. The product mix is expected to be about 50% specialty coal, which includes stoker, metallurgical and PCI coals, and the remainder utility steam coal. Metallurgical coal volumes are expected to be at, or slightly above, 2011 levels. The fully-loaded cost of production is expected to be in a range between $83 and $87 per ton. TECO Coal’s effective income tax rate is expected to be about 25% for the full year.

The guidance assumes normal operations for the Alborada Power Station in Guatemala. At the San José Power Station an extended steam turbine overhaul outage is planned, which will reduce energy sales primarily in the fourth quarter, and it is expected to reduce net income approximately $4 million compared to 2011.

This guidance is provided in the form of a range that is dependent on important variables, such as the continued economic and housing market recovery in Florida, weather and customer usage at the Florida utilities, and volumes and margins at TECO Coal.

Income Taxes

The provisions for income taxes from continuing operations for the three month periods ended March 31, 2012 and 2011 were $26.6 million and $28.4 million, respectively. The provision for income taxes for the three months ended March 31, 2012 was impacted by lower operating income, decreased state income taxes and decreased depletion at TECO Coal.

Liquidity and Capital Resources

The table below sets forth the March 31, 2012 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and TEC credit facilities.

At Mar. 31, 2012 (millions)	Consolidated		Tampa Electric Company		Unregulated Companies		Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts/Letters of Credit		44.7		34.7		0.0		10.0
Available credit facilities		630.3		440.3		0.0		190.0
Cash and short-term investments		59.0		10.5		35.7		12.8
Total liquidity	$	689.3	$	450.8	$	35.7	$	202.8

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Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements (see the Credit Facilities section). In addition, TECO Energy, TECO Finance, TEC, and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At March 31, 2012, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at March 31, 2012. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants
(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at March 31,  2012
TEC
Credit facility(2)	Debt/capital	Cannot exceed 65%		47.4	%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%		47.4	%
6.25% senior notes	Debt/capital Limit on liens(3)	Cannot exceed 60% Cannot exceed $700	$	47.4 0 liens outstanding	%
TECO Energy/TECO Finance
Credit facility(2)	Debt/capital	Cannot exceed 65%		56.7	%
TECO Energy 6.75% notes and TECO Finance 6.75% notes	Restrictions on secured debt(4)	(5)		(5)

(1) As defined in each applicable instrument.

(2) SeeNote 6to theTECO Energy, Inc. Consolidated Condensed Financial Statements for a description of the credit facilities.

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

(4) These restrictions would not apply to first mortgage bonds of TEC if any were outstanding.

(5) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by principal property, capital stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes.

Credit Ratings of Senior Unsecured Debt at March 31, 2012
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	Baa1	A-
TECO Energy/TECO Finance	BBB	Baa3	BBB

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

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

Fair Value Measurements

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

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

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The valuation methods used to determine fair value are described inNotes 7 and 13 to theTECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties and the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At March 31, 2012, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with all counterparties were liability positions.

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of critical accounting policies, seeTECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2011.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 16% from Dec. 31, 2011 to March 31, 2012. For natural gas, the company maintained a similar volume hedged as of March 31, 2012 from Dec. 31, 2011.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the 12-month period ended March 31, 2012:

Changes in Fair Value of Derivatives(millions)
Net fair value of derivatives as of Dec. 31, 2011	$	(66.1	)
Additions and net changes in unrealized fair value of derivatives		(30.1	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		21.7
Net fair value of derivatives as of March 31, 2012	$	(74.5	)
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2011	$	(66.1	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(30.1	)
Recorded in earnings		0.0
Realized net settlement of derivatives		21.7
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of March 31, 2012	$	(74.5	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at March 31, 2012:

Maturity and Source of Derivative Contracts Net Assets (Liabilities)(millions)
Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	0.0		$	0.0		$	0.0
Other external sources(1)		(67.9	)		(6.6	)		(74.5	)
Model prices(2)		0.0			0.0			0.0
Total	$	(67.9	)	$	(6.6	)	$	(74.5	)

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

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

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

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Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

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

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

Tampa Electric Company

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

(b) Changes in Internal Controls. There was no change in TEC’s is 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 TEC’s internal control over financial reporting that occurred during TEC’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 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
Jan. 1, 2012 – Jan. 31, 2012		927	$	19.03		0.0	$	0.0
Feb. 1, 2012 – Feb. 29, 2012		7,151	$	18.11		0.0	$	0.0
Mar. 1, 2012 – Mar. 31, 2012		2,786	$	17.57		0.0	$	0.0
Total 1st Quarter 2012		10,864	$	18.05		0.0	$	0.0

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

Item 4. MINE SAFETY INFORMATION

TECO Coal is subject to regulation by the Federal MSHA under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included inExhibit 95 to this quarterly report.

Item 6. EXHIBITS

Exhibits - See index on page 47.

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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: May 4, 2012	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting
		and Chief Financial Officer
		(Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

	TAMPA ELECTRIC COMPANY
	(Registrant)
Date: May 4, 2012	By:	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting
		and Chief Financial Officer
		(Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

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INDEX TO EXHIBITS

Exhibit No.	Description
3.1	Articles of Incorporation of TECO Energy, Inc., as amended on Apr. 20, 1993 (Exhibit 3, Form 10-Q for the quarter ended Mar. 31, 1993 of TECO Energy, Inc.).	*
3.2	Bylaws of TECO Energy, Inc., as amended effective May 4, 2011 (Exhibit 3.1, Form 8-K dated May 4, 2011 of TECO Energy, Inc.).	*
3.3	Articles of Incorporation of Tampa Electric Company (Exhibit 3 to Registration Statement No. 2-70653 of Tampa Electric Company).	*
3.4	Bylaws of Tampa Electric Company, as amended effective Feb. 2, 2011 (Exhibit 3.4, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.
12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.
31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(1)
32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1)
95	Mine Safety Disclosure
101.INS	XBRL Instance Document	**
101.SCH	XBRL Taxonomy Extension Schema Document	**
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	**
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	**
101.LAB	XBRL Taxonomy Extension Label Linkbase Document	**
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	**

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

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

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

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