TECO Energy 10-Q 2013 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, 2013

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 26, 2013 was 217,583,226. As of April 26, 2013, 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 52

Index to Exhibits appears on page 52.

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

2

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

3

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, 2013 and Dec. 31, 2012, and the results of their operations and cash flows for the periods ended March 31, 2013 and 2012. The results of operations for the three month period ended March 31, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013. 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, 2012 and to the notes on pages 10 through 26 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, March 31, 2013 and Dec. 31, 2012		5-6
Consolidated Condensed Statements of Income for the three month periods ended March 31, 2013 and 2012		7
Consolidated Condensed Statements of Comprehensive Income for the three month periods ended March  31, 2013 and 2012		8
Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2013 and 2012		9
Notes to Consolidated Condensed Financial Statements		10-26

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.

4

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2013			2012
Current assets
Cash and cash equivalents	$	212.9		$	200.5
Receivables, less allowance for uncollectibles of $4.2 at Mar. 31, 2013 and Dec. 31, 2012		269.7			282.7
Inventories, at average cost
Fuel		146.1			123.6
Materials and supplies		81.0			82.1
Derivative assets		11.8			0.0
Regulatory assets		52.7			70.3
Deferred income taxes		65.7			63.3
Prepayments and other current assets		33.3			33.9
Income tax receivables		0.0			0.4
Total current assets		873.2			856.8
Property, plant and equipment
Utility plant in service
Electric		6,694.0			6,655.8
Gas		1,260.5			1,228.3
Construction work in progress		333.4			336.1
Other property		443.9			443.8
Property, plant and equipment, at original costs		8,731.8			8,664.0
Accumulated depreciation		(2,754.5	)		(2,695.5	)
Total property, plant and equipment, net		5,977.3			5,968.5
Other assets
Regulatory assets		377.4			382.6
Derivative assets		1.0			0.2
Deferred charges and other assets		124.9			126.8
Total other assets		503.3			509.6
Total assets	$	7,353.8		$	7,334.9

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

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets– continued

Unaudited

Liabilities and Capital	Mar. 31,			Dec. 31,
(millions)	2013			2012
Current liabilities
Accounts payable	$	207.8		$	232.8
Customer deposits		163.9			162.9
Regulatory liabilities		118.3			105.6
Derivative liabilities		0.9			14.6
Interest accrued		55.3			33.2
Taxes accrued		48.3			32.1
Other		20.0			19.9
Total current liabilities		614.5			601.1
Other liabilities
Deferred income taxes		304.8			277.9
Investment tax credits		9.6			9.7
Regulatory liabilities		622.5			631.4
Derivative liabilities		0.3			0.6
Deferred credits and other liabilities		535.9			549.7
Long-term debt		2,972.7			2,972.7
Total other liabilities		4,445.8			4,442.0
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 217.5 million and 216.6 million shares outstanding at Mar. 31, 2013 and Dec. 31, 2012, respectively)		217.5			216.6
Additional paid in capital		1,570.4			1,564.5
Retained earnings		535.5			541.7
Accumulated other comprehensive loss		(29.9	)		(31.0	)
Total capital		2,293.5			2,291.8
Total liabilities and capital	$	7,353.8		$	7,334.9

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

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Mar. 31,
(millions, except per share amounts)		2013			2012
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $25.4 in 2013 and $26.1 in 2012)		$	539.1		$	556.4
Unregulated			122.0			140.7
Total revenues			661.1			697.1
Expenses
Regulated operations and maintenance
Fuel			140.0			157.5
Purchased power			14.6			28.2
Cost of natural gas sold			49.5			41.6
Other			120.8			112.2
Operation and maintenance other expense
Mining related costs			95.5			103.9
Other			1.3			1.7
Depreciation and amortization			82.0			81.2
Taxes, other than income			53.3			56.0
Total expenses			557.0			582.3
Income from continuing operations			104.1			114.8
Other income
Allowance for other funds used during construction			1.1			0.4
Other income			1.6			1.8
Total other income			2.7			2.2
Interest charges
Interest expense			43.0			48.5
Allowance for borrowed funds used during construction			(0.6	)		(0.2	)
Total interest charges			42.4			48.3
Income from continuing operations before provision for income taxes			64.4			68.7
Provision for income taxes			23.2			24.1
Net income from continuing operations			41.2			44.6
Discontinued operations
Income from discontinued operations			0.4			8.4
Provision for income taxes			0.1			2.4
Income from discontinued operations, net			0.3			6.0
Less: Income from discontinued operations attributable to noncontrolling interest			0.0			0.1
Income from discontinued operations attributable to TECO Energy, net			0.3			5.9
Net income attributable to TECO Energy		$	41.5		$	50.5
Average common shares outstanding	– Basic		214.6			213.9
	– Diluted		215.6			215.3
Earnings per share from continuing operations	– Basic	$	0.19		$	0.21
	– Diluted	$	0.19		$	0.20
Earnings per share from discontinued operations	– Basic	$	0.00		$	0.03
	– Diluted	$	0.00		$	0.03
Earnings per share attributable to TECO Energy	– Basic	$	0.19		$	0.24
	– Diluted	$	0.19		$	0.23
Dividends paid per common share outstanding		$	0.22		$	0.22

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2013		2012
Net income attributable to TECO Energy	$	41.5	$	50.5
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges		0.4		1.5
Amortization of unrecognized benefit costs		0.7		0.1
Other comprehensive income, net of tax		1.1		1.6
Comprehensive income attributable to TECO Energy	$	42.6	$	52.1

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2013			2012
Cash flows from operating activities
Net income attributable to TECO Energy	$	41.5		$	50.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		82.0			83.0
Deferred income taxes		23.4			24.8
Investment tax credits		(0.1	)		0.0
Allowance for other funds used during construction		(1.1	)		(0.4	)
Non-cash stock compensation		3.6			2.5
Gain on sales of business/assets, pretax		(0.2	)		0.0
Deferred recovery clauses		4.5			(20.5	)
Receivables, less allowance for uncollectibles		13.0			49.3
Inventories		(21.4	)		(9.5	)
Prepayments and other current assets		0.6			2.2
Taxes accrued		15.8			13.9
Interest accrued		22.1			20.6
Accounts payable		(25.0	)		1.7
Other		(0.8	)		5.8
Cash flows from operating activities		157.9			223.9
Cash flows from investing activities
Capital expenditures		(103.0	)		(117.4	)
Allowance for other funds used during construction		1.1			0.4
Net proceeds from sales of business/assets		0.3			0.0
Cash flows used in investing activities		(101.6	)		(117.0	)
Cash flows from financing activities
Dividends		(47.8	)		(47.5	)
Proceeds from the sale of common stock		3.9			0.3
Repayment of long-term debt/Purchase in lieu of redemption		0.0			(88.7	)
Net increase in short-term debt		0.0			44.0
Cash flows used in financing activities		(43.9	)		(91.9	)
Net increase in cash and cash equivalents		12.4			15.0
Cash and cash equivalents at beginning of the period		200.5			44.0
Cash and cash equivalents at end of the period	$	212.9		$	59.0

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

9

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See the company’s 2012 Annual Report on Form 10-K for a complete detailed discussion of 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. For the periods presented, no VIEs have been consolidated in continuing operations (seeNote 14).

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 TECO Energy, Inc. and its subsidiaries as of March 31, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended March 31, 2013 and 2012. The results of operations for the three months ended March 31, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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 U.S. GAAP.

Revenues

As of March 31, 2013 and Dec. 31, 2012, unbilled revenues of $48.1 million and $49.0 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 $25.4 million and $26.1 million for the three months ended March 31, 2013 and 2012, 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.

Reclassifications

Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TECO Energy’s net income in any period.

2. New Accounting Pronouncements

Comprehensive Income

In February 2013, the FASB issued guidance requiring improved disclosures of significant reclassifications out of AOCI and their corresponding effect on net income. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2012. The company has adopted this guidance as required. It has no effect on the company’s results of operations, financial position or cash flows.

10

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.

Base Rates-Tampa Electric

Tampa Electric’s 2013 and 2012 results reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

On Feb. 4, 2013, Tampa Electric delivered a letter to the FPSC notifying it of its intent to file a request for an increase in its retail base rates and service charges. On April 5, 2013, Tampa Electric filed a petition with the FPSC requesting, among other things, a permanent increase in rates and service charges sufficient to generate additional annual revenues of approximately $134.8 million, to be effective on or after Jan. 1, 2014. The request provides for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requests certain changes to existing rate schedules, as well as the adoption of new rate designs.

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 $51.5 million and $50.4 million as of March 31, 2013 and Dec. 31, 2012, 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 in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year.

11

Details of the regulatory assets and liabilities as of March 31, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset(1)	$	67.0	$	67.2
Other:
Cost-recovery clauses		25.0		42.9
Postretirement benefit asset		272.1		276.1
Deferred bond refinancing costs(2)		8.9		9.2
Environmental remediation		46.9		46.9
Competitive rate adjustment		4.4		4.1
Other		5.8		6.5
Total other regulatory assets		363.1		385.7
Total regulatory assets		430.1		452.9
Less: Current portion		52.7		70.3
Long-term regulatory assets	$	377.4	$	382.6
Regulatory liabilities:
Regulatory tax liability(1)	$	14.2	$	14.6
Other:
Cost-recovery clauses		86.7		73.9
Transmission and delivery storm reserve		51.5		50.4
Deferred gain on property sales(3)		3.0		3.4
Provision for stipulation and other		2.2		1.0
Accumulated reserve - cost of removal		583.2		593.7
Total other regulatory liabilities		726.6		722.4
Total regulatory liabilities		740.8		737.0
Less: Current portion		118.3		105.6
Long-term regulatory liabilities	$	622.5	$	631.4

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

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

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

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

Regulatory Assets
(millions)	Mar. 31, 2013		Dec. 31, 2012
Clause recoverable(1)	$	29.4	$	47.0
Components of rate base(2)		274.9		279.1
Regulatory tax assets(3)		67.0		67.2
Capital structure and other(3)		58.8		59.6
Total	$	430.1	$	452.9

(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.

12

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 2011 consolidated federal income tax return during 2012. The U.S. federal statute of limitations remains open for years 2009 and onward. Years 2012 and 2013 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2013. U.S. state jurisdictions have statutes of limitations generally ranging from three to four 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 2009 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation and maintenance 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 2013, the company recorded an immaterial amount of pretax charges for interest only.

The effective tax rate increased to 35.95% for the three months ended March 31, 2013 from 35.13% for the same period in 2012.

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,	2013			2012			2013			2012
Components of net periodic benefit expense
Service cost	$	4.8		$	4.4		$	0.7		$	0.7
Interest cost on projected benefit obligations		7.2			7.4			2.3			2.5
Expected return on assets		(9.7	)		(9.6	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			0.4
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		0.2
Actuarial loss		5.0			3.7			0.3			0.0
Net pension expense recognized in the
Consolidated Condensed Statements of Income	$	7.2		$	5.8		$	3.2		$	3.8

For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. Additionally, TECO Energy made contributions of $14.7 million to its pension plan in the first quarter of 2013.

For the three months ended March 31, 2013, TECO Energy and its subsidiaries reclassed $1.1 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, 2013, TEC reclassed $4.0 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

13

6. Short-Term Debt

At March 31, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2013						Dec. 31, 2012
(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	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility(2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	1.5	$	675.0	$	0.0	$	1.5

(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, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at March 31, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 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. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 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

Fair Value of Long-Term Debt

At March 31, 2013, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,426.6 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,439.4 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.

14

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended March 31, 2013 and 2012, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Mar. 31,
(millions)	Gross			Tax			Net
2013
Unrealized gain on cash flow hedges	$	0.3		$	(0.1	)	$	0.2
Reclassification from AOCI to net income(1)		0.3			(0.1	)		0.2
Gain on cash flow hedges		0.6			(0.2	)		0.4
Amortization of unrecognized benefit costs(2)		1.1			(0.4	)		0.7
Total other comprehensive income	$	1.7		$	(0.6	)	$	1.1
2012
Unrealized gain on cash flow hedges	$	2.5		$	(0.9	)	$	1.6
Reclassification from AOCI to net income(1)		(0.2	)		0.1			(0.1	)
Gain on cash flow hedges		2.3			(0.8	)		1.5
Amortization of unrecognized benefit costs(2)		0.7			(0.6	)		0.1
Total other comprehensive income	$	3.0		$	(1.4	)	$	1.6

(1) Related to interest rate contracts recognized in Interest expense and commodity contracts recognized in Mining related costs.

(2) Related to postretirement benefits. SeeNote 5 for additional information.

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2013			Dec. 31, 2012
Unrecognized pension loss and prior service credit(1)	$	(32.2	)	$	(32.9	)
Unrecognized other benefit loss, prior service cost and transition obligation(2)		11.1			11.1
Net unrealized losses from cash flow hedges(3)		(8.8	)		(9.2	)
Total accumulated other comprehensive loss	$	(29.9	)	$	(31.0	)

(1) Net of tax benefit of $19.7 million and $20.1 million as of Mar. 31, 2013 and Dec. 31, 2012, respectively.

(2) Net of tax expense of $6.7 million and $6.7 million as of Mar. 31, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax benefit of $5.5 million and $5.8 million as of Mar. 31, 2013 and Dec. 31, 2012, respectively.

15

9. Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2013(1)			2012(1)
Basic earnings per share
Net income from continuing operations	$	41.2		$	44.6
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to common shareholders - Basic	$	41.1		$	44.4
Income from discontinued operations attributable to TECO Energy, net	$	0.3		$	5.9
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.3		$	5.9
Net income attributable to TECO Energy	$	41.5		$	50.5
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	41.4		$	50.3
Average common shares outstanding - Basic		214.6			213.9
Earnings per share from continuing operations available to common shareholders - Basic	$	0.19		$	0.21
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		$	0.03
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.19		$	0.24
Diluted earnings per share
Net income from continuing operations	$	41.2		$	44.6
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to common shareholders - Diluted	$	41.1		$	44.4
Income from discontinued operations attributable to TECO Energy, net	$	0.3		$	5.9
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.3		$	5.9
Net income attributable to TECO Energy	$	41.5		$	50.5
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	41.4		$	50.3
Unadjusted average common shares outstanding - Diluted		214.6			213.9
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		1.0			1.4
Average common shares outstanding - Diluted		215.6			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.19		$	0.20
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		$	0.03
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.19		$	0.23
Anti-dilutive shares		0.0			1.4

(1) Periods presented reflect the classification of TECO Guatemala as discontinued operations (seeNote 15).

16

10. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas, and an outage in the natural gas service to Lee and Collier counties. Two commercial PGS customers filed a purported class action in Lee County Circuit Court against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. A hearing was held in January 2013 on the plaintiffs’ request that the court certify the suit as a class action; to date the court has not made a ruling. PGS filed suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident, and Posen Construction counter-claimed against PGS alleging negligence. In addition, the Posen Construction employee operating the heavy equipment involved in the incident has filed suit in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries.

Three former or inactive TEC employees are maintaining a suit against TEC in Hillsborough County Circuit Court for personal injuries allegedly caused by exposure to a chemical substance at one of TEC’s power stations. The suit was originally filed in 2002 and recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected in the first half of 2014.

The company believes the claims in each of the pending actions described above in this item are without merit and intends to defend each matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters.

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, 2013, TEC has estimated its ultimate financial liability to be $37.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. 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 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.

Environmental Protection Agency 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) (the “114 Letter”) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. The 114 Letter is a request for information, however, TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter.

17

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of March 31, 2013 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2013		2014-2017		After  (1) 2017		Total		Liabilities Recognized at Mar. 31, 2013
TECO Coal
Fuel purchase related(2)	$	0.0	$	1.4	$	4.0	$	5.4	$	1.5
Other subsidiaries
Guaranty under sale agreement (3)		0.0		4.9		0.0		4.9		4.9
Fuel purchase/energy management(2)		0.0		0.0		102.3		102.3		0.6
Total	$	0.0	$	6.3	$	106.3	$	112.6	$	7.0

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After  (1) 2017		Total		Liabilities Recognized at Mar. 31, 2013
Tampa Electric(2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2017.

(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, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement. SeeNote 15 for additional information.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At March 31, 2013, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

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

18

Segment Information(1)
(millions)	Tampa		Peoples		TECO			TECO		Other &			TECO
Three months ended Mar. 31,	Electric		Gas		Coal			Guatemala (2)		Eliminations			Energy
2013
Revenues - external	$	417.8	$	121.9	$	117.9		$	0.0	$	3.5		$	661.1
Sales to affiliates		0.2		0.0		0.0			0.0		(0.2	)		0.0
Total revenues		418.0		121.9		117.9			0.0		3.3			661.1
Depreciation and amortization		59.0		13.0		9.7			0.0		0.3			82.0
Total interest charges (1)		23.4		3.4		1.7			0.0		13.9			42.4
Internally allocated interest(1)		0.0		0.0		1.6			0.0		(1.6	)		0.0
Provision (benefit) for income taxes		19.8		8.7		(0.1	)		0.0		(5.2	)		23.2
Net income (loss) from continuing operations		31.8		13.8		3.0			0.0		(7.4	)		41.2
Income (loss) from discontinued operations attributable to TECO Energy, net		0.0		0.0		0.0			0.0		0.3			0.3
Net income (loss)	$	31.8	$	13.8	$	3.0		$	0.0	($	7.1	)	$	41.5
2012
Revenues - external	$	446.3	$	110.0	$	138.4		$	0.0	$	2.4		$	697.1
Sales to affiliates		0.3		0.2		0.0			0.0		(0.5	)		0.0
Total revenues		446.6		110.2		138.4			0.0		1.9			697.1
Depreciation and amortization		57.4		12.6		10.8			0.0		0.4			81.2
Total interest charges (1)		30.0		4.4		1.8			0.0		12.1			48.3
Internally allocated interest(1)		0.0		0.0		1.7			0.0		(1.7	)		0.0
Provision (benefit) for income taxes		18.9		6.9		3.1			0.0		(4.8	)		24.1
Net income (loss) from continuing operations		31.4		11.0		9.8			0.0		(7.6	)		44.6
Income (loss) from discontinued operations attributable to TECO Energy, net		0.0		0.0		0.0			6.6		(0.7	)		5.9
Net income (loss)	$	31.4	$	11.0	$	9.8		$	6.6	($	8.3	)	$	50.5
At Mar. 31, 2013
Total assets	$	6,045.9	$	1,013.8	$	344.1		$	0.0	($	50.0	)	$	7,353.8
At Dec. 31, 2012
Total assets	$	6,042.3	$	1,009.9	$	356.6		$	164.9	($	238.8	)	$	7,334.9

(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 2013 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. Revenues for TECO Guatemala that were reclassified to discontinued operations were $32.9 million for the three months ended Mar. 31, 2012. There were no revenues reclassified for the three months ended Mar. 31, 2013. SeeNote 15 for additional information.

12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

19

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, 2013, 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, 2013 and Dec. 31, 2012:

Total Derivatives (1)
(millions)	Mar. 31, 2013		Dec. 31, 2012
Current assets	$	11.8	$	0.0
Long-term assets		1.0		0.2
Total assets	$	12.8	$	0.2
Current liabilities	$	0.9	$	14.6
Long-term liabilities		0.3		0.6
Total liabilities	$	1.2	$	15.2

(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 gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at March 31, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Mar. 31, 2013
Description
Derivative assets	$	15.1		$	(2.3	)	$	12.8
Derivative liabilities	$	(3.5	)	$	2.3		$	(1.2	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

20

The following table presents the derivative hedges of diesel fuel contracts at March 31, 2013 and Dec. 31, 2012 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, 2013		Dec. 31, 2012
Current assets	$	0.0	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.0	$	0.0
Current liabilities	$	0.3	$	0.5
Long-term liabilities		0.3		0.4
Total liabilities	$	0.6	$	0.9

The following table presents the derivative hedges of natural gas contracts at March 31, 2013 and Dec. 31, 2012 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, 2013		Dec. 31, 2012
Current assets	$	11.8	$	0.0
Long-term assets		1.0		0.2
Total assets	$	12.8	$	0.2
Current liabilities	$	0.6	$	14.1
Long-term liabilities		0.0		0.2
Total liabilities	$	0.6	$	14.3

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at March 31, 2013 is a net loss of $8.8 million after tax and accumulated amortization. This compares to a net loss of $9.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at March 31, 2013 and Dec. 31, 2012:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Mar. 31, 2013	Location	Value		Location	Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.0	Derivative liabilities	$	0.3
Long-term	Derivative assets		0.0	Derivative liabilities		0.3
Natural gas derivatives:
Current	Derivative assets		11.8	Derivative liabilities		0.6
Long-term	Derivative assets		1.0	Derivative liabilities		0.0
Total derivatives designated as hedging instruments		$	12.8		$	1.2

21

	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Dec. 31, 2012	Location	Value		Location	Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.0	Derivative liabilities	$	0.5
Long-term	Derivative assets		0.0	Derivative liabilities		0.4
Natural gas derivatives:
Current	Derivative assets		0.0	Derivative liabilities		14.1
Long-term	Derivative assets		0.2	Derivative liabilities		0.2
Total derivatives designated as hedging instruments		$	0.2		$	15.2

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of March 31, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Mar. 31, 2013	Location(1)	Value		Location(1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	11.8	Regulatory assets	$	0.6
Long-term	Regulatory liabilities		1.0	Regulatory assets		0.0
Total		$	12.8		$	0.6

(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Dec. 31, 2012	Location (1)	Value		Location(1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.0	Regulatory assets	$	14.1
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.2
Total		$	0.2		$	14.3

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

Based on the fair value of the instruments at March 31, 2013, net pretax gains of $11.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

22

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)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.2	Mining related costs		0.0
Total	$	0.2		($	0.2	)
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

(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, 2013 and 2012, 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
2013
Interest rate swaps	$	0.0		$	0.0	($	0.2	)
Diesel fuel derivatives		(0.6	)		0.2		0.0
Total	($	0.6	)	$	0.2	($	0.2	)
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

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

23

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2015 for financial natural gas and Dec. 31, 2014 for financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2013		0.0		2.2		0.0		32.3
2014		0.0		1.5		0.0		9.0
2015		0.0		0.0		0.0		1.1
Total		0.0		3.7		0.0		42.4

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, 2013, 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.

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, 2013:

Contingent Features
(millions) At Mar. 31, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	1.1	)	($	1.1	)	$	0.0

24

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, 2013 and Dec. 31, 2012. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Mar. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	12.8	$	0.0	$	12.8
Diesel fuel swaps		0.0		0.0		0.0		0.0
Total	$	0.0	$	12.8	$	0.0	$	12.8
Liabilities
Natural gas swaps	$	0.0	$	0.6	$	0.0	$	0.6
Diesel fuel swaps		0.0		0.6		0.0		0.6
Total	$	0.0	$	1.2	$	0.0	$	1.2

	At fair value as of Dec. 31, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.0		0.0		0.0
Total	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas swaps	$	0.0	$	14.3	$	0.0	$	14.3
Diesel fuel swaps		0.0		0.9		0.0		0.9
Total	$	0.0	$	15.2	$	0.0	$	15.2

Natural gas and diesel fuel swaps are OTC 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, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

14. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, 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 $4.9 million and $22.5 million of capacity pursuant to PPAs for the three months ended March 31, 2013 and 2012, 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

25

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 for the three months ended March 31, 2012. This PPA expired on Dec. 31, 2012.

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.

15. Discontinued Operations

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. The following table provides selected components of discontinued operations:

Components of income from discontinued operations attributable to TECO Energy
(millions)
Three months ended Mar. 31,	2013		2012
Revenues	$	0.0	$	32.9
Income from operations		0.4		8.4
Income from discontinued operations		0.4		8.4
Provision for income taxes		0.1		2.4
Income from discontinued operations, net		0.3		6.0
Less: Income from discontinued operations attributable to noncontrolling interest		0.0		0.1
Income from discontinued operations attributable to TECO Energy, net	$	0.3	$	5.9

16. Subsequent Events

Tampa Electric Rate Case Proceeding

On Feb. 4, 2013, Tampa Electric delivered a letter to the FPSC notifying it of its intent to file a request for an increase in its retail base rates and service charges. On April 5, 2013, Tampa Electric filed a petition with the FPSC requesting, among other things, a permanent increase in rates and service charges sufficient to generate additional total annual revenues of approximately $134.8 million, to be effective on or after Jan. 1, 2014. The request provides for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requests certain changes to existing rate schedules, as well as the adoption of new rate designs. SeeNote 3for additional information.

26

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, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended March 31, 2013 and 2012. The results of operations for the three month period ended March 31, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013. 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, 2012 and to the notes on pages 32 through 42 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, March 31, 2013 and Dec. 31, 2012		28-39
Consolidated Condensed Statements of Income and Comprehensive Income for the three month periods ended March 31, 2013 and 2012		30
Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2013 and 2012		31
Notes to Consolidated Condensed Financial Statements		32-42

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.

27

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2013			2012
Property, plant and equipment
Utility plant in service
Electric	$	6,694.0		$	6,654.5
Gas		1,204.1			1,171.9
Construction work in progress		332.0			335.0
Utility plant in service, at original costs		8,230.1			8,161.4
Accumulated depreciation		(2,427.2	)		(2,373.6	)
		5,802.9			5,787.8
Other property, net		7.4			7.3
Total property, plant and equipment, net		5,810.3			5,795.1
Current assets
Cash and cash equivalents		60.0			45.2
Receivables, less allowance for uncollectibles of $1.5 at Mar. 31, 2013 and Dec. 31, 2012		211.5			213.8
Inventories, at average cost
Fuel		107.2			89.1
Materials and supplies		71.5			72.4
Regulatory assets		52.7			70.3
Derivative assets		11.8			0.0
Taxes receivable		0.0			22.1
Deferred income taxes		20.6			20.0
Prepayments and other current assets		11.6			11.5
Total current assets		546.9			544.4
Deferred debits
Unamortized debt expense		15.8			16.1
Regulatory assets		377.4			382.6
Derivative assets		1.0			0.2
Other		3.2			6.2
Total deferred debits		397.4			405.1
Total assets	$	6,754.6		$	6,744.6

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

28

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	Mar. 31,			Dec. 31,
(millions)	2013			2012
Capitalization
Common stock	$	1,970.4		$	1,970.4
Accumulated other comprehensive loss		(8.5	)		(8.7	)
Retained earnings		295.2			304.6
Total capital		2,257.1			2,266.3
Long-term debt		1,932.6			1,932.6
Total capitalization		4,189.7			4,198.9
Current liabilities
Accounts payable		167.5			188.6
Customer deposits		163.9			163.0
Regulatory liabilities		118.3			105.6
Derivative liabilities		0.6			14.1
Interest accrued		37.5			17.3
Taxes accrued		30.7			13.7
Other		11.7			11.8
Total current liabilities		530.2			514.1
Deferred credits
Deferred income taxes		1,005.1			980.9
Investment tax credits		9.6			9.7
Derivative liabilities		0.0			0.2
Regulatory liabilities		622.5			631.4
Other		397.5			409.4
Total deferred credits		2,034.7			2,031.6
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	6,754.6		$	6,744.6

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

29

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2013			2012
Revenues
Electric (includes franchise fees and gross receipts taxes of $19.0 in 2013 and $19.9 in 2012)	$	417.9		$	446.5
Gas (includes franchise fees and gross receipts taxes of $6.4 in 2013 and $6.2 in 2012)		121.9			110.0
Total revenues		539.8			556.5
Expenses
Regulated operations and maintenance
Fuel		140.0			157.5
Purchased power		14.6			28.2
Cost of natural gas sold		49.5			41.6
Other		120.6			112.1
Depreciation and amortization		72.0			70.0
Taxes, other than income		44.5			45.4
Total expenses		441.2			454.8
Income from operations		98.6			101.7
Other income
Allowance for other funds used during construction		1.1			0.4
Other income, net		1.2			0.5
Total other income		2.3			0.9
Interest charges
Interest on long-term debt		26.5			31.7
Other interest		0.9			2.9
Allowance for borrowed funds used during construction		(0.6	)		(0.2	)
Total interest charges		26.8			34.4
Income before provision for income taxes		74.1			68.2
Provision for income taxes		28.5			25.8
Net income		45.6			42.4
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges		0.2			0.1
Total other comprehensive income, net of tax		0.2			0.1
Comprehensive income	$	45.8		$	42.5

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

30

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2013			2012
Cash flows from operating activities
Net income	$	45.6		$	42.4
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		72.0			70.0
Deferred income taxes		23.3			31.0
Investment tax credits		(0.1	)		0.0
Allowance for funds used during construction		(1.1	)		(0.4	)
Gain on sale of business/assets, pretax		0.0			(0.1	)
Deferred recovery clauses		4.5			(20.5	)
Receivables, less allowance for uncollectibles		2.2			11.2
Inventories		(17.2	)		15.1
Prepayments		(0.1	)		0.9
Taxes accrued		39.1			23.9
Interest accrued		20.2			18.5
Accounts payable		(21.1	)		6.6
Other		(0.7	)		5.3
Cash flows from operating activities		166.6			203.9
Cash flows from investing activities
Capital expenditures		(97.9	)		(104.6	)
Allowance for funds used during construction		1.1			0.4
Net proceeds from sale of assets		0.0			0.3
Cash flows used in investing activities		(96.8	)		(103.9	)
Cash flows from financing activities
Repayment of long-term debt/Purchase in lieu of redemption		0.0			(86.0	)
Net increase in short-term debt		0.0			34.0
Dividends		(55.0	)		(51.4	)
Cash flows used in financing activities		(55.0	)		(103.4	)
Net increase (decrease) in cash and cash equivalents		14.8			(3.4	)
Cash and cash equivalents at beginning of period		45.2			13.9
Cash and cash equivalents at end of period	$	60.0		$	10.5

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

31

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2012 Annual Report on Form 10-K for a complete detailed discussion of 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. 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, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended March 31, 2013 and 2012. The results of operations for the three months ended March 31, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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 U.S. GAAP.

Revenues

As of March 31, 2013 and Dec. 31, 2012, unbilled revenues of $48.1 million and $49.0 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 $25.4 million and $26.1 million for the three months ended March 31, 2013 and 2012, 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.

Reclassifications

Certain reclassifications were made to prior year amounts to conform to current period presentation. Income tax expense related to regulated operations was previously included within income from operations as it is part of the determination of utility revenue requirements. Income tax expense is now presented directly above net income to conform to the TECO Energy, Inc. presentation. For prior periods, this change results in an increase in income from operations for the amount of income tax expense reclassified. None of the reclassifications affected TEC’s net income in any period.

2. New Accounting Pronouncements

Comprehensive Income

In February 2013, the FASB issued guidance requiring improved disclosures of significant reclassifications out of AOCI and their corresponding effect on net income. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2012. TEC has adopted this guidance as required. It will have no effect on TEC’s results of operations, financial position or cash flows.

32

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.

Base Rates-Tampa Electric

Tampa Electric’s 2013 and 2012 results reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

On Feb. 4, 2013, Tampa Electric delivered a letter to the FPSC notifying it of its intent to file a request for an increase in its retail base rates and service charges. On April 5, 2013, Tampa Electric filed a petition with the FPSC requesting, among other things, a permanent increase in rates and service charges sufficient to generate additional annual revenues of approximately $134.8 million, to be effective on or after Jan. 1, 2014. The request provides for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requests certain changes to existing rate schedules, as well as the adoption of new rate designs.

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 $51.5 million and $50.4 million as of March 31, 2013 and Dec. 31, 2012, 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 in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year.

33

Details of the regulatory assets and liabilities as of March 31, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset(1)	$	67.0	$	67.2
Other:
Cost-recovery clauses		25.0		42.9
Postretirement benefit asset		272.1		276.1
Deferred bond refinancing costs(2)		8.9		9.2
Environmental remediation		46.9		46.9
Competitive rate adjustment		4.4		4.1
Other		5.8		6.5
Total other regulatory assets		363.1		385.7
Total regulatory assets		430.1		452.9
Less: Current portion		52.7		70.3
Long-term regulatory assets	$	377.4	$	382.6
Regulatory liabilities:
Regulatory tax liability(1)	$	14.2	$	14.6
Other:
Cost-recovery clauses		86.7		73.9
Transmission and delivery storm reserve		51.5		50.4
Deferred gain on property sales(3)		3.0		3.4
Provision for stipulation and other		2.2		1.0
Accumulated reserve - cost of removal		583.2		593.7
Total other regulatory liabilities		726.6		722.4
Total regulatory liabilities		740.8		737.0
Less: Current portion		118.3		105.6
Long-term regulatory liabilities	$	622.5	$	631.4

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

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

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

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

Regulatory Assets
(millions)	Mar. 31, 2013		Dec. 31, 2012
Clause recoverable(1)	$	29.4	$	47.0
Components of rate base(2)		274.9		279.1
Regulatory tax assets(3)		67.0		67.2
Capital structure and other(3)		58.8		59.6
Total	$	430.1	$	452.9

(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, 2013 and 2012 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

34

The IRS concluded its examination of the company’s 2011 consolidated federal income tax return during 2012. The U.S. federal statute of limitations remains open for the year 2009 and onward. Years 2012 and 2013 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2013. 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 2009 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, 2013 and 2012, respectively, was $5.3 million and $4.2 million for pension benefits, and $2.6 million and $3.1 million for other postretirement benefits.

For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. Additionally, TECO Energy made contributions of $14.7 million to its pension plan in the first quarter of 2013. TEC’s portion of the contributions was $11.6 million.

Included in the benefit expenses discussed above, for the three months ended March 31, 2013, TEC reclassed $4.0 million of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

At March 31, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2013						Dec. 31, 2012
(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	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	0.0	$	1.5	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

At March 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at March 31, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 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. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 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

Fair Value of Long-Term Debt

At March 31, 2013, TEC’s total long-term debt had a carrying amount of $1,932.6 million and an estimated fair market value of $2,237.5 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $1,932.6 million and an estimated fair market value of $2,270.3 million. TEC uses the market approach in determining fair value. The majority of the

35

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. 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.

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas, and an outage in the natural gas service to Lee and Collier counties. Two commercial PGS customers filed a purported class action in Lee County Circuit Court against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. A hearing was held in January 2013 on the plaintiffs’ request that the court certify the suit as a class action; to date the court has not made a ruling. PGS filed suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident, and Posen Construction counter-claimed against PGS alleging negligence. In addition, the Posen Construction employee operating the heavy equipment involved in the incident has filed suit in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries.

Three former or inactive TEC employees are maintaining a suit against TEC in Hillsborough County Circuit Court for personal injuries allegedly caused by exposure to a chemical substance at one of TEC’s power stations. The suit was originally filed in 2002 and recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected in the first half of 2014.

The company believes the claims in each of the pending actions described above in this item are without merit and intends to defend each matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters.

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, 2013, TEC has estimated its ultimate financial liability to be $37.5 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. 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 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.

Environmental Protection Agency 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) (the “114 Letter”) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. The 114 Letter is a request for information, however, TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter.

36

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, 2013 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After  (1) 2017		Total		Liabilities Recognized at Mar. 31, 2013
Tampa Electric(2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2017.

(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 Mar. 31, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At March 31, 2013, 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
2013
Revenues - external	$	417.9	$	121.9	$	0.0		$	539.8
Sales to affiliates		0.1		0.0		(0.1	)		0.0
Total revenues		418.0		121.9		(0.1	)		539.8
Depreciation and amortization		59.0		13.0		0.0			72.0
Total interest charges		23.4		3.4		0.0			26.8
Provision for income taxes		19.8		8.7		0.0			28.5
Net income	$	31.8	$	13.8	$	0.0		$	45.6
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
Total assets at Mar. 31, 2013	$	5,779.8	$	977.9	($	3.1	)	$	6,754.6
Total assets at Dec. 31, 2012	$	5,760.4	$	970.9	$	13.3		$	6,744.6

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

37

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.

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, 2013, 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, 2013 and Dec. 31, 2012 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:

(millions)	2013		2012
Current assets	$	11.8	$	0.0
Long-term assets		1.0		0.2
Total assets	$	12.8	$	0.2
Current liabilities(1)	$	0.6	$	14.1
Long-term liabilities		0.0		0.2
Total liabilities	$	0.6	$	14.3

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

The ending balance in AOCI related to previously settled interest rate swaps at March 31, 2013 is a net loss of $8.5 million after tax and accumulated amortization. This compares to a net loss of $8.7 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at March 31, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets  (Liabilities) Presented on the Balance Sheet
Mar. 31, 2013
Description
Derivative assets	$	15.1		$	(2.3	)	$	12.8
Derivative liabilities	$	(2.9	)	$	2.3		$	(0.6	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

38

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, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Mar. 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	11.8	Regulatory assets	$	0.6
Long-term	Regulatory liabilities		1.0	Regulatory assets		0.0
Total		$	12.8		$	0.6

(millions) Dec. 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	$	14.1
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.2
Total		$	0.2		$	14.3

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

Based on the fair value of the instruments at March 31, 2013, net pretax losses of $11.2 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next 12 months.

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)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)
2012
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, 2013 and 2012, all hedges were effective.

39

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2015 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of March 31, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Natural Gas  Contracts (MMBTUs)
Year	Physical		Financial
2013		0.0		32.3
2014		0.0		9.0
2015		0.0		1.1
Total		0.0		42.4

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, 2013, 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.

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.

The table below presents the fair value of the overall contractual contingent liability positions for TEC’s derivative activity at March 31, 2013:

Contingent Features
(millions) Mar. 31, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	0.5	)	($	0.5	)	$	0.0

40

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, 2013 and Dec. 31, 2012. 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, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	12.8	$	0.0	$	12.8
Total	$	0.0	$	12.8	$	0.0	$	12.8
Liabilities
Natural gas swaps	$	0.0	$	0.6	$	0.0	$	0.6
Total	$	0.0	$	0.6	$	0.0	$	0.6

	At fair value as of Dec. 31, 2012
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas swaps	$	0.0	$	14.3	$	0.0	$	14.3
Total	$	0.0	$	14.3	$	0.0	$	14.3

Natural gas swaps are OTC 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, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2013
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.4		(0.2	)		0.2
Total other comprehensive income (loss)	$	0.4	($	0.2	)	$	0.2
2012
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI 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, 2013			Dec. 31, 2012
Net unrealized losses from cash flow hedges(1)	($	8.5	)	($	8.7	)
Total accumulated other comprehensive loss	($	8.5	)	($	8.7	)

(1) Net of tax benefit of $5.3 million and $5.5 million as of Mar. 31, 2013 and Dec. 31, 2012, respectively.

41

13. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, 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 $4.9 million and $22.5 million of capacity pursuant to PPAs for the three months ended March 31, 2013 and 2012, 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 for the three months ended March 31, 2012. This PPA expired on Dec. 31, 2012.

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

14. Subsequent Events

Tampa Electric Rate Case Proceeding

On Feb. 4, 2013, Tampa Electric delivered a letter to the FPSC notifying it of its intent to file a request for an increase in its retail base rates and service charges. On April 5, 2013, Tampa Electric filed a petition with the FPSC requesting, among other things, a permanent increase in rates and service charges sufficient to generate additional total annual revenues of approximately $134.8 million, to be effective on or after Jan. 1, 2014. The request provides for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requests certain changes to existing rate schedules, as well as the adoption of new rate designs. SeeNote 3for additional information.

42

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; 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; general operating conditions; input commodity prices affecting cost at all of the operating companies; operating cost and environmental or safety regulations affecting the production levels and margins at TECO Coal; fuel cost recoveries and related cash at the utilities; natural gas demand at Peoples Gas; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under “Risk Factors” in TECO Energy, Inc.’s Annual Report on Form 10-K for the period ended Dec. 31, 2012.

Earnings Summary - Unaudited
	Three months ended Mar. 31,
(millions, except per share amounts)	2013		2012
Consolidated revenues	$	661.1	$	697.1
Discontinued operations		0.3		6.0
Net income attributable to TECO Energy	$	41.5	$	50.5
Average common shares outstanding
Basic		214.6		213.9
Diluted		215.6		215.3
Earnings per share - basic
Continuing operations	$	0.19	$	0.21
Discontinued operations		—		0.03
Earnings per share - Basic	$	0.19	$	0.24
Earnings per share - diluted
Continuing operations	$	0.19	$	0.20
Discontinued operations		—		0.03
Earnings per share - Diluted	$	0.19	$	0.23

Operating Results

Three Months Ended March 31, 2013

TECO Energy, Inc. reported first quarter 2013 net income of $41.5 million, or $0.19 per share, compared with $50.5 million, or $0.24 per share in the first quarter of 2012. Net income from continuing operations was $41.2 million, or $0.19 per share, in the 2013 first quarter, compared with $44.6 million, or $0.21 per share, for the same period in 2012. The 2013 first-quarter net income of $0.3 million reported in discontinued operations was related to the TECO Guatemala sale transaction.

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

Tampa Electric’s net income for the first quarter of 2013 was $31.8 million, compared with $31.4 million for the same period in 2012. Results for the quarter reflected a 1.4% higher average number of customers, lower base revenues due to milder weather than in 2012, lower interest expense, and higher depreciation and operations and maintenance expenses. First quarter net income in 2013 included $1.1 million of AFUDC equity, which represents allowed equity cost capitalized to construction costs, compared with $0.4 million in the 2012 quarter.

Total degree days in Tampa Electric’s service area in the first quarter of 2013 were 9% below normal, and 16% below the same period in 2012, resulting in pretax base revenue approximately $4.0 million lower than in 2012. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 3.7% in the first quarter of 2013, compared with the same period in 2012. The quarterly energy sales shown below

43

reflect the energy sales based on the timing of billing cycles, which can vary period to period. While residential sales in 2013 were similar to 2012 levels, sales to commercial customers decreased in the first quarter of 2013 due to cooler-than-normal weather in March. Commercial customers are more sensitive to air conditioning load, which was higher in the first quarter of 2012 than in the 2013 period. Sales for resale decreased due to the expiration of several wholesale contracts.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, increased $2.1 million in the 2013 quarter, reflecting primarily higher pension and other employee benefit expenses, partially offset by lower costs due to the timing of generating unit outage expenditures. Depreciation and amortization expense increased $1.0 million in 2013 due to additions to facilities to serve customers, partially offset by a $1.0 million adjustment to depreciation expense related to combustion turbine repairs. Interest expense decreased $4.0 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

On Feb. 4, 2013, Tampa Electric delivered a letter to the FPSC notifying it of its intent to file a request for an increase in its retail base rates and service charges. On April 5, 2013, Tampa Electric filed a petition with the FPSC requesting, among other things, a permanent increase in rates and service charges sufficient to generate additional annual revenues of approximately $134.8 million, to be effective on or after Jan. 1, 2014. The request provides for a return on equity range of 10.25% to 12.25% with a midpoint of 11.25%. The petition also requests certain changes to existing rate schedules, as well as the adoption of new rate designs.

A summary of Tampa Electric’s regulated operating statistics for the three months ended March 31, 2013 and 2012 follows:

(millions, except average customers)	Operating Revenues								Kilowatt-hour sales
Three months ended Mar. 31,	2013			2012		% Change			2013		2012		% Change
By Customer Type
Residential	$	189.6		$	197.3		(3.9	)		1,725.3		1,725.1		0.0
Commercial		130.7			139.9		(6.6	)		1,353.2		1,393.9		(2.9	)
Industrial - Phosphate		17.8			18.4		(3.3	)		222.0		222.7		(0.3	)
Industrial - Other		23.3			24.1		(3.3	)		262.9		258.3		1.8
Other sales of electricity		41.4			42.6		(2.8	)		420.5		416.1		1.1
Deferred and other revenues(1)		(2.8	)		7.5		(137.3	)
Total energy sales	$	400.0		$	429.8		(6.9	)		3,983.9		4,016.1		(0.8	)
Sales for resale		1.3			3.1		(58.1	)		40.8		64.7		(36.9	)
Other operating revenue		16.7			13.7		21.9			0.0		0.0		0.0
Total revenues	$	418.0		$	446.6		(6.4	)		4,024.7		4,080.8		(1.4	)
Average customers (thousands)		690.2			680.8		1.4
Retail net energy for load (kilowatt hours)										4,088.0		4,243.6		(3.7	)

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

Tampa Electric Company - Natural Gas Division (PGS)

PGS reported net income of $13.8 million for the quarter, compared with $11.0 million recorded in 2012. First quarter results in 2013 reflected customer growth of 1.3% and higher therm sales to all retail customer classes. Therms sold to commercial and interruptible industrial customers increased due to improving economic conditions. Non-fuel operations and maintenance expense decreased $0.8 million compared to the 2012 period, primarily due to higher than normal self-insurance expenses in 2012. Interest expense decreased slightly due to lower long-term debt interest rates and a lower interest rate on customer deposits.

44

A summary of PGS’s regulated operating statistics for the three months ended March 31, 2013 and 2012 follows:

(millions, except average customers)	Operating Revenues							Therms
Three months ended Mar. 31,	2013		2012		% Change			2013		2012		% Change
By Customer Type
Residential	$	42.3	$	40.7		3.9			29.5		27.0		9.3
Commercial		39.2		38.6		1.6			124.8		118.3		5.5
Industrial		3.6		2.4		50.0			71.3		55.7		28.0
Off system sales		18.3		13.2		38.6			50.4		44.0		14.5
Power generation		3.1		3.4		(8.8	)		205.0		208.6		(1.7	)
Other revenues		12.4		10.0		24.0			0.0		0.0		0.0
Total	$	118.9	$	108.3		9.8			481.0		453.6		6.0
By Sales Type
System supply	$	74.1	$	68.6		8.0			89.9		82.7		8.7
Transportation		32.4		29.7		9.1			391.1		370.9		5.4
Other revenues		12.4		10.0		24.0			0.0		0.0		0.0
Total	$	118.9	$	108.3		9.8			481.0		453.6		6.0
Average customers (thousands)		346.4		342.0		1.3

TECO Coal

TECO Coal reported first quarter net income of $3.0 million on sales of 1.3 million tons, compared with $9.8 million on sales of 1.4 million tons in the same period in 2012. In 2013, first quarter results reflect an average net per-ton selling price, excluding transportation allowances, of almost $90 per ton, which included higher priced carry over tons from 2012, compared to an average selling price of almost $96 per ton in 2012. In the first quarter of 2013, the all-in total per-ton cost of sales was almost $88, which is higher than full-year guidance. The cost of sales in January and February included some higher-cost tons from December inventory that included costs associated with personnel reductions and with idling certain mining operations. The cost of sales in March was in line with full-year 2013 cost guidance. Due to the effects of tax percentage depletion, TECO Coal’s effective income tax rate in the first quarter of 2013 was essentially zero, compared with 24% in the 2012 period.

Parent & other

The cost for Parent & other in continuing operations in the first quarter of 2013 was $7.4 million, compared with a cost of $7.6 million in the same period in 2012. The cost for the 2013 quarter included slightly lower interest expense due to the repayment of $8.8 million of parent debt in 2012 and certain favorable tax adjustments recorded at Parent.

The total cost for Parent & other for the first quarter of 2013 was $7.1 million, compared with $8.3 million for the 2012 period. Total cost for the 2013 first quarter reflected a $0.3 million benefit at Parent related to the sale of TECO Guatemala in 2012, which was recorded as a discontinued operation.

2013 Guidance

TECO Energy is maintaining its earnings per share guidance for 2013 in a range between $0.90 and $1.00. TECO Energy expects earnings in 2013 to be driven by the factors discussed below.

At Tampa Electric, full-year customer growth of 1.2% is anticipated in 2013, but total retail energy sales growth is expected to be lower than customer growth due to lower average customer usage. Sales to the lower margin industrial-phosphate customers are expected to be lower in 2013 due to increased self-generation following outages of customers’ generating equipment that increased sales to these customers in 2012. Operations and maintenance expenses are expected to increase in 2013 due to increased expenses to operate the system and reliably serve customers and higher employee-related expenses. Pension expense is expected to increase driven by discount rate assumptions in the current low-interest rate environment. In 2013, Tampa Electric expects its full-year thirteen-month average ROE to be less than 9%.

PGS expects to continue to earn above the middle of its allowed ROE range of 9.75% to 11.75% from moderate customer growth, which is expected to continue in 2013 in line with the trends experienced in 2012, and continued focus on cost management. It also expects to benefit from continued interest from customers utilizing petroleum and other fuel sources to convert to natural gas due to the attractive economics.

TECO Coal now has almost 95% of its expected sales of between 5.2 million and 5.7 million tons contracted for 2013. The product mix is expected to be about 50% specialty coals, which include stoker, metallurgical and PCI coals, and the remainder utility steam coal. The average selling price across all products is expected to be more than $86 per ton. All of the 2.7 million tons of steam coal sales planned for 2013 are committed and priced. The all-in total cost of production is still expected to be in a range between $81 and $85 per ton, due to actions taken in 2012 to reduce mining costs and lower royalty payments and severance taxes, which are a function of selling price. Because of the zero effective tax rate in the first quarter, TECO Coal’s full-year 2013 effective income tax rate is expected to be less than the previously forecasted 25%.

45

Income Taxes

The provisions for income taxes from continuing operations for the three month periods ended March 31, 2013 and 2012 were $23.2 million and $24.1 million, respectively. The provision for income taxes for the three months ended March 31, 2013 was impacted by lower operating income and decreased depletion benefit at TECO Coal.

Liquidity and Capital Resources

The table below sets forth the March 31, 2013 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, 2013	Consolidated		Tampa  Electric Company		Other Companies		TECO Finance/Parent
(millions)
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts/Letters of Credit		1.5		1.5		0.0		0.0
Available credit facilities		673.5		473.5		0.0		200.0
Cash and short-term investments		213.0		60.0		4.5		148.5
Total liquidity	$	886.5	$	533.5	$	4.5	$	348.5

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 theLiquidity and Capital Resources section above). In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At March 31, 2013, 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, 2013. 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 Mar.��31,  2013
TEC
Credit facility (2)	Debt/capital		Cannot exceed 65	%		46.1	%
Accounts receivable credit facility (2)	Debt/capital		Cannot exceed 65	%		46.1	%
6.25% senior notes	Debt/capital		Cannot exceed 60	%		46.1	%
	Limit on liens (3)		Cannot exceed $700			$0 liens outstanding
TECO Energy/TECO
Finance
Credit facility (2)	Debt/capital		Cannot exceed 65	%		56.1	%
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 indenture 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.

46

Credit Ratings of Senior Unsecured Debt at March 31, 2013
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	A3	A–
TECO Energy/TECO Finance	BBB	Baa2	BBB

On May 4, 2012, Moody’s upgraded the credit ratings of TEC, TECO Energy and TECO Finance to A3, Baa2 and Baa2, respectively, all with stable outlooks.

S&P, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P 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. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (seeNote 12 to theTECO Energy Consolidated Condensed Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings. These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Fair Value Measurements

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

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

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, 2013, the fair value of derivatives was not materially affected by nonperformance risk.

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, 2012.

47

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 increase in the average market price component of the company’s outstanding natural gas swaps of approximately 8% from Dec. 31, 2012 to March 31, 2013. For natural gas, the company maintained a similar volume hedged as of March 31, 2013 from Dec. 31, 2012.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three month period ended March 31, 2013:

Changes in Fair Value of Derivatives(millions)
Net fair value of derivatives as of Dec. 31, 2012	$	(15.0	)
Additions and net changes in unrealized fair value of derivatives		19.4
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		7.2
Net fair value of derivatives as of Mar. 31, 2013	$	11.6

Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2012	$	(15.0	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		19.4
Recorded in earnings		0.0
Realized net settlement of derivatives		7.2
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Mar. 31, 2013	$	11.6

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at March 31, 2013:

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)		10.9		0.7		11.6
Model prices(2)		0.0		0.0		0.0
Total	$	10.9	$	0.7	$	11.6

(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.

48

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 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 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.

49

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, 2013 – Jan. 31, 2013		490	$	17.11		0.0	$	0.0
Feb. 1, 2013 – Feb. 28, 2013		7,419	$	17.24		0.0	$	0.0
Mar. 1, 2013 – Mar. 31, 2013		438	$	17.42		0.0	$	0.0
Total 1st Quarter 2013		8,347	$	17.24		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 52.

50

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 3, 2013	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 3, 2013	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)

51

INDEX TO EXHIBITS

Exhibit No.	Description
3.1	Amended and Restated Articles of Incorporation of TECO Energy, Inc., as filed on May 3, 2012 (Exhibit 3.1, Form 8-K dated May 4, 2012 of TECO Energy, Inc.).	*
3.2	Bylaws of TECO Energy, Inc., as amended effective May 3, 2012 (Exhibit 3.1, Form 8-K dated May 4, 2012 of TECO Energy, Inc.).	*
3.3	Restated Articles of Incorporation of Tampa Electric Company, as amended on Nov. 30, 1982 (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 2011 of TECO Energy, Inc. and Tampa Electric Company).	*
10.1	Form of Performance Shares Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan.
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.

52