10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2014

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 25, 2014 was 217,805,680. As of April 25, 2014, 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 2 of 54

Index to Exhibits appears on page 54.

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
AMT	alternative minimum tax
AOCI	accumulated other comprehensive income
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
BACT	Best Available Control Technology
BTU	British Thermal Unit
CAA	Federal Clean Air Act
CAIR	Clean Air Interstate Rule
capacity clause	capacity cost-recovery clause, as established by the FPSC
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980
CCRs	coal combustion residuals
CGESJ	Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala
CMMA	Cardno Marshall Miller & Associates
CMBS	commercial mortgage-backed securities
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CO2	carbon dioxide
CT	combustion turbine
DECA II	Distribución Eléctrica Centro Americana, II, S.A.
DOE	U.S. Department of Energy
DR-CAFTA	Dominican Republic Central America – United States Free Trade Agreement
ECRC	environmental cost recovery clause
EEGSA	Empresa Eléctrica de Guatemala, S.A., the largest private distribution company in Central America
EEI	Edison Electric Institute
EGWP	Employee Group Waiver Plan
EPA	U.S. Environmental Protection Agency
EPS	earnings per share
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
ERP	enterprise resource planning
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
ICSID	International Centre for the Settlement of Investment Disputes

3

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(s)
KWH	kilowatt-hour(s)
LIBOR	London Interbank Offered Rate
MAP-21	Moving Ahead for Progress in the 21st Century Act
MBS	mortgage-backed securities
MD&A	Management’s Discussion and Analysis
Met	metallurgical
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MMBTU	one million British Thermal Units
MRV	market-related value
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
NMGC	New Mexico Gas Company, Inc., the principal subsidiary of NMGI
NMGI	New Mexico Gas Intermediate, Inc.
NMPRC	New Mexico Public Regulation Commission
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
PM	particulate matter
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

4

RPS	renewable portfolio standards
RTO	regional transmission organization
S&P	Standard and Poor’s
SCR	selective catalytic reduction
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SERP	Supplemental Executive Retirement Plan
SPA	stock purchase agreement
STIF	short-term investment fund
Tampa Electric	Tampa Electric, the electric division of Tampa Electric Company
TCAE	Tampa Centro Americana de Electridad, Limitada, majority owner of the Alborada Power Station
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, and its subsidiaries, a coal producing subsidiary of TECO Diversified
TECO Finance	TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.
TECO Guatemala	TECO Guatemala, Inc., a subsidiary of TECO Energy, Inc., parent company of formerly owned generating and transmission assets in Guatemala.
TEMSA	Tecnología Marítima, S.A., a provider of dry bulk and coal unloading services located in Guatemala
TGH	TECO Guatemala Holdings, LLC
TRC	TEC Receivables Company
USACE	U.S. Army Corps of Engineers
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

5

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, 2014 and Dec. 31, 2013, and the results of their operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three month period ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. 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, 2013 and to the notes on pages 12 through 28 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, March 31, 2014 and Dec. 31, 2013		7-8
Consolidated Condensed Statements of Income for the three month periods ended March 31, 2014 and 2013		9
Consolidated Condensed Statements of Comprehensive Income for the three month periods ended March  31, 2014 and 2013		10
Consolidated Condensed Statements of Cash Flows for the three month periods ended March  31, 2014 and 2013		11
Notes to Consolidated Condensed Financial Statements		12-28

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.

6

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2014			2013
Current assets
Cash and cash equivalents	$	137.0		$	185.2
Receivables, less allowance for uncollectibles of $4.9 and $4.7 at Mar. 31, 2014 and Dec. 31, 2013, respectively		269.1			287.2
Inventories, at average cost
Fuel		120.0			118.7
Materials and supplies		84.2			85.9
Derivative assets		15.6			9.7
Regulatory assets		32.7			34.3
Deferred income taxes		89.0			100.3
Prepayments and other current assets		35.1			34.9
Income tax receivables		0.8			1.5
Total current assets		783.5			857.7
Property, plant and equipment
Utility plant in service
Electric		6,982.4			6,934.0
Gas		1,312.5			1,308.3
Construction work in progress		442.9			386.7
Other property		447.5			448.3
Property, plant and equipment, at original costs		9,185.3			9,077.3
Accumulated depreciation		(2,951.5	)		(2,907.2	)
Total property, plant and equipment, net		6,233.8			6,170.1
Other assets
Regulatory assets		288.8			293.1
Derivative assets		0.2			0.3
Deferred charges and other assets		124.4			126.8
Total other assets		413.4			420.2
Total assets	$	7,430.7		$	7,448.0

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

7

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital	Mar. 31, 2014			Dec. 31, 2013
(millions)
Current liabilities
Long-term debt due within one year	$	83.3		$	83.3
Notes payable		29.0			84.0
Accounts payable		250.0			261.7
Customer deposits		166.8			164.5
Regulatory liabilities		90.1			85.8
Derivative liabilities		0.1			0.1
Interest accrued		54.8			31.9
Taxes accrued		49.4			34.6
Other		18.3			19.5
Total current liabilities		741.8			765.4
Other liabilities
Deferred income taxes		461.6			444.0
Investment tax credits		9.3			9.4
Regulatory liabilities		625.0			631.4
Derivative liabilities		0.1			0.2
Deferred credits and other liabilities		421.5			426.1
Long-term debt, less amount due within one year		2,837.8			2,837.8
Total other liabilities		4,355.3			4,348.9
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 218.2 million and 217.3 million shares outstanding at Mar. 31, 2014 and Dec. 31, 2013, respectively)		218.2			217.3
Additional paid in capital		1,585.7			1,581.3
Retained earnings		550.4			548.3
Accumulated other comprehensive loss		(20.7	)		(13.2	)
Total capital		2,333.6			2,333.7
Total liabilities and capital	$	7,430.7		$	7,448.0

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Mar. 31,
(millions, except per share amounts)		2014			2013
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $27.2 in 2014 and $25.4 in 2013)		$	575.7		$	539.1
Unregulated			108.4			122.0
Total revenues			684.1			661.1
Expenses
Regulated operations and maintenance
Fuel			149.6			140.0
Purchased power			18.2			14.6
Cost of natural gas sold			47.1			49.5
Other			120.6			120.8
Operation and maintenance other expense
Mining related costs			91.2			95.5
Other			3.1			1.3
Depreciation and amortization			84.9			82.0
Taxes, other than income			56.3			53.3
Total expenses			571.0			557.0
Income from continuing operations			113.1			104.1
Other income
Allowance for other funds used during construction			2.4			1.1
Other income			(0.7	)		1.6
Total other income			1.7			2.7
Interest charges
Interest expense			42.5			43.0
Allowance for borrowed funds used during construction			(1.4	)		(0.6	)
Total interest charges			41.1			42.4
Income from continuing operations before provision for income taxes			73.7			64.4
Provision for income taxes			26.7			23.2
Net income from continuing operations			47.0			41.2
Discontinued operations
Income from discontinued operations			5.0			0.4
Provision for income taxes			1.9			0.1
Income from discontinued operations, net			3.1			0.3
Net income		$	50.1		$	41.5
Average common shares outstanding	– Basic		215.2			214.6
	– Diluted		215.7			215.6
Earnings per share from continuing operations	– Basic	$	0.22		$	0.19
	– Diluted	$	0.22		$	0.19
Earnings per share from discontinued operations	– Basic	$	0.01		$	0.00
	– Diluted	$	0.01		$	0.00
Earnings per share attributable to TECO Energy	– Basic	$	0.23		$	0.19
	– Diluted	$	0.23		$	0.19
Dividends paid per common share outstanding		$	0.22		$	0.22

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

9

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2014			2013
Net income	$	50.1		$	41.5
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges		0.2			0.4
Amortization of unrecognized benefit costs		0.5			0.7
Increase in unrecognized post employment costs		(8.2	)		0.0
Other comprehensive income, net of tax		(7.5	)		1.1
Comprehensive income	$	42.6		$	42.6

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

10

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2014			2013
Cash flows from operating activities
Net income	$	50.1		$	41.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		84.9			82.0
Deferred income taxes		28.9			23.4
Investment tax credits		(0.1	)		(0.1	)
Allowance for other funds used during construction		(2.4	)		(1.1	)
Non-cash stock compensation		3.7			3.6
Gain on sales of business/assets, pretax		(0.1	)		(0.2	)
Deferred recovery clauses		2.6			4.5
Receivables, less allowance for uncollectibles		18.1			13.0
Inventories		0.4			(21.4	)
Prepayments and other current assets		(0.2	)		0.6
Taxes accrued		15.5			15.8
Interest accrued		22.9			22.1
Accounts payable		(25.2	)		(25.0	)
Other		(12.2	)		(0.8	)
Cash flows from operating activities		186.9			157.9
Cash flows from investing activities
Capital expenditures		(136.3	)		(103.0	)
Allowance for other funds used during construction		2.4			1.1
Net proceeds from sales of business/assets		0.2			0.3
Cash flows used in investing activities		(133.7	)		(101.6	)
Cash flows from financing activities
Dividends		(48.0	)		(47.8	)
Proceeds from the sale of common stock		1.6			3.9
Net decrease in short-term debt		(55.0	)		0.0
Cash flows used in financing activities		(101.4	)		(43.9	)
Net (decrease) increase in cash and cash equivalents		(48.2	)		12.4
Cash and cash equivalents at beginning of the period		185.2			200.5
Cash and cash equivalents at end of the period	$	137.0		$	212.9
Supplemental disclosure of non-cash activities
Capital expenditures not yet paid	$	14.6		$	0.6

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

11

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2013 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 (see Note 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, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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, 2014 and Dec. 31, 2013, unbilled revenues of $48.1 million and $46.7 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 $27.2 million and $25.4 million for the three months ended March 31, 2014 and 2013, 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.

12

2. New Accounting Pronouncements

Unrecognized Tax Benefits

In July 2013, the FASB issued guidance regarding the presentation of unrecognized tax benefits in the statement of position when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. It requires that an unrecognized tax benefit be presented as a reduction to a deferred tax asset for net operating loss carryforwards, similar tax losses or tax credit carryforwards, with certain exceptions. The guidance became effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. The company has adopted this guidance and it has no effect on the company’s results of operations, financial position or cash flows.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric 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.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $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. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both March 31, 2014 and Dec. 31, 2013.

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.

13

Details of the regulatory assets and liabilities as of March 31, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2014		Dec. 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	67.9	$	67.4
Other:
Cost-recovery clauses		3.3		6.1
Postretirement benefit asset		180.2		182.7
Deferred bond refinancing costs (2)		7.8		8.0
Environmental remediation		51.4		51.4
Competitive rate adjustment		3.4		4.1
Other		7.5		7.7
Total other regulatory assets		253.6		260.0
Total regulatory assets		321.5		327.4
Less: Current portion		32.7		34.3
Long-term regulatory assets	$	288.8	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.8	$	9.8
Other:
Cost-recovery clauses		58.9		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.7		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		591.8		594.0
Total other regulatory liabilities		709.3		707.4
Total regulatory liabilities		715.1		717.2
Less: Current portion		90.1		85.8
Long-term regulatory liabilities	$	625.0	$	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, 2014		Dec. 31, 2013
Clause recoverable (1)	$	6.7	$	10.2
Components of rate base (2)		183.2		185.6
Regulatory tax assets (3)		67.9		67.4
Capital structure and other (3)		63.7		64.2
Total	$	321.5	$	327.4

(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.

14

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 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for years 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. 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 2010 and forward.

The effective tax rate increased to 36.22% for the three months ended March 31, 2014 from 35.95% for the same period in 2013.

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,	2014			2013			2014		2013
Components of net periodic benefit expense
Service cost	$	4.1		$	4.8		$	0.6	$	0.7
Interest cost on projected benefit obligations		8.2			7.2			2.6		2.3
Expected return on assets		(10.3	)		(9.7	)		0.0		0.0
Amortization of:
Prior service cost		(0.1	)		(0.1	)		0.0		(0.1	)
Actuarial loss		3.2			5.0			0.0		0.3
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	5.1		$	7.2		$	3.2	$	3.2

For the fiscal 2014 plan year, TECO Energy is using an assumed long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $16.0 million to its pension plan in the first quarter of 2014.

For the three months ended March 31, 2014, TECO Energy and its subsidiaries reclassed $0.6 million pretax of unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended March 31, 2014, TEC reclassed $2.5 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

15

6. Short-Term Debt

At March 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2014						Dec. 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding(1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding(1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		29.0		0.0		150.0		78.0		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	$	29.0	$	0.7	$	675.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

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

At March 31, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2014 and Dec. 31, 2013 was 0.63% and 0.56%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 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. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 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, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2014, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,209.7 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 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.

16

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended March 31, 2014 and 2013, 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
2014
Unrealized loss on cash flow hedges	($	0.1	)	$	0.0		($	0.1	)
Reclassification from AOCI to net income (1)		0.4			(0.1	)		0.3
Gain on cash flow hedges		0.3			(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5
Increase in unrecognized post employment costs (3)		(12.9	)		4.7			(8.2	)
Total other comprehensive loss	($	11.8	)	$	4.3		($	7.5	)
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

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

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

(3) Amount reflects an out-of-period adjustment to unfunded black lung liability.

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2014			Dec. 31, 2013
Unrecognized pension loss and prior service credit (1)	($	20.0	)	($	20.5	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		6.9			15.1
Net unrealized losses from cash flow hedges (3)		(7.6	)		(7.8	)
Total accumulated other comprehensive loss	($	20.7	)	($	13.2	)

(1) Net of tax benefit of $12.3 million and $12.6 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

(2) Net of tax expense of $4.4 million and $9.1 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

(3) Net of tax benefit of $4.8 million and $4.9 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

17

9. Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2014			2013
Basic earnings per share
Net income from continuing operations	$	47.0		$	41.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Income before discontinued operations available to common shareholders - Basic	$	46.8		$	41.1
Income from discontinued operations, net	$	3.1		$	0.3
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations available to common shareholders - Basic	$	3.1		$	0.3
Net income	$	50.1		$	41.5
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Net income available to common shareholders - Basic	$	49.9		$	41.4
Average common shares outstanding - Basic		215.2			214.6
Earnings per share from continuing operations available to common shareholders - Basic	$	0.22		$	0.19
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.01		$	0.00
Earnings per share available to common shareholders - Basic	$	0.23		$	0.19
Diluted earnings per share
Net income from continuing operations	$	47.0		$	41.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Income before discontinued operations available to common shareholders - Diluted	$	46.8		$	41.1
Income from discontinued operations, net	$	3.1		$	0.3
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations available to common shareholders - Diluted	$	3.1		$	0.3
Net income	$	50.1		$	41.5
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Net income available to common shareholders - Diluted	$	49.9		$	41.4
Unadjusted average common shares outstanding - Diluted		215.2			214.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			1.0
Average common shares outstanding - Diluted		215.7			215.6
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.22		$	0.19
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.01		$	0.00
Earnings per share available to common shareholders - Diluted	$	0.23		$	0.19
Anti-dilutive shares		0.0			0.0

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.

18

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, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees were maintaining a suit against TEC in Hillsborough County Circuit Court, Florida 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 the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014 all plaintiffs voluntarily dismissed their suits with prejudice.

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, 2014 TEC has estimated its ultimate financial liability to be $38.4 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, most 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. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

19

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, 2014 is as follows:

Guarantees - TECO Energy
(millions)					After(1) 2018		Total		Liabilities Recognized at Mar. 31, 2014
Guarantees for the Benefit of:	2014		2015-2018
TECO Coal
Fuel purchase related (2)	$	0.8	$	0.7	$	4.0	$	5.5	$	2.3
Other subsidiaries
Fuel purchase/energy management (2)		10.0		0.0		92.9		102.9		0.1
Total	$	10.8	$	0.7	$	96.9	$	108.4	$	2.4
Letters of Credit - Tampa Electric Company
(millions)	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Mar. 31, 2014
Letters of Credit for the Benefit of:
Tampa Electric Company(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.

(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, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, 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, 2014, 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.

20

Segment Information (1)
(millions)	Tampa		Peoples		TECO			Other &			TECO
Three months ended Mar. 31,	Electric		Gas		Coal			Eliminations			Energy
2014
Revenues - external	$	452.9	$	122.4	$	106.1		$	2.7		$	684.1
Sales to affiliates		0.3		0.2		0.0			(0.5	)		0.0
Total revenues		453.2		122.6		106.1			2.2			684.1
Depreciation and amortization		62.1		13.3		9.0			0.5			84.9
Total interest charges(1)		22.0		3.4		1.5			14.2			41.1
Internally allocated interest (1)		0.0		0.0		1.5			(1.5	)		0.0
Provision (benefit) for income taxes		26.6		9.2		(2.2	)		(6.9	)		26.7
Net income (loss) from continuing operations		45.2		14.6		(1.6	)		(11.2	)		47.0
Income from discontinued operations, net		0.0		0.0		0.0			3.1			3.1
Net income (loss)	$	45.2	$	14.6	($	1.6	)	($	8.1	)	$	50.1
2013
Revenues - external	$	417.8	$	121.9	$	117.9		$	3.5		$	661.1
Sales to affiliates		0.2		0.0		0.0			(0.2	)		0.0
Total revenues		418.0		121.9		117.9			3.3			661.1
Depreciation and amortization		59.0		13.0		9.7			0.3			82.0
Total interest charges(1)		23.4		3.4		1.7			13.9			42.4
Internally allocated interest (1)		0.0		0.0		1.6			(1.6	)		0.0
Provision (benefit) for income taxes		19.8		8.7		(0.1	)		(5.2	)		23.2
Net income (loss) from continuing operations		31.8		13.8		3.0			(7.4	)		41.2
Income from discontinued operations, net		0.0		0.0		0.0			0.3			0.3
Net income (loss)	$	31.8	$	13.8	$	3.0		($	7.1	)	$	41.5
At Mar. 31, 2014
Total assets	$	6,120.8	$	1,031.1	$	319.5		($	40.7	)	$	7,430.7
At Dec. 31, 2013
Total assets	$	6,126.9	$	1,021.2	$	316.3		($	16.4	)	$	7,448.0

(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 2013 through March 2014 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.

12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

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

21

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, 2014, 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, 2014 and Dec. 31, 2013:

Total Derivatives(1)
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	15.6	$	9.7
Long-term assets		0.2		0.3
Total assets	$	15.8	$	10.0
Current liabilities	$	0.1	$	0.1
Long-term liabilities		0.1		0.2
Total liabilities	$	0.2	$	0.3

(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 following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at March 31, 2014 and Dec. 31, 2013. 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, 2014
Description
Derivative assets	$	16.1		$	(0.3	)	$	15.8
Derivative liabilities	$	(0.5	)	$	0.3		$	(0.2	)
Dec. 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)

22

The following table presents the derivative hedges of diesel fuel contracts at March 31, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	0.1	$	0.2
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.2
Current liabilities	$	0.1	$	0.1
Long-term liabilities		0.0		0.0
Total liabilities	$	0.1	$	0.1

The following table presents the derivative hedges of natural gas contracts at March 31, 2014 and Dec. 31, 2013 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, 2014		Dec. 31, 2013
Current assets	$	15.5	$	9.5
Long-term assets		0.2		0.3
Total assets	$	15.7	$	9.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.1	$	0.2

The ending balance in AOCI related to the cash flow hedges and interest rate swaps at March 31, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at March 31, 2014 and Dec. 31, 2013:

Derivatives Designated as Hedging Instruments
	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet Location		Fair Value		Balance Sheet Location	Fair Value
Mar. 31, 2014
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	0.1	Derivative liabilities	$	0.1
Long-term		Derivative assets		0.0	Derivative liabilities		0.0
Natural gas derivatives:
Current		Derivative assets		15.5	Derivative liabilities		0.0
Long-term		Derivative assets		0.2	Derivative liabilities		0.1
Total derivatives designated as hedging instruments			$	15.8		$	0.2

23

	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Dec. 31, 2013	Location		Value		Location		Value
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	0.2		Derivative liabilities	$	0.1
Long-term		Derivative assets		0.0		Derivative liabilities		0.0
Natural gas derivatives:
Current		Derivative assets		9.5		Derivative liabilities		0.0
Long-term		Derivative assets		0.3		Derivative liabilities		0.2
Total derivatives designated as hedging instruments			$	10.0			$	0.3

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of March 31, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Mar. 31, 2014	Location (1)		Value		Location (1)		Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	15.5		Regulatory assets	$	0.0
Long-term		Regulatory liabilities		0.2		Regulatory assets		0.1
Total			$	15.7			$	0.1
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Dec. 31, 2013	Location (1)		Value		Location (1)		Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	9.5		Regulatory assets	$	0.0
Long-term		Regulatory liabilities		0.3		Regulatory assets		0.2
Total			$	9.8			$	0.2

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

Based on the fair value of the instruments at March 31, 2014, net pretax gains of $15.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

24

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

	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
(millions)
Derivatives in Cash Flow Hedging Relationships		Effective Portion(1)				Effective Portion(1)
2014
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.1	)	Mining related costs		(0.1	)
Total	($	0.1	)		($	0.3	)
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	)

(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, 2014 and 2013, 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:

	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
(millions)
2014
Interest rate swaps	$	0.0		$	0.0		($	0.2	)
Diesel fuel derivatives		0.0			(0.1	)		(0.1	)
Total	$	0.0		($	0.1	)	($	0.3	)
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	)

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

25

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		1.5		0.0		26.9
2015		0.0		0.0		0.0		18.5
2016		0.0		0.0		0.0		1.7
Total		0.0		1.5		0.0		47.1

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, 2014, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were 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 risk in determining the fair value of counterparty positions. 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 in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2014, substantially all positions with counterparties were net assets.

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, 2014:

Contingent Features
	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
(millions)
At Mar. 31, 2014
Credit Rating	($	0.1	)	($	0.1	)	$	0.0

26

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, 2014 and Dec. 31, 2013. 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, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	15.7	$	0.0	$	15.7
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	15.8	$	0.0	$	15.8
Liabilities
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.2	$	0.0	$	0.2

	At fair value as of Dec. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Diesel fuel swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	10.0	$	0.0	$	10.0
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.3	$	0.0	$	0.3

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 (see Note 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, 2014, 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 160 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 $5.9 million and $4.9 million of capacity pursuant to PPAs for the three months ended March 31, 2014 and 2013, respectively.

27

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. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below. The following table provides selected components of discontinued operations:

Components of income from discontinued operations
(millions)
Three months ended Mar. 31,	2014		2013
Revenues	$	0.0	$	0.0
Income from operations		5.0		0.4
Income from discontinued operations		5.0		0.4
Provision for income taxes		1.9		0.1
Income from discontinued operations, net	$	3.1	$	0.3

16. Subsequent Events

Pending Acquisition of New Mexico Gas Company

As previously disclosed, TECO Energy must obtain approval for the acquisition from the NMPRC prior to closing the transaction. Hearings before the hearing examiner were concluded on April 3, 2014.

The current schedule calls for the parties to submit post-hearing briefs on May 2, 2014, with reply briefs due May 15, 2014. Following the submittal of briefs, the hearing examiner will provide a recommendation to the NMPRC. The schedule for the hearing examiner’s recommendation and the NMPRC’s final decision has not been established but we expect to close the transaction by mid to late third quarter this year.

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

As previously reported, on Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, Inc., against the Republic of Guatemala (“Guatemala”) under the DR – CAFTA, issued an award in the case (the “Award”). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. Pursuant to ICSID’s rules and procedures, each party had 120 days after the date of the Award to file an application for its annulment.

On April 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. Guatemala also requested that the enforcement of the Award be stayed while the annulment proceeding is pending. Under the applicable rules, the enforcement of the Award is provisionally stayed until the ad hoc committee that will be deciding Guatemala’s application is constituted and makes a decision regarding whether the stay should continue through the rest of the annulment proceeding.

Also on April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.

While the duration of the annulment proceedings is uncertain, they are expected to take approximately 17 to 24 months to conclude. Pending the outcome of annulment proceedings, results in the first quarter of 2014 do not reflect any benefit of this decision.

28

TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC and its subsidiaries as of March 31, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three month period ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. 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, 2013 and to the notes on pages 34 through 44 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page
	No.
Consolidated Condensed Balance Sheets, March 31, 2014 and Dec. 31, 2013		30-31
Consolidated Condensed Statements of Income and Comprehensive Income for the three month periods ended March  31, 2014 and 2013		32
Consolidated Condensed Statements of Cash Flows for the three month periods ended March 31, 2014 and 2013		33
Notes to Consolidated Condensed Financial Statements		34-44

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.

29

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2014			2013
Property, plant and equipment
Utility plant in service
Electric	$	6,982.4		$	6,934.0
Gas		1,253.6			1,249.5
Construction work in progress		441.2			385.3
Utility plant in service, at original costs		8,677.2			8,568.8
Accumulated depreciation		(2,602.7	)		(2,562.6	)
		6,074.5			6,006.2
Other property		8.3			8.3
Total property, plant and equipment, net		6,082.8			6,014.5
Current assets
Cash and cash equivalents		16.9			9.8
Receivables, less allowance for uncollectibles of $2.2 and $2.0 at Mar. 31, 2014 and Dec. 31, 2013, respectively		214.9			227.6
Inventories, at average cost
Fuel		86.1			93.7
Materials and supplies		75.1			76.8
Regulatory assets		32.7			34.3
Derivative assets		15.5			9.5
Taxes receivable		0.0			54.9
Deferred income taxes		20.1			29.4
Prepayments and other current assets		12.7			12.5
Total current assets		474.0			548.5
Deferred debits
Unamortized debt expense		14.5			14.8
Regulatory assets		288.8			293.1
Derivative assets		0.2			0.3
Other		5.0			4.6
Total deferred debits		308.5			312.8
Total assets	$	6,865.3		$	6,875.8

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

30

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	Mar. 31,			Dec. 31,
(millions)	2014			2013
Capitalization
Common stock	$	2,037.4		$	2,030.4
Accumulated other comprehensive loss		(7.6	)		(7.8	)
Retained earnings		301.7			308.1
Total capital		2,331.5			2,330.7
Long-term debt		1,797.5			1,797.5
Total capitalization		4,129.0			4,128.2
Current liabilities
Long-term debt due within one year		83.3			83.3
Notes payable		29.0			84.0
Accounts payable		216.2			226.0
Customer deposits		166.8			164.5
Regulatory liabilities		90.1			85.8
Interest accrued		37.3			16.4
Taxes accrued		39.7			12.2
Other		12.0			12.0
Total current liabilities		674.4			684.2
Deferred credits
Deferred income taxes		1,132.1			1,114.3
Investment tax credits		9.3			9.4
Derivative liabilities		0.1			0.2
Regulatory liabilities		625.0			631.4
Other		295.4			308.1
Total deferred credits		2,061.9			2,063.4
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	6,865.3		$	6,875.8

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

31

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2014			2013
Revenues
Electric (includes franchise fees and gross receipts taxes of $20.3 in 2014 and $19.0 in 2013)	$	453.0		$	417.9
Gas (includes franchise fees and gross receipts taxes of $6.9 in 2014 and $6.4 in 2013)		122.5			121.9
Total revenues		575.5			539.8
Expenses
Regulated operations and maintenance
Fuel		149.6			140.0
Purchased power		18.2			14.6
Cost of natural gas sold		47.2			49.5
Other		120.3			120.6
Depreciation and amortization		75.4			72.0
Taxes, other than income		47.4			44.5
Total expenses		458.1			441.2
Income from operations		117.4			98.6
Other income
Allowance for other funds used during construction		2.4			1.1
Other income, net		1.2			1.2
Total other income		3.6			2.3
Interest charges
Interest on long-term debt		25.7			26.5
Other interest		1.1			0.9
Allowance for borrowed funds used during construction		(1.4	)		(0.6	)
Total interest charges		25.4			26.8
Income before provision for income taxes		95.6			74.1
Provision for income taxes		35.8			28.5
Net income		59.8			45.6
Other comprehensive income, net of tax
Amortization of settled interest rate swaps		0.2			0.2
Total other comprehensive income, net of tax		0.2			0.2
Comprehensive income	$	60.0		$	45.8

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

32

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2014			2013
Cash flows from operating activities
Net income	$	59.8		$	45.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		75.4			72.0
Deferred income taxes		22.8			23.3
Investment tax credits		(0.1	)		(0.1	)
Allowance for funds used during construction		(2.4	)		(1.1	)
Deferred recovery clauses		2.6			4.5
Receivables, less allowance for uncollectibles		12.7			2.2
Inventories		9.3			(17.2	)
Prepayments		(0.2	)		(0.1	)
Taxes accrued		82.4			39.1
Interest accrued		20.9			20.2
Accounts payable		(23.3	)		(21.1	)
Other		(9.1	)		(0.7	)
Cash flows from operating activities		250.8			166.6
Cash flows from investing activities
Capital expenditures		(132.0	)		(97.9	)
Allowance for funds used during construction		2.4			1.1
Cash flows used in investing activities		(129.6	)		(96.8	)
Cash flows from financing activities
Common stock		7.0			0.0
Net decrease in short-term debt		(55.0	)		0.0
Dividends		(66.1	)		(55.0	)
Cash flows used in financing activities		(114.1	)		(55.0	)
Net increase in cash and cash equivalents		7.1			14.8
Cash and cash equivalents at beginning of period		9.8			45.2
Cash and cash equivalents at end of period	$	16.9		$	60.0
Supplemental disclosure of non-cash activities
Capital expenditures not yet paid	$	14.7		$	0.6

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

33

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2013 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 (see Note 13).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of March 31, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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, 2014 and Dec. 31, 2013, unbilled revenues of $48.1 million and $46.7 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 $27.2 million and $25.4 million for the three months ended March 31, 2014 and 2013, 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

Unrecognized Tax Benefits

In July 2013, the FASB issued guidance regarding the presentation of unrecognized tax benefits in the statement of position when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. It requires that an unrecognized tax benefit be presented as a reduction to a deferred tax asset for net operating loss carryforwards, similar tax losses or tax credit carryforwards, with certain exceptions. The guidance became effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. TEC has adopted this guidance and it has no effect on TEC’s results of operations, financial position or cash flows.

34

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.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $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. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both March 31, 2014 and Dec. 31, 2013.

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.

35

Details of the regulatory assets and liabilities as of March 31, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Regulatory assets:
Regulatory tax asset (1)	$	67.9	$	67.4
Other:
Cost-recovery clauses		3.3		6.1
Postretirement benefit asset		180.2		182.7
Deferred bond refinancing costs (2)		7.8		8.0
Environmental remediation		51.4		51.4
Competitive rate adjustment		3.4		4.1
Other		7.5		7.7
Total other regulatory assets		253.6		260.0
Total regulatory assets		321.5		327.4
Less: Current portion		32.7		34.3
Long-term regulatory assets	$	288.8	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.8	$	9.8
Other:
Cost-recovery clauses		58.9		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.7		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		591.8		594.0
Total other regulatory liabilities		709.3		707.4
Total regulatory liabilities		715.1		717.2
Less: Current portion		90.1		85.8
Long-term regulatory liabilities	$	625.0	$	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
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Clause recoverable (1)	$	6.7	$	10.2
Components of rate base (2)		183.2		185.6
Regulatory tax assets (3)		67.9		67.4
Capital structure and other (3)		63.7		64.2
Total	$	321.5	$	327.4

(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, 2014 and 2013 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

36

The IRS concluded its examination of TECO Energy’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. 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 2010 and forward.

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 in Note 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, 2014 and 2013, respectively, was $3.8 million and $5.3 million for pension benefits, and $2.6 million and $2.6 million for other postretirement benefits.

For the fiscal 2014 plan year, TECO Energy assumed a long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $16.0 million to its pension plan in the first quarter of 2014. TEC’s portion of the contributions was $13.0 million.

Included in the benefit expenses discussed above, for the three months ended March 31, 2014, TEC reclassed $2.5 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

At March 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2014						Dec. 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		29.0		0.0		150.0		78.0		0.0
Total	$	475.0	$	29.0	$	0.7	$	475.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

At March 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2014 and Dec. 31, 2013 was 0.63% and 0.56%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 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. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 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, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

37

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2014, TEC’s total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,058.4 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,042.0 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

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 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, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees were maintaining a suit against TEC in Hillsborough County Circuit Court, Florida 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 the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014 all plaintiffs voluntarily dismissed their suits with prejudice.

TEC believes the claims in each of the pending actions described above in this item are without merit and intends to defend each matter vigorously. TEC 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 Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $38.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated 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, most 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. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

38

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, 2014 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2014		2015-2018		2018		Total		at Mar. 31, 2014
Tampa Electric Company (2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2018.

(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, 2014. 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, 2014, TEC was in compliance with all applicable financial covenants.

9. Segment Information

(millions)	Tampa		Peoples		Other &			Tampa Electric
Three months ended Mar. 31,	Electric		Gas		Eliminations			Company
2014
Revenues - external	$	453.1	$	122.4	$	0.0		$	575.5
Sales to affiliates		0.1		0.2		(0.3	)		0.0
Total revenues		453.2		122.6		(0.3	)		575.5
Depreciation and amortization		62.1		13.3		0.0			75.4
Total interest charges		22.0		3.4		0.0			25.4
Provision for income taxes		26.6		9.2		0.0			35.8
Net income	$	45.2	$	14.6	$	0.0		$	59.8
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
Total assets at Mar. 31, 2014	$	5,871.0	$	999.4	($	5.1	)	$	6,865.3
Total assets at Dec. 31, 2013	$	5,895.4	$	989.3	($	8.9	)	$	6,875.8

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

39

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 (see Note 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, 2014, 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, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	15.5	$	9.5
Long-term assets		0.2		0.3
Total assets	$	15.7	$	9.8
Current liabilities (1)	$	0.0	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.1	$	0.2

(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 ending balance in AOCI related to previously settled interest rate swaps at March 31, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

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, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
	Gross Amounts			Gross Amounts offset on the Balance Sheet			Net Amounts of
	of Recognized						Assets (Liabilities)
	Assets						Presented on the
(millions)	(Liabilities)						Balance Sheet
Mar. 31, 2014
Description
Derivative assets	$	16.0		$	(0.3	)	$	15.7
Derivative liabilities	$	(0.4	)	$	0.3		$	(0.1	)
Dec. 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)

40

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of March 31, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Mar. 31, 2014	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	15.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.1
Total		$	15.7		$	0.1
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Dec. 31, 2013	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Based on the fair value of the instruments at March 31, 2014, net pretax losses of $15.5 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)
2014
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Total	$	0.0			($	0.2	)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Total	$	0.0			($	0.2	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2014 and 2013, all hedges were effective.

41

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of March 31, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

	Natural Gas Contracts (MMBTUs)
(millions)
Year	Physical		Financial
2014		0.0		26.9
2015		0.0		18.5
2016		0.0		1.7
Total		0.0		47.1

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, 2014, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were 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. TEC 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 risk in determining the fair value of counterparty positions. 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 in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2014, substantially all positions with counterparties were net assets.

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. Substantially all of TEC’s open positions with counterparties as of March 31, 2014 were asset positions.

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, 2014 and Dec. 31, 2013. 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.

42

Recurring Derivative Fair Value Measures
	At fair value as of Mar. 31, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	15.7	$	0.0	$	15.7
Total	$	0.0	$	15.7	$	0.0	$	15.7
Liabilities
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Total	$	0.0	$	0.1	$	0.0	$	0.1

	At fair value as of Dec. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Total	$	0.0	$	9.8	$	0.0	$	9.8
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2

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 (see Note 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, 2014, 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
2014
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
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
Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2014						Dec. 31, 2013
Net unrealized losses from cash flow hedges (1)	($	7.6	)				($	7.8	)
Total accumulated other comprehensive loss	($	7.6	)				($	7.8	)

(1) Net of tax benefit of $4.7 million and $4.9 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

43

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 160 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 $5.9 million and $4.9 million of capacity pursuant to PPAs for the three months ended March 31, 2014 and 2013, respectively.

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.

44

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, including the required approval by the New Mexico Public Regulation Commission for the acquisition of NMGC; the risk that the transaction to acquire NMGC may be delayed, may be consummated on less favorable terms than originally expected, or not be consummated at all; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required, including the permanent financing for the acquisition of NMGC; 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 alternate fuels used for power generation affecting demand for TECO Coal’s thermal coal production; operating costs and environmental or safety regulations affecting production levels and margins at TECO Coal; weak demand and market pricing conditions affecting the value of TECO Coal’s facilities and coal reserves; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost at all of the operating companies; natural gas demand at the utilities; 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, 2013.

Earnings Summary - Unaudited
	Three months ended Mar. 31,
(millions, except per share amounts)	2014		2013
Consolidated revenues	$	684.1	$	661.1
Continuing operations		47.0		41.2
Discontinued operations		3.1		0.3
Net income	$	50.1	$	41.5
Average common shares outstanding
Basic		215.2		214.6
Diluted		215.7		215.6
Earnings per share - Basic
Continuing operations	$	0.22	$	0.19
Discontinued operations		0.01		0.0
Earnings per share - Basic	$	0.23	$	0.19
Earnings per share - Diluted
Continuing operations	$	0.22	$	0.19
Discontinued operations		0.01		0.0
Earnings per share - Diluted	$	0.23	$	0.19

Operating Results

Three Months Ended Mar. 31, 2014

TECO Energy, Inc. reported first-quarter 2014 net income of $50.1 million, or $0.23 per share, compared with $41.5 million, or $0.19 per share, in the first quarter of 2013. Net income from continuing operations was $47.0 million, or $0.22 per share, in the 2014 first quarter, compared with $41.2 million, or $0.19 per share, for the same period in 2013. First-quarter results include $2.1 million of costs associated with the pending acquisition of New Mexico Gas Co. (NMGC).

The 2014 first-quarter benefit of $3.1 million reported in discontinued operations was related to the release of an indemnification associated with the 2012 sale of TECO Guatemala.

Operating Company Results

All amounts included in the operating company discussions below are after tax, unless otherwise noted.

45

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the first quarter of 2014 was $45.2 million, compared with $31.8 million for the same period in 2013. Results for the quarter reflected the benefits of the rate case settlement effective Nov. 1, 2013, a 1.8% higher average number of customers, higher energy sales primarily due to more favorable weather, and $0.8 million lower earnings on assets recovered through the ECRC due to a lower current weighted average cost of capital, which includes the lower ROE in the 2013 rate case settlement. Results reflected lower interest and essentially unchanged operations and maintenance expenses, partially offset by higher depreciation expense. First-quarter net income in 2014 included $2.4 million of AFUDC- equity, which represents allowed equity cost capitalized to construction costs, compared with $1.1 million in the 2013 quarter.

Total degree days in Tampa Electric’s service area in the first quarter of 2014 were 2% below normal, and 7% above the 2013 period, due to colder weather in January 2014, partially offset by very mild weather in March. In comparison, 2013 weather was very mild throughout the quarter without normal heating or air conditioning load. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 2.4% in the first quarter of 2014 compared with the same period in 2013. In the 2014 period, pretax base revenues were almost $22 million higher than in 2013 including approximately $14 million of higher revenue as a result of the 2013 rate case settlement. (The quarterly energy sales shown on the statistical summary below reflects the energy sales based on the timing of billing cycles, which can vary period to period.) Sales to residential customers increased 5.7%, reflecting customer growth and more favorable winter weather. Sales to industrial customers increased due to the improving economy. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, was essentially unchanged from the 2013 quarter, reflecting $1.6 million of higher costs to operate and maintain the generation and energy delivery systems, offset by the elimination of the $1.2 million storm damage accrual as a result of the 2013 rate case settlement, and lower pension and other expenses. Depreciation and amortization expense increased $1.9 million in 2014 primarily as a result of normal additions to facilities to reliably serve customers, partially offset by approximately $1.0 million of lower amortization on software due to the change in expected useful life for software in the 2013 rate case settlement.

A summary of Tampa Electric’s regulated operating statistics for the three months ended March 31, 2014 and 2013 follows:

(millions, except average customers)	Operating Revenues									Kilowatt-hour sales
Three months ended Mar. 31,	2014			2013			% Change			2014		2013		% Change
By Customer Type
Residential	$	213.5		$	189.6			12.6			1,822.9		1,725.3		5.7
Commercial		134.9			130.7			3.2			1,350.9		1,353.2		(0.2	)
Industrial – Phosphate		16.7			17.8			(6.2	)		208.3		222.0		(6.2	)
Industrial – Other		24.3			23.3			4.3			267.9		262.9		1.9
Other sales of electricity		42.5			41.4			2.7			421.8		420.5		0.3
Deferred and other revenues (1)		(1.9	)		(2.8	)		(32.1	)
Total energy sales	$	430.0		$	400.0			7.5			4,071.8		3,983.9		2.2
Sales for resale		7.0			1.3			438.5			106.4		40.8		160.8
Other operating revenue		16.2			16.7			(3.0	)		0.0		0.0		0.0
Total revenues	$	453.2		$	418.0			8.4			4,178.2		4,024.7		3.8
Average customers (thousands)		702.3			690.2			1.8
Retail net energy for load (kilowatt hours)											4,185.2		4,088.0		2.4

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

Tampa Electric Company – Natural Gas Division

PGS reported net income of $14.6 million for the first quarter, compared with $13.8 million in 2013. First-quarter results in 2014 reflected slightly higher general non-fuel operations and maintenance expense partially offset by a $1.6 million recovery of costs incurred in a 2010 contractor damage incident. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers, partially offset by a change in software amortization similar to Tampa Electric’s discussed above. Average customer growth was 1.6% in the quarter, and therm sales to residential customers increased as a result of colder winter weather. Sales to power generation customers and off-system sales decreased due to two power generators not operating, new participants in the market, and higher natural gas prices in 2014 compared to 2013.

46

A summary of PGS’s regulated operating statistics for the three months ended March 31, 2014 and 2013 follows:

(millions, except average customers)	Operating Revenues							Therms
Three months ended Mar. 31,	2014		2013		% Change			2014		2013		% Change
By Customer Type
Residential	$	49.7	$	42.3		17.5			33.2		29.5		12.5
Commercial		40.9		39.2		4.3			131.0		124.8		5.0
Industrial		3.6		3.6		0.0			72.0		71.3		1.0
Off system sales		8.5		18.3		(53.6	)		15.4		50.4		(69.4	)
Power generation		1.9		3.1		(38.7	)		155.6		205.0		(24.1	)
Other revenues		16.0		12.4		29.0			0.0		0.0		0.0
Total	$	120.6	$	118.9		1.4			407.2		481.0		(15.3	)
By Sales Type
System supply	$	71.7	$	74.1		(3.2	)		57.4		89.9		(36.2	)
Transportation		32.9		32.4		1.5			349.8		391.1		(10.6	)
Other revenues		16.0		12.4		29.0			0.0		0.0		0.0
Total	$	120.6	$	118.9		1.4			407.2		481.0		(15.3	)
Average customers (thousands)		351.9		346.4		1.6

TECO Coal

TECO Coal reported a first-quarter loss of $1.6 million on sales of 1.3 million tons, compared with net income of $3.0 million on similar sales volumes in the same period in 2013. In 2014, first-quarter results reflect an average net selling price, excluding transportation allowances, of more than $79 per ton, almost $11 per ton lower than in 2013. In the first quarter of 2014, the all-in total per-ton cost of sales was $82 per ton, compared with almost $88 per ton in the 2013 period. First quarter sales volumes were reduced by rail service interruptions due to the harsh winter weather in 2014. TECO Coal recorded a $2.2 million income tax benefit in the first quarter of 2014 that included a $0.7 million tax depletion benefit, compared with a $0.1 million tax benefit that included a $1.1 million tax depletion benefit, in the 2013 period.

Parent & other

The cost from continuing operations for Parent & other in the first quarter of 2014 was $11.2 million, compared with a cost of $7.4 million in the same period in 2013. The 2014 results included $2.1 million of costs associated with the pending acquisition of NMGC. Results in 2014 reflect lower results at the smaller unregulated companies reported in Parent & other and unfavorable tax adjustments compared to 2013.

2014 Guidance

TECO Energy expects the Florida regulated utility operations, net of Parent & other, to deliver earnings in a range between $1.00 and $1.05 in 2014, and expects consolidated 2014 earnings in a range between $0.95 and $1.05.

The above guidance excludes any impact from the pending acquisition of NMGC. Revised guidance will be provided upon the closing of that acquisition and completion of related financing actions. TECO Energy expects earnings in 2014 to be driven by the factors discussed below.

Tampa Electric expects to earn in the middle of its authorized allowed ROE range of 9.25% to 11.25%, driven by approximately $50 million of higher base revenues in 2014 as a result of its September 2013 rate case settlement agreement. It expects customer growth of 1.5% and total retail energy sales growth about 0.5% lower than customer growth due to lower average customer usage. Operations and maintenance expenses are expected to be lower than 2013 actual amounts due to lower employee-related costs, lower storm damage expense accruals and lower pension expense driven by higher discount rate assumptions, partially offset by increased expenses to operate the system and reliably serve customers. Depreciation expense is expected to be higher due to normal additions to facilities to serve customers.

Peoples Gas expects to continue to earn above the middle of its allowed ROE range of 9.75% to 11.75% from moderate customer growth, in line with the trends experienced in 2013. 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.

The expectations for both Tampa Electric and Peoples Gas assume normal weather for 2014.

TECO Coal has 90% of its expected sales contracted and priced for 2014 and 10% committed but unpriced. Total sales are expected toward the high end of the 5.5 million to 6.0 million ton range previously forecast, reflecting almost 70% specialty coal. At prices currently being paid for its products, about $80 per ton, TECO Coal expects to be about earnings breakeven for the year, and cash flow positive. However, the unpriced tons are subject to quarterly met coal price adjustments, and the most recent quarterly Asian benchmark pricing is below the level at which TECO Coal’s current prices were set. The all-in cost of sales is expected to be in a range between $79 and $83 per ton. The cash cost of sales, which excludes depreciation and allocated interest, is expected to be about $7 per ton below the all-in cost. In 2014, TECO Coal expects to continue to record tax depletion tax benefits. TECO Coal’s 2014 financial results may be adversely affected by rail service disruptions as a result of a tunnel fire on the railroad serving its Premier Elkhorn facility that began on April 26. At this time there is no estimate as to extent of the damage to the rail facilities or duration of any service disruptions.

47

New Mexico Gas Co. Acquisition

As previously disclosed, TECO Energy must obtain approval for the acquisition from the NMPRC prior to closing the transaction. Hearings before the hearing examiner concluded on April 3.

The current schedule calls for the parties to submit post-hearing briefs on May 2, with reply briefs due May 15. Following the submittal of briefs the hearing examiner will provide a recommendation to the NMPRC. The schedule for the hearing examiner’s recommendation and the NMPRC’s final decision has not been established but we expect to close the transaction by mid to late third quarter this year.

Below is a partial list of the benefits to New Mexico and NMGC customers offered by the Joint Applicants (TECO Energy, NMGC and its current owner, Continental Energy) in the course of the proceedings.

• No rate increases prior to mid-2017

• Bill credits of $2 million in year one, and $4 million for each year following closing, until base rates are reset in a future base rate proceeding

• Maintain NMGC headquarters in New Mexico

• No more than 99 positions eliminated at NMGC in the first three years

• Maintain customer-facing positions, offices and facilities to safely and reliably serve customers

• Customer service and field offices will not be closed without NMPRC approval

• NMGC will not seek to recover transaction costs or acquisition premium through rates

• TECO agrees to invest an average of $30 million on an annual basis in the NMGC system to ensure reliability and safety until the final order in NMGC’s next general rate case

• TECO and NMGC agree to engage in economic development opportunities, including a study for the prospects for growth in the use of compressed natural gas

Including the effects of the items described above, TECO Energy expects the transaction to begin to be accretive to earnings twelve months after closing.

Income Taxes

The provisions for income taxes from continuing operations for the three-month periods ended March 31, 2014 and 2013 were $26.7 million and $23.2 million, respectively. The provision for income taxes for the three months ended March 31, 2014 was impacted by higher operating income and decreased depletion benefit at TECO Coal.

Liquidity and Capital Resources

The table below sets forth the March 31, 2014 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, 2014
(millions)			Tampa Electric		Other		TECO
	Consolidated		Company		Companies		Finance/Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts/Letters of Credit		29.7		29.7		0.0		0.0
Available credit facilities		645.3		445.3		0.0		200.0
Cash and short-term investments		137.0		16.9		4.1		116.0
Total liquidity	$	782.3	$	462.2	$	4.1	$	316.0

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. 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, 2014, 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, 2014. Reference is made to the specific agreements and instruments for more details.

48

Significant Financial Covenants
(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Mar. 31, 2014
TEC
Credit facility(2)	Debt/capital	Cannot exceed 65%	45.0%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%	45.0%
6.25% senior notes	Debt/capital Limit on liens(3)	Cannot exceed 60% Cannot exceed $700	45.0% $0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	Debt/capital	Cannot exceed 65%	55.6%
TECO Finance 6.75% notes	Restrictions on secured debt(4)	(5)	(5)

(1) As defined in each applicable instrument.

(2) See Note 6 to the TECO 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.

Credit Ratings of Senior Unsecured Debt at March 31, 2014
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	A2	A-
TECO Energy/TECO Finance	BBB	Baa1	BBB

On Jan. 30, 2014, Moody’s upgraded the credit ratings of TECO Energy, TECO Finance and TEC. TECO Energy and TECO Finance senior unsecured debt is rated Baa1, up from Baa2, and TEC’s senior unsecured debt is rated A2, up from A3, all with stable outlooks.

On May 30, 2013, Fitch placed the rating of TECO Energy, TECO Finance and TEC on ratings watch negative following the announcement of our agreement to purchase NMGC. On Oct. 9, 2013, Fitch removed TEC from ratings watch negative and affirmed its ratings. 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 credit 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 (see Note 12 to the TECO Energy Consolidated 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 (see the Risk Factors section). 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 in Notes 7 and 13 to the TECO Energy, Inc. Consolidated Condensed Financial Statements. In addition, the company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance

49

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, 2014, 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, see TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013.

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 4% from Dec. 31, 2013 to March 31, 2014. For natural gas, the company maintained a similar volume hedged as of March 31, 2014 from Dec. 31, 2013.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the three month period ended March 31, 2014:

Changes in Fair Value of Derivatives (millions)
Net fair value of derivatives as of Dec. 31, 2013	$	9.7
Additions and net changes in unrealized fair value of derivatives		16.6
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		(10.7	)
Net fair value of derivatives as of Mar. 31, 2014	$	15.6

Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2013	$	9.7
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		16.6
Recorded in earnings		0.0
Realized net settlement of derivatives		(10.7	)
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Mar. 31, 2014	$	15.6

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at March 31, 2014:

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)		15.5		0.1		15.6
Model prices (2)		0.0		0.0		0.0
Total	$	15.5	$	0.1	$	15.6

(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.

50

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.

51

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:

	Total Number of Shares (or Units) Purchased(1)		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2014 - Jan. 31, 2014		2,088	$	16.84		0.0	$	0.0
Feb. 1, 2014 - Feb. 28, 2014		10,382	$	16.70		0.0	$	0.0
Mar. 1, 2014 - Mar. 31, 2014		1,280	$	16.59		0.0	$	0.0
Total 1st Quarter 2014		13,750	$	16.71		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 in Exhibit 95 to this quarterly report.

Item 6. EXHIBITS

Exhibits - See index on page 54.

52

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 2, 2014	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 2, 2014	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)

53

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.
10.2	Omnibus Amendment No. 12 to Loan and Servicing Agreement dated as of Feb. 14, 2014, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citibank, N.A. as Program Agent. (Exhibit 10.37, Form 10-K for 2013 of TECO Energy, Inc. and Tampa Electric Company).	*
12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.
12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.
31.1	Certification of the Chief Executive Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes -Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer of TECO Energy, Inc. pursuant to Securities Exchange Act Rules 13a- 14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes -Oxley Act of 2002.
31.3	Certification of the Chief Executive Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes -Oxley Act of 2002.
31.4	Certification of the Chief Financial Officer of Tampa Electric Company pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes -Oxley Act of 2002.
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of TECO Energy, Inc. pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes -Oxley Act of 2002. (1)
32.2	Certification of the Chief Executive Officer and Chief Financial Officer of Tampa Electric Company pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes -Oxley Act of 2002. (1)
95	Mine Safety Disclosure
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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

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

54

EX-10.1

Exhibit 10.1

TECO ENERGY, INC.

2010 EQUITY INCENTIVE PLAN

Restricted Stock Agreement

TECO Energy, Inc. (the “Company”) and                      (the “Grantee”) have entered into this Restricted Stock Agreement (the “Agreement”) dated                  under the Company’s 2010 Equity Incentive Plan (the “Plan”). Capitalized terms not otherwise defined herein have the meanings given to them in the Plan.

1. Grant of Restricted Stock; Shareholder Approval. Pursuant to the Plan and subject to the terms and conditions set forth in this Agreement, the Company hereby grants, issues and delivers to the Grantee                  shares of its Common Stock (the “Restricted Stock”). Notwithstanding the foregoing, the Restricted Stock is granted subject to shareholder approval of Amendment No. 1 to the Plan at the Company’s 2014 Annual Meeting, and such grant shall be null and void in all respects if and upon the Company’s shareholders’ failure to approve Amendment No. 1 to the Plan at such meeting.

2. Restrictions on Stock. Until the restrictions terminate under Section 3, unless otherwise determined by the Committee:

(a) the Restricted Stock may not be sold, assigned, pledged or transferred by the Grantee; and

(b) all shares of Restricted Stock will be forfeited and returned to the Company if the Grantee ceases to be an employee of the Company or any business entity in which the Company owns directly or indirectly 50% or more of the total voting power or has a significant financial interest as determined by the Committee (an “Affiliate”).

3. Termination of Restrictions. If the Performance Goal as defined on Schedule A hereto is achieved, the restrictions on shares of Restricted Stock will terminate on the earliest to occur of the following events, as follows:

(a) on the Vesting Date (as defined on Schedule A hereto) following the third anniversary of the date of this Agreement the restrictions on all shares of Restricted Stock will terminate;

(b) on the Vesting Date following the termination of Grantee’s employment with the Company or any Affiliate because of a disability that would entitle the Grantee to benefits under the long-term disability benefits program of the Company for which the Grantee is eligible, as determined by the Committee, the restrictions on a prorated portion of shares of Restricted Stock will terminate based on the number of months Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this Agreement to the date of termination, divided by 36;

(c) on the Vesting Date following the termination by the Company or any Affiliate of Grantee’s employment other than for Cause, the restrictions on a prorated portion of shares of Restricted Stock will terminate based on the number of months Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this Agreement to the date of termination, divided by 36. “Cause” means (i) the willful and continued failure by Grantee to substantially perform Grantee’s duties with the Company (other than any such failure resulting from Grantee’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination by Grantee for Good Reason, each as defined in Section 3(f)) after a written demand for substantial performance is delivered to Grantee by the Board, which demand specifically identifies the manner in which the Board believes that Grantee has not substantially performed Grantee’s duties, or (ii) the willful engaging by Grantee in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise. For purposes of this Subsection, no act, or failure to act, on Grantee’s part shall be deemed “willful” unless done, or omitted to be done, by Grantee not in good faith and without reasonable belief that Grantee’s action or omission was in the best interest of the Company. Notwithstanding the foregoing, Grantee shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to Grantee a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters (3/4) of the entire membership of the Board at a meeting of the Board called and held for such purpose (after reasonable notice to Grantee and an opportunity for Grantee, together with Grantee’s counsel, to be heard before the Board), finding that in the good faith opinion of the Board Grantee were guilty of conduct set forth above in this Subsection and specifying the particulars thereof in detail;

(d) on the Vesting Date following a termination of Grantee’s employment that the Committee determines will constitute a normal retirement for purposes of this Agreement, the restrictions on a prorated portion of shares of Restricted Stock will terminate based on the number of months Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this Agreement to the date of termination, divided by 36;

(e) on the Vesting Date following the Grantee’s death, the restrictions on a prorated portion of shares of Restricted Stock will terminate based on the number of months Grantee was employed (with partial months rounded up to the nearest whole month) beginning on the date of this Agreement to the date of Grantee’s death, divided by 36; or

(f) on the Vesting Date following the termination of Grantee’s employment other than by the Company for Cause or by Grantee without Good Reason within 24 months following a Change in Control, or prior to a Change in Control under circumstances described in the next sentence. For purposes of this Agreement, Grantee’s employment shall be deemed to have been terminated following a Change in Control of the Company by the Company without Cause or by Grantee with Good Reason, if (i) Grantee’s employment is terminated by the Company without Cause prior to a Change in Control of the Company (whether or not such a Change in Control ever occurs) and such termination was at the request or direction of a “person” (as defined in Section 4) who has entered into an agreement with the Company the consummation of which would constitute a Change in Control of the Company, (ii) Grantee terminates Grantee’s employment for Good Reason prior to a Change in Control of the Company

2

(whether or not such a Change in Control ever occurs) and the circumstance or event which constitutes Good Reason occurs at the request or direction of such person, or (iii) Grantee’s employment is terminated by the Company without Cause or by Grantee for Good Reason and such termination or the circumstance or event which constitutes Good Reason is otherwise in connection with or in anticipation of a Change in Control of the Company (whether or not such a Change in Control ever occurs).

(i) A “Change in Control” means a Change in Control of the Company of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), whether or not the Company is in fact required to comply therewith; provided, that, without limitation, such a Change in Control shall be deemed to have occurred if:

(a) any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), other than the Company, any trustee or other fiduciary holding securities under an employee benefit plan of the Company or a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company, is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 30% or more of the combined voting power of the Company’s then outstanding securities;

(b) the following individuals cease to constitute a majority of the number of directors then serving: individuals who on the date hereof constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation, relating to the election of directors of the Company) whose election by the Board or nomination for election by the shareholders of the Company was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on the date hereof or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority thereof;

(c) there is consummated a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any other corporation, other than (i) a merger or consolidation resulting in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50% of the combined voting securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation or (ii) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no “person” (as hereinabove defined) acquires 30% or more of the combined voting power of the Company’s then outstanding securities; or

(d) the shareholders of the Company approve a plan of complete liquidation of the Company or there is consummated the sale or disposition by the Company of all or substantially all of the Company’s assets.

3

(ii) “Good Reason” for termination by Grantee of Grantee’s employment shall mean the occurrence (without Grantee’s express written consent) after any Change in Control of the Company, or prior to a Change in Control of the Company under the circumstances described in the second sentence of Section 3(f) hereof (treating all references in paragraphs (a) through (h) below to a “Change in Control of the Company” as references to a “potential Change in Control of the Company”), of any one of the following acts by the Company, or failures by the Company to act:

(a) the assignment to Grantee of any duties inconsistent (except in the nature of a promotion) with the position in the Company that Grantee held immediately prior to the Change in Control of the Company or a substantial adverse alteration in the nature or status of Grantee’s position or responsibilities or the conditions of Grantee’s employment from those in effect immediately prior to the Change in Control of the Company;

(b) a reduction by the Company in Grantee’s annual base salary as in effect on the date hereof or as the same may be increased from time to time;

(c) the Company’s requiring Grantee to be based more than fifty (50) miles from the Company’s offices at which Grantee were principally employed immediately prior to the date of the Change in Control of the Company except for required travel on the Company’s business to an extent substantially consistent with Grantee’s present business travel obligations;

(d) the failure by the Company to pay to Grantee any portion of Grantee’s current compensation or compensation under any deferred compensation program of the Company, within seven (7) days of the date such compensation is due;

(e) the failure by the Company to continue in effect any material compensation or benefit plan in which Grantee participate immediately prior to the Change in Control of the Company unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan, or the failure by the Company to continue Grantee’s participation therein (or in such substitute or alternative plan) on a basis not materially less favorable, both in terms of the amount of benefits provided and the level of Grantee’s participation relative to other participants, than existed at the time of the Change in Control;

(f) the failure by the Company to continue to provide Grantee with benefits substantially similar to those enjoyed by Grantee under any of the Company’s pension, life insurance, medical, health and accident, or disability plans in which Grantee were participating at the time of the Change in Control of the Company, the taking of any action by the Company which would directly or indirectly materially reduce any of such benefits or deprive Grantee of any material fringe benefit enjoyed by Grantee at the time of the Change in Control of the Company, or the failure by the Company to provide Grantee with the number of paid vacation days to which Grantee are entitled on the basis of Grantee’s years of service with the Company in accordance with the Company’s normal vacation policy in effect at the time of the Change in Control of the Company;

4

(g) the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform this Agreement, as contemplated in Section 6 hereof; or

(h) any purported termination of Grantee’s employment which is not effected pursuant to a Notice of Termination satisfying the requirements of Subsection (iii) below (and, if applicable, the requirements of Subsection 3(c) above), which purported termination shall not be effective for purposes of this Agreement.

Grantee’s right to terminate Grantee’s employment pursuant to this Subsection shall not be affected by Grantee’s incapacity due to physical or mental illness. Grantee’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting Good Reason hereunder.

(iii) A “Notice of Termination” shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Grantee’s employment under the provision so indicated.

4. Rights as Shareholder. Subject to the restrictions and other limitations and conditions provided in this Agreement, the Grantee as owner of the Restricted Stock will have all the rights of a shareholder, including but not limited to the right to receive all dividends paid on, and the right to vote, such Restricted Stock.

5. Book Entry. The Restricted Stock will be registered in the name of the Grantee and held by the Company’s transfer agent in uncertificated form in a restricted account. Upon the termination of the restrictions imposed under this Agreement as to any shares of Restricted Stock held by the Company’s transfer agent hereunder, the Company will cause the unrestricted shares to be transferred electronically to Grantee’s brokerage account (or to the account of such Grantee’s legal representative, beneficiary or heir), subject to the withholding provision of Section 8.

6. Adjustment of Terms. In the event of corporate transactions affecting the Company’s outstanding Common Stock, the Committee will equitably adjust the number and kind of shares subject to this Agreement to the extent provided by the Plan.

7. Notice of Election Under Section 83(b). If the Grantee makes an election under Section 83(b) of the Internal Revenue Code of 1986, as amended, he or she will provide a copy thereof to the Company within thirty days of the filing of such election with the Internal Revenue Service.

8. Withholding Taxes. The Grantee will pay to the Company, or make provision satisfactory to the Committee for payment of, any taxes required by law to be withheld in respect of the Restricted Stock no later than the date of the event creating the tax liability. In the Committee’s discretion, such tax obligations may be paid in whole or in part in shares of

5

Common Stock, including the Restricted Stock, valued at Fair Market Value on the date of delivery (which is defined as the closing price on the New York Stock Exchange on the previous trading day). Provided, however, that if any of the events in Section 3 occurs on a date that is not a Business Day, the restrictions on the shares of Restricted Stock shall be deemed to have terminated for the purposes of this Section on the Business Day immediately preceding the date of such event. “Business Day” means any day other than a Saturday or Sunday that is not a day on which the New York Stock Exchange is authorized or required by law or regulations to be closed. The Company and its Affiliates may, to the extent permitted by law, deduct any such tax obligations from any payment of any kind otherwise due to the Grantee.

9. The Committee. Any determination by the Committee under, or interpretation of the terms of, this Agreement or the Plan will be final and binding on the Grantee.

10. Limitation of Rights. The Grantee will have no right to continued employment by virtue of this grant of Restricted Stock.

11. Amendment. The Company may amend, modify or terminate this Agreement, including substituting another Award of the same or a different type and changing the date of realization, provided that the Grantee’s consent to such action will be required unless the action, taking into account any related action, would not adversely affect the Grantee.

12. Governing Law. This Agreement will be governed by and interpreted in accordance with the laws of the State of Florida.

TECO ENERGY, INC.
By:
	Phil L. Barringer
	Chief Human Resources Officer
	Grantee

6

SCHEDULE A

The “Performance Period” is the period beginning January 1, 20     and ending on December 31, 20    , unless one of the events specified in Subsections 3(b) through 3(f) (an “Early Termination Event”) occurs, in which case the Performance Period will end on the last day of the quarter following the Early Termination Event, unless the Early Termination Event occurs on a date that would cause the Performance Period to be shorter than four times as long as the period between the beginning of the Performance Period and the date of this Agreement, then the Performance Period will end on the last day of the quarter after that period of time has elapsed.

The “Performance Goal” for the Performance Period is earnings before interest, taxes, depreciation and amortization (“EBITDA”) of at least $        , which shall be adjusted to exclude the effect of any of the following events that impact EBITDA: (i) any reorganization, merger, consolidation, recapitalization, liquidation, reclassification, stock dividend, stock split, combination of shares, rights offering, extraordinary dividend or divestiture (including a spin-off) or any other change in corporate structure or shares; (ii) any purchase, acquisition, sale, disposition or write-down of a significant amount of assets or a significant business; (iii) any change in accounting principles or practices, tax laws or other such laws or provisions affecting reported results; or (iv) any uninsured catastrophic losses or extraordinary non-recurring items as described in Accounting Principles Board Opinion No. 30, provided that the exclusion of the impact of the foregoing specified events from the calculation of a Performance Goal shall only be made to the extent permitted by Section 162(m) of the Code. If the Performance Period ends prior to December 31, 20     due to the occurrence of an Early Termination Event, the Performance Goal shall be prorated for the number of quarters that elapsed, beginning on January 1, 20     and ending on the last day of the quarter following the Early Termination Event.

The “Vesting Date” is the date of the Compensation Committee’s certification that the Performance Goal has been achieved according to the terms of this paragraph, on which date, if the Performance Goal is achieved, the Restricted Stock will vest, subject to any restrictions on distributions of shares under the Plan and subject to Section 8 of this Agreement. Promptly after the end of the Performance Period, the Company will submit its calculation regarding the Performance Goal to the Compensation Committee for certification. In no event will the Vesting Date be more than 45 days after the end of the Performance Period.

7

EX-12.1

Exhibit 12.1

TECO ENERGY, INC.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth TECO Energy’s ratio of earnings to fixed charges for the periods indicated.

	3-months ended Mar. 31, 2014		12-months ended Mar. 31, 2014
					Year Ended Dec. 31,
(millions)					2013		2012		2011		2010			2009
Income from continuing operations, before income taxes	$	73.7	$	316.0	$	306.7	$	383.8	$	393.5	$	321.2		$	268.3
Add:
Interest expense		44.2		175.9		176.1		189.6		202.4		221.5			223.4
Deduct:
Income from equity investments, net		0.0		0.0		0.0		0.0		0.0		(2.8	)		(0.6	)
Earnings before taxes and fixed charges	$	117.9	$	491.9	$	482.8	$	573.4	$	595.9	$	545.5		$	492.3
Interest expense	$	44.2	$	175.9	$	176.1	$	189.6	$	202.4	$	221.5		$	223.4
Total fixed charges	$	44.2	$	175.9	$	176.1	$	189.6	$	202.4	$	221.5		$	223.4
Ratio of earnings to fixed charges		2.67x		2.80x		2.74x		3.02x		2.94x		2.46x			2.20x

For the purposes of calculating these ratios, earnings consist of income from continuing operations before income taxes, income or loss from equity investments (net of distributions) and fixed charges. Fixed charges consist of interest expense on indebtedness, amortization of debt premium and an estimate of the interest component of rentals. Interest expense includes total interest expense, excluding AFUDC, and an estimate of the interest component of rentals. TECO Energy, Inc. does not have any preferred stock outstanding, and there were no preferred stock dividends paid or accrued during the periods presented.

The sale of TECO Guatemala was completed in December 2012 and is considered a discontinued operation. Prior periods presented have been adjusted to reflect the classification of TECO Guatemala as discontinued operations.

EX-12.2

Exhibit 12.2

TAMPA ELECTRIC COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth Tampa Electric Company’s ratio of earnings to fixed charges for the periods indicated.

	3-months ended Mar. 31, 2014		12-months ended Mar. 31, 2014
					Year Ended Dec. 31,
(millions)					2013		2012		2011		2010		2009
Income from continuing operations, before income taxes	$	95.6	$	385.8	$	364.4	$	368.9	$	380.7	$	386.6	$	303.7
Interest expense		27.8		112.2		112.7		129.9		141.9		143.9		141.2
Earnings before taxes and fixed charges	$	123.4	$	498.0	$	477.1	$	498.8	$	522.6	$	530.5	$	444.9
Interest expense	$	27.8	$	112.2	$	112.7	$	129.9	$	141.9	$	143.9	$	141.2
Total fixed charges	$	27.8	$	112.2	$	112.7	$	129.9	$	141.9	$	143.9	$	141.2
Ratio of earnings to fixed charges		4.44x		4.44x		4.23x		3.84x		3.68x		3.69x		3.15x

For the purposes of calculating these ratios, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges consist of interest expense on indebtedness, amortization of debt premium and an estimate of the interest component of rentals. Interest expense includes total interest expense, excluding AFUDC, and an estimate of the interest component of rentals.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, John B. Ramil, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TECO Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 2, 2014	/s/ J. B. RAMIL
		J. B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of TECO Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 2, 2014	/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)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, John B. Ramil, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 2, 2014	/s/ J. B. RAMIL
		J. B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tampa Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 2, 2014	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting
		and Chief Financial Officer (Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

TECO ENERGY, INC

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of TECO Energy, Inc. (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended March 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 2, 2014	/s/ J. B. RAMIL
		J. B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)
Date:	May 2, 2014	/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)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-Q and shall not be considered filed as part of the Form 10-Q.

EX-32.2

Exhibit 32.2

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended March 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 2, 2014	/s/ J. B. RAMIL
		J. B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)
Date:	May 2, 2014	/s/ S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting
		and Chief Financial Officer
		(Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Form 10-Q and shall not be considered filed as part of the Form 10-Q.

EX-95

Exhibit 95

MINE SAFETY DISCLOSURE

TECO Coal’s subsidiaries operate mining complexes that are subject to regulation by the Mine Safety and Health Administration (MSHA) under the U.S. Federal Mine Safety and Health Act of 1977 (the Mine Act). MSHA inspects TECO Coal mines on a regular basis and issues various citations and orders when it believes that a violation of the Mine Act, any health or safety standard, or any regulation has occurred. Set forth below is information regarding certain mining safety and health orders and citations issued by MSHA and related assessment and legal actions and mine-related fatalities with respect to TECO Coal’s mining operations. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size and type (underground or surface) of the coal mine, (ii) the number of citations and orders issued will vary from inspector to inspector, and (iii) citations and orders can be contested and appealed, and as part of that process, may be reduced in severity and amount, and are sometimes dismissed.

For purposes of reporting regulatory matters under Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the following table sets forth the total number of specific citations and orders issued by MSHA under the Mine Act, along with the total dollar value of the proposed civil penalty assessment, and the total number of fatalities during the current reporting period for each TECO Coal subsidiary that is acting as a coal mine operator, by individual mine. Information relating to the aggregate number of legal actions pending, initiated and resolved during the reporting period is also reported below for each of the mines.

For the quarter ended March 31, 2014 (1)(2)
Mine ID #	Section 104 Significant & Substantial Citations		Section 104(b) Orders		Section 104(d) Citations and Orders		Section 110(b)(2) Violations		Section 107(a) Orders		Proposed MSHA Assessments (in thousands)		Fatalities		Pending Legal Actions (3)(4)		Legal Actions Initiated During Period (3)		Legal Actions Resolved During Period (3)
Clintwood Elkhorn
15-16734		0		0		0		0		0	$	1.0		0		6		0		0
15-19396		1		0		0		0		0		0.0		0		0		0		0
44-03010		4		0		0		0		0		1.0		0		1		1		3
40-07199(5)		6		0		0		0		0		0.0		0		4		0		3
YGX (6)		0		0		0		0		0		0.0		0		3		0		0
Totals		11		0		0		0		0	$	2.0		0		14		1		6
Perry County
15-05485(7)		1		0		0		0		0	$	1.0		0		7		4		20
15-18565		11		0		0		0		0		7.0		0		33		7		23
15-18662		1		0		0		0		0		2.0		0		40		9		4
15-19015		4		0		0		0		0		8.0		0		58		18		5
Totals		17		0		0		0		0	$	18.0		0		138		38		52
Premier Elkhorn
15-16470		0		0		0		0		0	$	0.0		0		0		0		0
15-18823		2		0		0		0		0		8.0		0		8		2		0
15-18946		3		0		0		0		0		0.0		0		0		0		0
15-19622		0		0		0		0		0		2.0		0		0		0		0
15-19649		0		0		0		0		0		0.0		0		0		0		0
15-19721		0		0		0		0		0		0.0		0		0		0		0
A906(8)		0		0		0		0		0		0.0		0		0		0		0
Totals		5		0		0		0		0	$	10.0		0		8		2		0
Grand Totals		33		0		0		0		0	$	30.0		0		160		41		58

1. Based on data obtained from MSHA Mine Data Retrieval System as of April 1, 2014 for the 1st quarter of 2014.

2. No TECO Coal Corporation mining entity has received written notice that it meets the requirements of a Pattern of Violations (POV) during the reporting period.

3. All of the Pending Legal Actions identified in this column are based on data contained in the MSHA Mine Data Retrieval System (MDRS) at the time of data retrieval for this report.

4. All of the Pending Legal Actions involve citations or orders referenced in Subpart B of 29 C.F.R. Part 2700 that are being contested by a TECO Coal Corporation subsidiary.

5. In addition to the number of “Legal Actions Resolved During the Period”, one vacated citation that was shown “In Contest” in the 2013 year-end report is no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

6. YGX is the MSHA “Contractor Identification Number” assigned to Clintwood Elkhorn Mining Company for contracted engineering work performed at a mine that is operated by an independent contract mining company for Clintwood Elkhorn Mining Company.

7. In addition to the number of “Legal Actions Resolved During the Period”, one vacated citation that was shown “In Contest” in the 2013 year-end report is no longer within the MSHA MDRS, and is therefore no longer reflected on this report.

8. A-906 is the MSHA “Contractor Identification Number” assigned to Clintwood Elkhorn Mining Company for contracted engineering work performed at a mine that is operated by an independent contract mining company for Premier Elkhorn Coal Company.

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Regulatory assets:
Regulatory assets	$ 321.5	$ 327.4
Less: Current portion	32.7	34.3
Long-term regulatory assets	288.8	293.1
Regulatory liabilities:
Regulatory liabilities	715.1	717.2
Less: Current portion	90.1	85.8
Long-term regulatory liabilities	625.0	631.4
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	5.8	9.8
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	58.9	54.5
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Deferred Gain on Property Sales [Member]
Regulatory liabilities:
Regulatory liabilities	1.7	2.0
Provision for Stipulation and Other [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	0.8
Accumulated Reserve-Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	591.8	594.0
Total Other Regulatory Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	709.3	707.4
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	67.9	67.4
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	3.3	6.1
Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	180.2	182.7
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	7.8	8.0
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	51.4	51.4
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	3.4	4.1
Other [Member]
Regulatory assets:
Regulatory assets	7.5	7.7
Total Other Regulatory Assets [Member]
Regulatory assets:
Regulatory assets	$ 253.6	$ 260.0

XML

Commitments and Contingencies - Letters of Credit and Guarantees (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Guarantor Obligations [Line Items]
2014	$ 10.8
2015-2018	0.7
After 2018	96.9
Total	108.4
Liabilities Recognized at Mar. 31, 2014	2.4
Tampa Electric Company [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Mar. 31, 2014	0.1
Tampa Electric Company [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Mar. 31, 2014	0.1
TECO Coal [Member] | Fuel Purchase Related [Member]
Guarantor Obligations [Line Items]
2014	0.8
2015-2018	0.7
After 2018	4.0
Total	5.5
Liabilities Recognized at Mar. 31, 2014	2.3
Other Subsidiaries [Member] | Fuel Purchase / Energy Management [Member]
Guarantor Obligations [Line Items]
2014	10.0
2015-2018	0
After 2018	92.9
Total	102.9
Liabilities Recognized at Mar. 31, 2014	$ 0.1

XML

Long-Term Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt, carrying amount	$ 2,921.1	$ 2,921.1
Estimated fair value	3,209.7	3,184.1
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount	1,880.8	1,880.8
Estimated fair value	$ 2,058.4	$ 2,042.0

XML

Subsequent Events - Additional Information (Detail) (TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member], USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended
	Dec. 19, 2013	Mar. 31, 2014
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Subsequent Event [Line Items]
litigation settlement expenses	$ 21.10
litigation settlement interest		U.S. prime rate plus 2%
litigation settlement amount	$ 7.50
Settlement agreement payment term		120 days after the date of the Award

XML

Segment Information - Schedule of Segment Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 684.1	$ 661.1
Depreciation and amortization	84.9	82.0
Total interest charges	41.1	42.4
Internally allocated interest	0	0
Provision (benefit) for income taxes	26.7	23.2
Net income (loss) from continuing operations	47.0	41.2
Income from discontinued operations, net	3.1	0.3
Net income	50.1	41.5
Total assets	7,430.7		7,448.0
Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	2.2	3.3
Depreciation and amortization	0.5	0.3
Total interest charges	14.2	13.9
Internally allocated interest	(1.5)	(1.6)
Provision (benefit) for income taxes	(6.9)	(5.2)
Net income (loss) from continuing operations	(11.2)	(7.4)
Income from discontinued operations, net	3.1	0.3
Net income	(8.1)	(7.1)
Total assets	(40.7)		(16.4)
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	684.1	661.1
Revenues - External [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	2.7	3.5
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0
Sales to Affiliates [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	(0.5)	(0.2)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	453.2	418.0
Depreciation and amortization	62.1	59.0
Total interest charges	22.0	23.4
Internally allocated interest	0	0
Provision (benefit) for income taxes	26.6	19.8
Net income (loss) from continuing operations	45.2	31.8
Income from discontinued operations, net	0	0
Net income	45.2	31.8
Total assets	6,120.8		6,126.9
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	452.9	417.8
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.3	0.2
People Gas [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	122.6	121.9
Depreciation and amortization	13.3	13.0
Total interest charges	3.4	3.4
Internally allocated interest	0	0
Provision (benefit) for income taxes	9.2	8.7
Net income (loss) from continuing operations	14.6	13.8
Income from discontinued operations, net	0	0
Net income	14.6	13.8
Total assets	1,031.1		1,021.2
People Gas [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	122.4	121.9
People Gas [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.2	0
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	106.1	117.9
Depreciation and amortization	9.0	9.7
Total interest charges	1.5	1.7
Internally allocated interest	1.5	1.6
Provision (benefit) for income taxes	(2.2)	(0.1)
Net income (loss) from continuing operations	(1.6)	3.0
Income from discontinued operations, net	0	0
Net income	(1.6)	3.0
Total assets	319.5		316.3
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	106.1	117.9
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	575.5	539.8
Depreciation and amortization	75.4	72.0
Total interest charges	25.4	26.8
Provision (benefit) for income taxes	35.8	28.5
Net income	59.8	45.6
Total assets	6,865.3	6,875.8	6,875.8
Tampa Electric Company [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(0.3)	(0.1)
Depreciation and amortization	0	0
Total interest charges	0	0
Provision (benefit) for income taxes	0	0
Net income	0	0
Total assets	(5.1)	(8.9)
Tampa Electric Company [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	575.5	539.8
Tampa Electric Company [Member] | Revenues - External [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	(0.3)	(0.1)
Tampa Electric Company [Member] | Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	453.2	418.0
Depreciation and amortization	62.1	59.0
Total interest charges	22.0	23.4
Provision (benefit) for income taxes	26.6	19.8
Net income	45.2	31.8
Total assets	5,871.0	5,895.4
Tampa Electric Company [Member] | Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	453.1	417.9
Tampa Electric Company [Member] | Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.1	0.1
Tampa Electric Company [Member] | People Gas [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	122.6	121.9
Depreciation and amortization	13.3	13.0
Total interest charges	3.4	3.4
Provision (benefit) for income taxes	9.2	8.7
Net income	14.6	13.8
Total assets	999.4	989.3
Tampa Electric Company [Member] | People Gas [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	122.4	121.9
Tampa Electric Company [Member] | People Gas [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	$ 0.2	$ 0

XML

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

XML

Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Schedule of Segment Information

The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. All significant intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.

Segment Information (1)
(millions)	Tampa		Peoples		TECO			Other &			TECO
Three months ended Mar. 31,	Electric		Gas		Coal			Eliminations			Energy
2014
Revenues - external	$	452.9	$	122.4	$	106.1		$	2.7		$	684.1
Sales to affiliates		0.3		0.2		0.0			(0.5	)		0.0
Total revenues		453.2		122.6		106.1			2.2			684.1
Depreciation and amortization		62.1		13.3		9.0			0.5			84.9
Total interest charges(1)		22.0		3.4		1.5			14.2			41.1
Internally allocated interest (1)		0.0		0.0		1.5			(1.5	)		0.0
Provision (benefit) for income taxes		26.6		9.2		(2.2	)		(6.9	)		26.7
Net income (loss) from continuing operations		45.2		14.6		(1.6	)		(11.2	)		47.0
Income from discontinued operations, net		0.0		0.0		0.0			3.1			3.1
Net income (loss)	$	45.2	$	14.6	($	1.6	)	($	8.1	)	$	50.1
2013
Revenues - external	$	417.8	$	121.9	$	117.9		$	3.5		$	661.1
Sales to affiliates		0.2		0.0		0.0			(0.2	)		0.0
Total revenues		418.0		121.9		117.9			3.3			661.1
Depreciation and amortization		59.0		13.0		9.7			0.3			82.0
Total interest charges(1)		23.4		3.4		1.7			13.9			42.4
Internally allocated interest (1)		0.0		0.0		1.6			(1.6	)		0.0
Provision (benefit) for income taxes		19.8		8.7		(0.1	)		(5.2	)		23.2
Net income (loss) from continuing operations		31.8		13.8		3.0			(7.4	)		41.2
Income from discontinued operations, net		0.0		0.0		0.0			0.3			0.3
Net income (loss)	$	31.8	$	13.8	$	3.0		($	7.1	)	$	41.5
At Mar. 31, 2014
Total assets	$	6,120.8	$	1,031.1	$	319.5		($	40.7	)	$	7,430.7
At Dec. 31, 2013
Total assets	$	6,126.9	$	1,021.2	$	316.3		($	16.4	)	$	7,448.0

(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 2013 through March 2014 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.

Tampa Electric Company [Member]

Schedule of Segment Information

(millions)	Tampa		Peoples		Other &			Tampa Electric
Three months ended Mar. 31,	Electric		Gas		Eliminations			Company
2014
Revenues - external	$	453.1	$	122.4	$	0.0		$	575.5
Sales to affiliates		0.1		0.2		(0.3	)		0.0
Total revenues		453.2		122.6		(0.3	)		575.5
Depreciation and amortization		62.1		13.3		0.0			75.4
Total interest charges		22.0		3.4		0.0			25.4
Provision for income taxes		26.6		9.2		0.0			35.8
Net income	$	45.2	$	14.6	$	0.0		$	59.8
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
Total assets at Mar. 31, 2014	$	5,871.0	$	999.4	($	5.1	)	$	6,865.3
Total assets at Dec. 31, 2013	$	5,895.4	$	989.3	($	8.9	)	$	6,875.8

XML

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current assets	$ 15.6	$ 9.7
Long-term assets	0.2	0.3
Total assets	15.8	10.0
Current liabilities	0.1	0.1
Long-term liabilities	0.1	0.2
Total liabilities	0.2	0.3
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	32.7	34.3
Long-term assets	0.2	0.3
Long-term liabilities	0.1	0.2
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1	0.2
Long-term assets	0	0
Total assets	0.1	0.2
Current liabilities	0.1	0.1
Long-term liabilities	0	0
Total liabilities	0.1	0.1
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	15.5	9.5
Long-term assets	0.2	0.3
Total assets	15.7	9.8
Current liabilities	0	0
Long-term liabilities	0.1	0.2
Total liabilities	0.1	0.2
Natural Gas Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	15.5	9.5
Long-term assets	0.2	0.3
Total assets	15.7	9.8
Current liabilities	0	0
Long-term liabilities	0.1	0.2
Total liabilities	$ 0.1	$ 0.2

XML

Subsequent Events

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

Subsequent Events

16. Subsequent Events

Pending Acquisition of New Mexico Gas Company

As previously disclosed, TECO Energy must obtain approval for the acquisition from the NMPRC prior to closing the transaction. Hearings before the hearing examiner were concluded on April 3, 2014.

The current schedule calls for the parties to submit post-hearing briefs on May 2, 2014, with reply briefs due May 15, 2014. Following the submittal of briefs, the hearing examiner will provide a recommendation to the NMPRC. The schedule for the hearing examiner’s recommendation and the NMPRC’s final decision has not been established but we expect to close the transaction by mid to late third quarter this year.

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

As previously reported, on Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, Inc., against the Republic of Guatemala (“Guatemala”) under the DR – CAFTA, issued an award in the case (the “Award”). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration. Pursuant to ICSID’s rules and procedures, each party had 120 days after the date of the Award to file an application for its annulment.

On April 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. Guatemala also requested that the enforcement of the Award be stayed while the annulment proceeding is pending. Under the applicable rules, the enforcement of the Award is provisionally stayed until the ad hoc committee that will be deciding Guatemala’s application is constituted and makes a decision regarding whether the stay should continue through the rest of the annulment proceeding.

Also on April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.

While the duration of the annulment proceedings is uncertain, they are expected to take approximately 17 to 24 months to conclude. Pending the outcome of annulment proceedings, results in the first quarter of 2014 do not reflect any benefit of this decision.

XML

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	$ (7.6)	$ (7.8)
Total accumulated other comprehensive loss	(20.7)	(13.2)
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	(7.6)	(7.8)
Total accumulated other comprehensive loss	(7.6)	(7.8)
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit loss, prior service cost and transition obligation	(20.0)	(20.5)
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit loss, prior service cost and transition obligation	$ 6.9	$ 15.1

XML

Income Taxes - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Taxes [Line Items]
Income tax examination period	1 year
Effective tax rate	36.22%	35.95%
Tampa Electric Company [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Income tax examination period	1 year
Minimum [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations	4 years

XML

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Tampa Electric Company [Member]	Mar. 31, 2013 Tampa Electric Company [Member]	Mar. 31, 2014 Unbilled Revenues [Member]	Dec. 31, 2013 Unbilled Revenues [Member]	Mar. 31, 2014 Unbilled Revenues [Member] Tampa Electric Company [Member]	Dec. 31, 2013 Unbilled Revenues [Member] Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues					$ 48.1	$ 46.7	$ 48.1	$ 46.7
Franchise fees and gross receipts taxes	$ 27.2	$ 25.4	$ 27.2	$ 25.4

XML

Earnings Per Share - Schedule of Earnings Per Share (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Basic earnings per share
Net income from continuing operations	$ 47.0	$ 41.2
Amount allocated to nonvested participating shareholders	(0.2)	(0.1)
Income before discontinued operations available to common shareholders-Basic	46.8	41.1
Income from discontinued operations, net	3.1	0.3
Amount allocated to nonvested participating shareholders	0	0
Income from discontinued operations available to common shareholders-Basic	3.1	0.3
Net income	50.1	41.5
Amount allocated to nonvested participating shareholders	(0.2)	(0.1)
Net income available to common shareholders-Basic	49.9	41.4
Average common shares outstanding-Basic	215.2	214.6
Earnings per share from continuing operations available to common shareholders-Basic	$ 0.22	$ 0.19
Earnings per share from discontinued operations available to common shareholders-Basic	$ 0.01	$ 0.00
Earnings per share attributable to TECO Energy - Basic	$ 0.23	$ 0.19
Diluted earnings per share
Net income from continuing operations	47.0	41.2
Amount allocated to nonvested participating shareholders	(0.2)	(0.1)
Income before discontinued operations available to common shareholders-Diluted	46.8	41.1
Income from discontinued operations, net	3.1	0.3
Amount allocated to nonvested participating shareholders	0	0
Income from discontinued operations available to common shareholders-Diluted	3.1	0.3
Net income	50.1	41.5
Amount allocated to nonvested participating shareholders	(0.2)	(0.1)
Net income available to common shareholders-Diluted	$ 49.9	$ 41.4
Unadjusted average common shares outstanding-Diluted	215.2	214.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net	0.5	1.0
Average common shares outstanding-Diluted	215.7	215.6
Earnings per share from continuing operations available to common shareholders-Diluted	$ 0.22	$ 0.19
Earnings per share from discontinued operations available to common shareholders-Diluted	$ 0.01	$ 0.00
Earnings per share attributable to TECO Energy - Diluted	$ 0.23	$ 0.19
Anti-dilutive shares	0	0

XML

Fair Value Measurements - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	$ 15.8	$ 10.0
Total Swap Liabilities	0.2	0.3
Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	15.8	10.0
Total Swap Liabilities	0.2	0.3
Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	$ 0	$ 0

XML

Accounting for Derivative Instruments and Hedging Activities - Energy Related Derivatives (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member]	Mar. 31, 2014 Energy Related Derivatives [Member]	Dec. 31, 2013 Energy Related Derivatives [Member]	Mar. 31, 2013 Energy Related Derivatives [Member] Tampa Electric Company [Member]	Dec. 31, 2012 Energy Related Derivatives [Member] Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	$ 32.7	$ 34.3	$ 15.5	$ 9.5	$ 0	$ 0	$ 0	$ 0
Long-term regulatory assets	288.8	293.1	288.8	293.1	0.1	0.2	0.1	0.2
Regulatory assets	321.5	327.4	321.5	327.4	0.1	0.2	0.1	0.2
Current regulatory liabilities	90.1	85.8	90.1	85.8	15.5	9.5	15.5	9.5
Long-term regulatory liabilities	625.0	631.4	625.0	631.4	0.2	0.3	0.2	0.3
Regulatory liabilities	$ 715.1	$ 717.2			$ 15.7	$ 9.8	$ 15.7	$ 9.8

XML

Short-Term Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified			3 Months Ended		3 Months Ended			3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member]	Mar. 31, 2014 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Feb. 14, 2014 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Mar. 31, 2014 Tampa Electric Company [Member] Minimum [Member]	Mar. 31, 2013 Tampa Electric Company [Member] Minimum [Member]	Mar. 31, 2014 Tampa Electric Company [Member] Maximum [Member]	Mar. 31, 2013 Tampa Electric Company [Member] Maximum [Member]
Line of Credit Facility [Line Items]
Commitment fees, percentage			0.70%		0.70%			0.125%	0.125%	0.30%	0.30%
Weighted-average interest rate			0.63%	0.56%
Amended credit facility	$ 675.0	$ 675.0	$ 475.0	$ 475.0	$ 150.0	$ 150.0	$ 150.0
Debt instrument maturity date			Feb. 13, 2015
Basis spread on federal funds rate			0.50%		0.50%

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Franchise fees and gross receipts taxes	$ 27.2	$ 25.4
Tampa Electric Company [Member]
Franchise fees and gross receipts taxes	27.2	25.4
Tampa Electric Company [Member] | Electric [Member]
Franchise fees and gross receipts taxes	20.3	19.0
Tampa Electric Company [Member] | Gas [Member]
Franchise fees and gross receipts taxes	$ 6.9	$ 6.4

XML

Accounting for Derivative Instruments and Hedging Activities - Effect of Hedging Instruments on Other Comprehensive Income and Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ (0.1)	$ 0.2
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.3)	(0.2)
Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	0
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.2)	(0.2)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.1)	0.2
Location of Gain/(Loss) Reclassified From AOCI Into Income	Mining related costs	Mining related costs
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.1)	0
Interest rate contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	0
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense	Interest expense
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.2)	(0.2)
Interest rate contracts [Member] | Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	0
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense	Interest expense
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ (0.2)	$ (0.2)

XML

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4.1	$ 4.8
Interest cost on projected benefit obligations	8.2	7.2
Expected return on assets	(10.3)	(9.7)
Amortization of:
Prior service cost	(0.1)	(0.1)
Actuarial loss	3.2	5.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	5.1	7.2
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.6	0.7
Interest cost on projected benefit obligations	2.6	2.3
Expected return on assets	0	0
Amortization of:
Prior service cost	0	(0.1)
Actuarial loss	0	0.3
Net pension expense recognized in the Consolidated Condensed Statements of Income	$ 3.2	$ 3.2

XML

Short-Term Debt (Tables)

3 Months Ended

Mar. 31, 2014

Short-Term Debt Credit Facilities

At March 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2014						Dec. 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		29.0		0.0		150.0		78.0		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	$	29.0	$	0.7	$	675.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

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

Tampa Electric Company [Member]

Short-Term Debt Credit Facilities

At March 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2014						Dec. 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		29.0		0.0		150.0		78.0		0.0
Total	$	475.0	$	29.0	$	0.7	$	475.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

XML

Employee Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Compensation And Retirement Disclosure [Abstract]

Schedule of Net Periodic Benefit Cost

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,	2014			2013			2014		2013
Components of net periodic benefit expense
Service cost	$	4.1		$	4.8		$	0.6	$	0.7
Interest cost on projected benefit obligations		8.2			7.2			2.6		2.3
Expected return on assets		(10.3	)		(9.7	)		0.0		0.0
Amortization of:
Prior service cost		(0.1	)		(0.1	)		0.0		(0.1	)
Actuarial loss		3.2			5.0			0.0		0.3
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	5.1		$	7.2		$	3.2	$	3.2

XML

Segment Information - Schedule of Segment Information (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]
Internally allocated interest costs, pre tax rate	6.00%
Capital structure assumption, debt to equity ratio	50.00%

XML

Employee Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.25%
Contributions to pension plan	$ 16.0
Reclassification of AOCI to net income as part of periodic benefit expense	0.6
Reclassification of regulatory assets to net income as part of periodic benefit expense	2.5
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA	7.25%
Contributions to pension plan	13.0
Reclassification of regulatory assets to net income as part of periodic benefit expense	2.5
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.118%
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.118%
Net pension expense	3.8	5.3
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.096%
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.096%
Net pension expense	$ 2.6	$ 2.6

XML

Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2014

Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended March 31, 2014 and 2013, 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
2014
Unrealized loss on cash flow hedges	($	0.1	)	$	0.0		($	0.1	)
Reclassification from AOCI to net income (1)		0.4			(0.1	)		0.3
Gain on cash flow hedges		0.3			(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5
Increase in unrecognized post employment costs (3)		(12.9	)		4.7			(8.2	)
Total other comprehensive loss	($	11.8	)	$	4.3		($	7.5	)
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

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

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

(3) Amount reflects an out-of-period adjustment to unfunded black lung liability.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2014			Dec. 31, 2013
Unrecognized pension loss and prior service credit (1)	($	20.0	)	($	20.5	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		6.9			15.1
Net unrealized losses from cash flow hedges (3)		(7.6	)		(7.8	)
Total accumulated other comprehensive loss	($	20.7	)	($	13.2	)

(1) Net of tax benefit of $12.3 million and $12.6 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

(2) Net of tax expense of $4.4 million and $9.1 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

(3) Net of tax benefit of $4.8 million and $4.9 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2014
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
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

Accumulated Other Comprehensive Loss

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross			Tax			Net
2014
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
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
Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2014						Dec. 31, 2013
Net unrealized losses from cash flow hedges (1)	($	7.6	)				($	7.8	)
Total accumulated other comprehensive loss	($	7.6	)				($	7.8	)

(1) Net of tax benefit of $4.7 million and $4.9 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

XML

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

For the three months ended Mar. 31,
(millions, except per share amounts)	2014			2013
Basic earnings per share
Net income from continuing operations	$	47.0		$	41.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Income before discontinued operations available to common shareholders - Basic	$	46.8		$	41.1
Income from discontinued operations, net	$	3.1		$	0.3
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations available to common shareholders - Basic	$	3.1		$	0.3
Net income	$	50.1		$	41.5
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Net income available to common shareholders - Basic	$	49.9		$	41.4
Average common shares outstanding - Basic		215.2			214.6
Earnings per share from continuing operations available to common shareholders - Basic	$	0.22		$	0.19
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.01		$	0.00
Earnings per share available to common shareholders - Basic	$	0.23		$	0.19
Diluted earnings per share
Net income from continuing operations	$	47.0		$	41.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Income before discontinued operations available to common shareholders - Diluted	$	46.8		$	41.1
Income from discontinued operations, net	$	3.1		$	0.3
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations available to common shareholders - Diluted	$	3.1		$	0.3
Net income	$	50.1		$	41.5
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Net income available to common shareholders - Diluted	$	49.9		$	41.4
Unadjusted average common shares outstanding - Diluted		215.2			214.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			1.0
Average common shares outstanding - Diluted		215.7			215.6
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.22		$	0.19
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.01		$	0.00
Earnings per share available to common shareholders - Diluted	$	0.23		$	0.19
Anti-dilutive shares		0.0			0.0

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Revenues
Total revenues	$ 684.1	$ 661.1
Expenses
Fuel	149.6	140.0
Purchased power	18.2	14.6
Cost of natural gas sold	47.1	49.5
Other	120.6	120.8
Depreciation and amortization	84.9	82.0
Taxes, other than income	56.3	53.3
Total expenses	571.0	557.0
Income from operations	113.1	104.1
Other income
Allowance for other funds used during construction	2.4	1.1
Total other income	1.7	2.7
Interest charges
Interest on long-term debt	42.5	43.0
Allowance for borrowed funds used during construction	(1.4)	(0.6)
Total interest charges	41.1	42.4
Income before provision for income taxes	73.7	64.4
Provision for income taxes	26.7	23.2
Net income	50.1	41.5
Other comprehensive income, net of tax
Total other comprehensive income, net of tax	(7.5)	1.1
Comprehensive income	42.6	42.6
Tampa Electric Company [Member]
Revenues
Electric (includes franchise fees and gross receipts taxes of $20.3 in 2014 and $19.0 in 2013)	453.0	417.9
Gas (includes franchise fees and gross receipts taxes of $6.9 in 2014 and $6.4 in 2013)	122.5	121.9
Total revenues	575.5	539.8
Expenses
Fuel	149.6	140.0
Purchased power	18.2	14.6
Cost of natural gas sold	47.2	49.5
Other	120.3	120.6
Depreciation and amortization	75.4	72.0
Taxes, other than income	47.4	44.5
Total expenses	458.1	441.2
Income from operations	117.4	98.6
Other income
Allowance for other funds used during construction	2.4	1.1
Other income, net	1.2	1.2
Total other income	3.6	2.3
Interest charges
Interest on long-term debt	25.7	26.5
Other interest	1.1	0.9
Allowance for borrowed funds used during construction	(1.4)	(0.6)
Total interest charges	25.4	26.8
Income before provision for income taxes	95.6	74.1
Provision for income taxes	35.8	28.5
Net income	59.8	45.6
Other comprehensive income, net of tax
Amortization of settled interest rate swaps	0.2	0.2
Total other comprehensive income, net of tax	0.2	0.2
Comprehensive income	$ 60.0	$ 45.8

XML

Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2014

Letters of Credit and Guarantees

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of March 31, 2014 is as follows:

Guarantees - TECO Energy
(millions)					After(1) 2018		Total		Liabilities Recognized at Mar. 31, 2014
Guarantees for the Benefit of:	2014		2015-2018
TECO Coal
Fuel purchase related (2)	$	0.8	$	0.7	$	4.0	$	5.5	$	2.3
Other subsidiaries
Fuel purchase/energy management (2)		10.0		0.0		92.9		102.9		0.1
Total	$	10.8	$	0.7	$	96.9	$	108.4	$	2.4
Letters of Credit - Tampa Electric Company
(millions)	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Mar. 31, 2014
Letters of Credit for the Benefit of:
Tampa Electric Company(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.

(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, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Tampa Electric Company [Member]

Letters of Credit and Guarantees

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of March 31, 2014 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2014		2015-2018		2018		Total		at Mar. 31, 2014
Tampa Electric Company (2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2018.

(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, 2014. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2014
Schedule Of Regulatory Assets And Liabilities [Line Items]
Amortization period	5-year
Tampa Electric Company [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Amortization period	5-year

XML

Commitments and Contingencies - Additional Information (Detail) (PGS [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014
PGS [Member]
Site Contingency [Line Items]
Ultimate financial liability to superfund sites and former MGP sites	$ 38.4

XML

Consolidated Condensed Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 137.0	$ 185.2
Receivables, less allowance for uncollectibles	269.1	287.2
Inventories, at average cost
Derivative assets	15.6	9.7
Regulatory assets	32.7	34.3
Deferred income taxes	89.0	100.3
Prepayments and other current assets	35.1	34.9
Income tax receivables	0.8	1.5
Total current assets	783.5	857.7
Property, plant and equipment
Construction work in progress	442.9	386.7
Other property	447.5	448.3
Property, plant and equipment, at original costs	9,185.3	9,077.3
Accumulated depreciation	(2,951.5)	(2,907.2)
Total property, plant and equipment, net	6,233.8	6,170.1
Other assets
Regulatory assets	288.8	293.1
Derivative assets	0.2	0.3
Deferred charges and other assets	124.4	126.8
Total other assets	413.4	420.2
Total assets	7,430.7	7,448.0
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	29.0	84.0
Accounts payable	250.0	261.7
Customer deposits	166.8	164.5
Regulatory liabilities	90.1	85.8
Derivative liabilities	0.1	0.1
Interest accrued	54.8	31.9
Taxes accrued	49.4	34.6
Other	18.3	19.5
Total current liabilities	741.8	765.4
Other liabilities
Deferred income taxes	461.6	444.0
Investment tax credits	9.3	9.4
Regulatory liabilities	625.0	631.4
Derivative liabilities	0.1	0.2
Deferred credits and other liabilities	421.5	426.1
Long-term debt, less amount due within one year	2,837.8	2,837.8
Total other liabilities	4,355.3	4,348.9
Commitments and contingencies (see Note 10)
Capital
Common equity	218.2	217.3
Additional paid in capital	1,585.7	1,581.3
Retained earnings	550.4	548.3
Accumulated other comprehensive loss	(20.7)	(13.2)
Total capital	2,333.6	2,333.7
Total liabilities and capital	7,430.7	7,448.0
Fuel [Member]
Inventories, at average cost
Utility inventories	120.0	118.7
Materials and supplies [Member]
Inventories, at average cost
Utility inventories	84.2	85.9
Electric [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	6,982.4	6,934.0
Gas [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	1,312.5	1,308.3
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	16.9	9.8
Receivables, less allowance for uncollectibles	214.9	227.6
Inventories, at average cost
Derivative assets	32.7	34.3
Regulatory assets	15.5	9.5
Deferred income taxes	20.1	29.4
Prepayments and other current assets	12.7	12.5
Income tax receivables	0	54.9
Total current assets	474.0	548.5
Property, plant and equipment
Construction work in progress	441.2	385.3
Property, plant and equipment, at original costs	8,677.2	8,568.8
Accumulated depreciation	(2,602.7)	(2,562.6)
Public utilities, property, plant and equipment, net	6,074.5	6,006.2
Other property	8.3	8.3
Total property, plant and equipment, net	6,082.8	6,014.5
Other assets
Unamortized debt expense	14.5	14.8
Regulatory assets	288.8	293.1
Derivative assets	0.2	0.3
Deferred charges and other assets	308.5	312.8
Other	5.0	4.6
Total other assets	5.0	4.6
Total assets	6,865.3	6,875.8
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	29.0	84.0
Accounts payable	216.2	226.0
Customer deposits	166.8	164.5
Regulatory liabilities	90.1	85.8
Interest accrued	37.3	16.4
Taxes accrued	39.7	12.2
Other	12.0	12.0
Total current liabilities	674.4	684.2
Other liabilities
Deferred income taxes	1,132.1	1,114.3
Investment tax credits	9.3	9.4
Regulatory liabilities	625.0	631.4
Derivative liabilities	0.1	0.2
Other	295.4	308.1
Long-term debt, less amount due within one year	1,797.5	1,797.5
Total other liabilities	2,061.9	2,063.4
Commitments and contingencies (see Note 10)
Capital
Common equity	2,037.4	2,030.4
Retained earnings	301.7	308.1
Accumulated other comprehensive loss	(7.6)	(7.8)
Total capital	2,331.5	2,330.7
Total capitalization	4,129.0	4,128.2
Total liabilities and capital	6,865.3	6,875.8
Tampa Electric Company [Member] | Fuel [Member]
Inventories, at average cost
Utility inventories	86.1	93.7
Tampa Electric Company [Member] | Materials and supplies [Member]
Inventories, at average cost
Utility inventories	75.1	76.8
Tampa Electric Company [Member] | Electric [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	6,982.4	6,934.0
Tampa Electric Company [Member] | Gas [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	$ 1,253.6	$ 1,249.5

XML

Short-Term Debt - Credit Facilities (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Feb. 14, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Credit Facilities	$ 675.0		$ 675.0
Borrowings Outstanding	29.0		84.0
Letters of Credit Outstanding	0.7		0.7
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit Facilities	475.0		475.0
Borrowings Outstanding	29.0		84.0
Letters of Credit Outstanding	0.7		0.7
Tampa Electric Company [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	325.0		325.0
Borrowings Outstanding	0		6.0
Letters of Credit Outstanding	0.7		0.7
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	150.0	150.0	150.0
Borrowings Outstanding	29.0		78.0
Letters of Credit Outstanding	0		0
TECO Energy [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	200.0		200.0
Borrowings Outstanding	0		0
Letters of Credit Outstanding	$ 0		$ 0

XML

Consolidated Condensed Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net income	$ 50.1	$ 41.5
Other comprehensive income, net of tax
Net unrealized gains on cash flow hedges	0.2	0.4
Amortization of unrecognized benefit costs	0.5	0.7
Increase in unrecognized post employment costs	(8.2)	0
Other comprehensive income, net of tax	(7.5)	1.1
Comprehensive income	$ 42.6	$ 42.6

XML

Accounting for Derivative Instruments and Hedging Activities - Gross Amounts of Derivatives and Their Related Offset Amounts (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	$ 16.1	$ 10.5
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	(0.5)	(0.8)
Derivative assets, Gross Amounts offset on the Balance Sheet	(0.3)	(0.5)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	0.3	0.5
Derivative assets, Net Amounts of Assets	15.8	10.0
Derivative assets, Net Amounts of Liabilities	(0.2)	(0.3)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	16.0	10.3
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	(0.4)	(0.7)
Derivative assets, Gross Amounts offset on the Balance Sheet	(0.3)	(0.5)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	0.3	0.5
Derivative assets, Net Amounts of Assets	15.7	9.8
Derivative assets, Net Amounts of Liabilities	$ (0.1)	$ (0.2)

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Schedule of Recurring Fair Value Measurements

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, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	15.7	$	0.0	$	15.7
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	15.8	$	0.0	$	15.8
Liabilities
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.2	$	0.0	$	0.2

	At fair value as of Dec. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Diesel fuel swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	10.0	$	0.0	$	10.0
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.3	$	0.0	$	0.3

Tampa Electric Company [Member]

Schedule of Recurring Fair Value Measurements

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, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	15.7	$	0.0	$	15.7
Total	$	0.0	$	15.7	$	0.0	$	15.7
Liabilities
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Total	$	0.0	$	0.1	$	0.0	$	0.1
	At fair value as of Dec. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Total	$	0.0	$	9.8	$	0.0	$	9.8
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2

XML

Accounting for Derivative Instruments and Hedging Activities - Fair Value of Overall Contractual Contingent Liability Positions (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair Value Asset/ (Liability)	$ (0.1)
Derivative Exposure Asset/ (Liability)	(0.1)
Posted Collateral	$ 0

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2014

Fair Value Measurements

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, 2014 and Dec. 31, 2013. 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, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	15.7	$	0.0	$	15.7
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	15.8	$	0.0	$	15.8
Liabilities
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.2	$	0.0	$	0.2

	At fair value as of Dec. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Diesel fuel swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	10.0	$	0.0	$	10.0
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.3	$	0.0	$	0.3

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 (see Note 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, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Tampa Electric Company [Member]

Fair Value Measurements

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, 2014 and Dec. 31, 2013. 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, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	15.7	$	0.0	$	15.7
Total	$	0.0	$	15.7	$	0.0	$	15.7
Liabilities
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Total	$	0.0	$	0.1	$	0.0	$	0.1
	At fair value as of Dec. 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Total	$	0.0	$	9.8	$	0.0	$	9.8
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2

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 (see Note 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, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

XML

Discontinued Operations (Tables) (TECO Guatemala [Member])

3 Months Ended

Mar. 31, 2014

TECO Guatemala [Member]

Components of Discontinued Operations

The following table provides selected components of discontinued operations:

Components of income from discontinued operations
(millions)
Three months ended Mar. 31,	2014		2013
Revenues	$	0.0	$	0.0
Income from operations		5.0		0.4
Income from discontinued operations		5.0		0.4
Provision for income taxes		1.9		0.1
Income from discontinued operations, net	$	3.1	$	0.3

XML

Discontinued Operations

3 Months Ended

Mar. 31, 2014

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations

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. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below. The following table provides selected components of discontinued operations:

Components of income from discontinued operations
(millions)
Three months ended Mar. 31,	2014		2013
Revenues	$	0.0	$	0.0
Income from operations		5.0		0.4
Income from discontinued operations		5.0		0.4
Provision for income taxes		1.9		0.1
Income from discontinued operations, net	$	3.1	$	0.3

XML

Variable Interest Entities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 18.2	$ 14.6
Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	18.2	14.6
Power Purchase Agreements [Member] | Variable Interest Entities [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	5.9	4.9
Power Purchase Agreements [Member] | Variable Interest Entities [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 5.9	$ 4.9
Minimum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	117
Minimum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	117
Maximum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	160
Maximum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	160

XML

Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash flows from operating activities
Net income	$ 50.1	$ 41.5
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	84.9	82.0
Depreciation and amortization	84.9	82.0
Deferred income taxes	28.9	23.4
Investment tax credits	(0.1)	(0.1)
Allowance for funds used during construction	(2.4)	(1.1)
Non-cash stock compensation	3.7	3.6
Gain on sales of business/assets, pretax	(0.1)	(0.2)
Deferred recovery clauses	2.6	4.5
Receivables, less allowance for uncollectibles	18.1	13.0
Inventories	0.4	(21.4)
Prepayments and other current assets	(0.2)	0.6
Taxes accrued	15.5	15.8
Interest accrued	22.9	22.1
Accounts payable	(25.2)	(25.0)
Other	(12.2)	(0.8)
Cash flows from operating activities	186.9	157.9
Cash flows from investing activities
Capital expenditures	(136.3)	(103.0)
Allowance for funds used during construction	2.4	1.1
Net proceeds from sales of business/assets	0.2	0.3
Cash flows used in investing activities	(133.7)	(101.6)
Cash flows from financing activities
Dividends	(48.0)	(47.8)
Common stock	1.6	3.9
Net decrease in short-term debt	(55.0)	0
Cash flows used in financing activities	(101.4)	(43.9)
Net (decrease) increase in cash and cash equivalents	(48.2)	12.4
Cash and cash equivalents at beginning of period	185.2	200.5
Cash and cash equivalents at end of period	137.0	212.9
Supplemental disclosure of non-cash activities
Capital expenditures not yet paid	14.6	0.6
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	59.8	45.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	75.4	72.0
Deferred income taxes	22.8	23.3
Investment tax credits	(0.1)	(0.1)
Allowance for funds used during construction	(2.4)	(1.1)
Deferred recovery clauses	2.6	4.5
Receivables, less allowance for uncollectibles	12.7	2.2
Inventories	9.3	(17.2)
Prepayments	(0.2)	(0.1)
Taxes accrued	82.4	39.1
Interest accrued	20.9	20.2
Accounts payable	(23.3)	(21.1)
Other	(9.1)	(0.7)
Cash flows from operating activities	250.8	166.6
Cash flows from investing activities
Capital expenditures	(132.0)	(97.9)
Allowance for funds used during construction	2.4	1.1
Cash flows used in investing activities	(129.6)	(96.8)
Cash flows from financing activities
Dividends	(66.1)	(55.0)
Common stock	7.0	0
Net decrease in short-term debt	(55.0)	0
Cash flows used in financing activities	(114.1)	(55.0)
Net (decrease) increase in cash and cash equivalents	7.1	14.8
Cash and cash equivalents at beginning of period	9.8	45.2
Cash and cash equivalents at end of period	16.9	60.0
Supplemental disclosure of non-cash activities
Capital expenditures not yet paid	$ 14.7	$ 0.6

XML

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Allowance for uncollectibles	$ 4.9	$ 4.7
Common equity, shares authorized	400.0	400.0
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	218.2	217.3
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 2.2	$ 2.0

XML

Other Comprehensive Income

3 Months Ended

Mar. 31, 2014

Other Comprehensive Income

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended March 31, 2014 and 2013, 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
2014
Unrealized loss on cash flow hedges	($	0.1	)	$	0.0		($	0.1	)
Reclassification from AOCI to net income (1)		0.4			(0.1	)		0.3
Gain on cash flow hedges		0.3			(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5
Increase in unrecognized post employment costs (3)		(12.9	)		4.7			(8.2	)
Total other comprehensive loss	($	11.8	)	$	4.3		($	7.5	)
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

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

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

(3) Amount reflects an out-of-period adjustment to unfunded black lung liability.

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2014			Dec. 31, 2013
Unrecognized pension loss and prior service credit (1)	($	20.0	)	($	20.5	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		6.9			15.1
Net unrealized losses from cash flow hedges (3)		(7.6	)		(7.8	)
Total accumulated other comprehensive loss	($	20.7	)	($	13.2	)

(1) Net of tax benefit of $12.3 million and $12.6 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

(2) Net of tax expense of $4.4 million and $9.1 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

(3) Net of tax benefit of $4.8 million and $4.9 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross			Tax			Net
2014
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
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
Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2014						Dec. 31, 2013
Net unrealized losses from cash flow hedges (1)	($	7.6	)				($	7.8	)
Total accumulated other comprehensive loss	($	7.6	)				($	7.8	)

(1) Net of tax benefit of $4.7 million and $4.9 million as of Mar. 31, 2014 and Dec. 31, 2013, respectively.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 25, 2014
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	0000350563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		217,805,680
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

XML

Earnings Per Share

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share

9. Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2014			2013
Basic earnings per share
Net income from continuing operations	$	47.0		$	41.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Income before discontinued operations available to common shareholders - Basic	$	46.8		$	41.1
Income from discontinued operations, net	$	3.1		$	0.3
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations available to common shareholders - Basic	$	3.1		$	0.3
Net income	$	50.1		$	41.5
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Net income available to common shareholders - Basic	$	49.9		$	41.4
Average common shares outstanding - Basic		215.2			214.6
Earnings per share from continuing operations available to common shareholders - Basic	$	0.22		$	0.19
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.01		$	0.00
Earnings per share available to common shareholders - Basic	$	0.23		$	0.19
Diluted earnings per share
Net income from continuing operations	$	47.0		$	41.2
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Income before discontinued operations available to common shareholders - Diluted	$	46.8		$	41.1
Income from discontinued operations, net	$	3.1		$	0.3
Amount allocated to nonvested participating shareholders		0.0			0.0
Income from discontinued operations available to common shareholders - Diluted	$	3.1		$	0.3
Net income	$	50.1		$	41.5
Amount allocated to nonvested participating shareholders		(0.2	)		(0.1	)
Net income available to common shareholders - Diluted	$	49.9		$	41.4
Unadjusted average common shares outstanding - Diluted		215.2			214.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			1.0
Average common shares outstanding - Diluted		215.7			215.6
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.22		$	0.19
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.01		$	0.00
Earnings per share available to common shareholders - Diluted	$	0.23		$	0.19
Anti-dilutive shares		0.0			0.0

XML

Consolidated Condensed Statements of Income (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $27.2 in 2014 and $25.4 in 2013)	$ 575.7	$ 539.1
Unregulated	108.4	122.0
Total revenues	684.1	661.1
Expenses
Fuel	149.6	140.0
Purchased power	18.2	14.6
Cost of natural gas sold	47.1	49.5
Other	120.6	120.8
Operation and maintenance other expense
Mining related costs	91.2	95.5
Other	3.1	1.3
Depreciation and amortization	84.9	82.0
Taxes, other than income	56.3	53.3
Total expenses	571.0	557.0
Income from continuing operations	113.1	104.1
Other income
Allowance for other funds used during construction	2.4	1.1
Other income	(0.7)	1.6
Total other income	1.7	2.7
Interest charges
Interest expense	42.5	43.0
Allowance for borrowed funds used during construction	(1.4)	(0.6)
Total interest charges	41.1	42.4
Income from continuing operations before provision for income taxes	73.7	64.4
Provision for income taxes	26.7	23.2
Net income from continuing operations	47.0	41.2
Discontinued operations
Income from discontinued operations	5.0	0.4
Provision for income taxes	1.9	0.1
Income from discontinued operations, net	3.1	0.3
Net income	$ 50.1	$ 41.5
Average common shares outstanding - Basic	215.2	214.6
Average common shares outstanding - Diluted	215.7	215.6
Earnings per share from continuing operations - Basic	$ 0.22	$ 0.19
Earnings per share from continuing operations - Diluted	$ 0.22	$ 0.19
Earnings per share from discontinued operations - Basic	$ 0.01	$ 0.00
Earnings per share from discontinued operations - Diluted	$ 0.01	$ 0.00
Earnings per share attributable to TECO Energy - Basic	$ 0.23	$ 0.19
Earnings per share attributable to TECO Energy - Diluted	$ 0.23	$ 0.19
Dividends paid per common share outstanding	$ 0.22	$ 0.22

XML

Regulatory

3 Months Ended

Mar. 31, 2014

Regulatory

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.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $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. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both March 31, 2014 and Dec. 31, 2013.

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.

Details of the regulatory assets and liabilities as of March 31, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2014		Dec. 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	67.9	$	67.4
Other:
Cost-recovery clauses		3.3		6.1
Postretirement benefit asset		180.2		182.7
Deferred bond refinancing costs (2)		7.8		8.0
Environmental remediation		51.4		51.4
Competitive rate adjustment		3.4		4.1
Other		7.5		7.7
Total other regulatory assets		253.6		260.0
Total regulatory assets		321.5		327.4
Less: Current portion		32.7		34.3
Long-term regulatory assets	$	288.8	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.8	$	9.8
Other:
Cost-recovery clauses		58.9		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.7		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		591.8		594.0
Total other regulatory liabilities		709.3		707.4
Total regulatory liabilities		715.1		717.2
Less: Current portion		90.1		85.8
Long-term regulatory liabilities	$	625.0	$	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, 2014		Dec. 31, 2013
Clause recoverable (1)	$	6.7	$	10.2
Components of rate base (2)		183.2		185.6
Regulatory tax assets (3)		67.9		67.4
Capital structure and other (3)		63.7		64.2
Total	$	321.5	$	327.4

(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.

Tampa Electric Company [Member]

Regulatory

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.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $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. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both March 31, 2014 and Dec. 31, 2013.

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.

Details of the regulatory assets and liabilities as of March 31, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Regulatory assets:
Regulatory tax asset (1)	$	67.9	$	67.4
Other:
Cost-recovery clauses		3.3		6.1
Postretirement benefit asset		180.2		182.7
Deferred bond refinancing costs (2)		7.8		8.0
Environmental remediation		51.4		51.4
Competitive rate adjustment		3.4		4.1
Other		7.5		7.7
Total other regulatory assets		253.6		260.0
Total regulatory assets		321.5		327.4
Less: Current portion		32.7		34.3
Long-term regulatory assets	$	288.8	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.8	$	9.8
Other:
Cost-recovery clauses		58.9		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.7		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		591.8		594.0
Total other regulatory liabilities		709.3		707.4
Total regulatory liabilities		715.1		717.2
Less: Current portion		90.1		85.8
Long-term regulatory liabilities	$	625.0	$	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
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Clause recoverable (1)	$	6.7	$	10.2
Components of rate base (2)		183.2		185.6
Regulatory tax assets (3)		67.9		67.4
Capital structure and other (3)		63.7		64.2
Total	$	321.5	$	327.4

(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.

XML

New Accounting Pronouncements

3 Months Ended

Mar. 31, 2014

New Accounting Pronouncements

2. New Accounting Pronouncements

Unrecognized Tax Benefits

In July 2013, the FASB issued guidance regarding the presentation of unrecognized tax benefits in the statement of position when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. It requires that an unrecognized tax benefit be presented as a reduction to a deferred tax asset for net operating loss carryforwards, similar tax losses or tax credit carryforwards, with certain exceptions. The guidance became effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. The company has adopted this guidance and it has no effect on the company’s results of operations, financial position or cash flows.

Tampa Electric Company [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Unrecognized Tax Benefits

In July 2013, the FASB issued guidance regarding the presentation of unrecognized tax benefits in the statement of position when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. It requires that an unrecognized tax benefit be presented as a reduction to a deferred tax asset for net operating loss carryforwards, similar tax losses or tax credit carryforwards, with certain exceptions. The guidance became effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. TEC has adopted this guidance and it has no effect on TEC’s results of operations, financial position or cash flows.

XML

Variable Interest Entities

3 Months Ended

Mar. 31, 2014

Variable Interest Entities

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 160 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 $5.9 million and $4.9 million of capacity pursuant to PPAs for the three months ended March 31, 2014 and 2013, respectively.

The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. 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.

Tampa Electric Company [Member]

Variable Interest Entities

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 160 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 $5.9 million and $4.9 million of capacity pursuant to PPAs for the three months ended March 31, 2014 and 2013, respectively.

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.

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies

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, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees were maintaining a suit against TEC in Hillsborough County Circuit Court, Florida 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 the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014 all plaintiffs voluntarily dismissed their suits with prejudice.

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, 2014 TEC has estimated its ultimate financial liability to be $38.4 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, most 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. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

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, 2014 is as follows:

Guarantees - TECO Energy
(millions)					After(1) 2018		Total		Liabilities Recognized at Mar. 31, 2014
Guarantees for the Benefit of:	2014		2015-2018
TECO Coal
Fuel purchase related (2)	$	0.8	$	0.7	$	4.0	$	5.5	$	2.3
Other subsidiaries
Fuel purchase/energy management (2)		10.0		0.0		92.9		102.9		0.1
Total	$	10.8	$	0.7	$	96.9	$	108.4	$	2.4
Letters of Credit - Tampa Electric Company
(millions)	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Mar. 31, 2014
Letters of Credit for the Benefit of:
Tampa Electric Company(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.

(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, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, 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, 2014, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

Tampa Electric Company [Member]

Commitments and Contingencies

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 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, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees were maintaining a suit against TEC in Hillsborough County Circuit Court, Florida 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 the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. In the first quarter of 2014 all plaintiffs voluntarily dismissed their suits with prejudice.

TEC believes the claims in each of the pending actions described above in this item are without merit and intends to defend each matter vigorously. TEC 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 Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $38.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated 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, most 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. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

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, 2014 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2014		2015-2018		2018		Total		at Mar. 31, 2014
Tampa Electric Company (2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

(1) These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2018.

(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, 2014. 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, 2014, TEC was in compliance with all applicable financial covenants.

XML

Short-Term Debt

3 Months Ended

Mar. 31, 2014

Short-Term Debt

6. Short-Term Debt

At March 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2014						Dec. 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		29.0		0.0		150.0		78.0		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	$	29.0	$	0.7	$	675.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

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

At March 31, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2014 and Dec. 31, 2013 was 0.63% and 0.56%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 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. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 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, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

Tampa Electric Company [Member]

Short-Term Debt

6. Short-Term Debt

At March 31, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2014						Dec. 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		29.0		0.0		150.0		78.0		0.0
Total	$	475.0	$	29.0	$	0.7	$	475.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

At March 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at March 31, 2014 and Dec. 31, 2013 was 0.63% and 0.56%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 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. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 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, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

XML

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Hedging Instruments (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current liabilities	$ 0.1	$ 0.1
Long-term derivative liabilities	0.1	0.2
Total derivatives designated as hedging instruments	0.2	0.3
Current assets	15.6	9.7
Long-term derivative assets	0.2	0.3
Total assets	15.8	10.0
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0.1	0.1
Long-term derivative liabilities	0	0
Total derivatives designated as hedging instruments	0.1	0.1
Current assets	0.1	0.2
Long-term derivative assets	0	0
Total assets	0.1	0.2
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0	0
Long-term derivative liabilities	0.1	0.2
Total derivatives designated as hedging instruments	0.1	0.2
Current assets	15.5	9.5
Long-term derivative assets	0.2	0.3
Total assets	15.7	9.8
Derivatives Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Total derivatives designated as hedging instruments	0.2	0.3
Total assets	15.8	10.0
Derivatives Designated as Hedging Instruments [Member] | Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0.1	0.1
Long-term derivative liabilities	0	0
Current assets	0.1	0.2
Long-term derivative assets	0	0
Derivatives Designated as Hedging Instruments [Member] | Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0	0
Long-term derivative liabilities	0.1	0.2
Current assets	15.5	9.5
Long-term derivative assets	$ 0.2	$ 0.3

XML

Income Taxes

3 Months Ended

Mar. 31, 2014

Income Taxes

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 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for years 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. 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 2010 and forward.

The effective tax rate increased to 36.22% for the three months ended March 31, 2014 from 35.95% for the same period in 2013.

Tampa Electric Company [Member]

Income Taxes

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, 2014 and 2013 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. 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 2010 and forward.

XML

Employee Postretirement Benefits

3 Months Ended

Mar. 31, 2014

Employee Postretirement Benefits

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,	2014			2013			2014		2013
Components of net periodic benefit expense
Service cost	$	4.1		$	4.8		$	0.6	$	0.7
Interest cost on projected benefit obligations		8.2			7.2			2.6		2.3
Expected return on assets		(10.3	)		(9.7	)		0.0		0.0
Amortization of:
Prior service cost		(0.1	)		(0.1	)		0.0		(0.1	)
Actuarial loss		3.2			5.0			0.0		0.3
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	5.1		$	7.2		$	3.2	$	3.2

For the fiscal 2014 plan year, TECO Energy is using an assumed long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $16.0 million to its pension plan in the first quarter of 2014.

For the three months ended March 31, 2014, TECO Energy and its subsidiaries reclassed $0.6 million pretax of unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended March 31, 2014, TEC reclassed $2.5 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

Tampa Electric Company [Member]

Employee Postretirement Benefits

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 in Note 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, 2014 and 2013, respectively, was $3.8 million and $5.3 million for pension benefits, and $2.6 million and $2.6 million for other postretirement benefits.

For the fiscal 2014 plan year, TECO Energy assumed a long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $16.0 million to its pension plan in the first quarter of 2014. TEC’s portion of the contributions was $13.0 million.

Included in the benefit expenses discussed above, for the three months ended March 31, 2014, TEC reclassed $2.5 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

XML

Long-Term Debt

3 Months Ended

Mar. 31, 2014

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2014, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,209.7 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 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.

Tampa Electric Company [Member]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At March 31, 2014, TEC’s total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,058.4 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,042.0 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Mar. 31, 2014 gal
Diesel Fuel Derivatives [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,500,000
Diesel Fuel Derivatives [Member] | 2014 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2014 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,500,000
Diesel Fuel Derivatives [Member] | 2015 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2015 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	47,100,000
Natural Gas Contracts [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	47,100,000
Natural Gas Contracts [Member] | 2014 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2014 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2014 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	26,900,000
Natural Gas Contracts [Member] | 2014 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	26,900,000
Natural Gas Contracts [Member] | 2015 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2015 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2015 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	18,500,000
Natural Gas Contracts [Member] | 2015 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	18,500,000
Natural Gas Contracts [Member] | 2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,700,000
Natural Gas Contracts [Member] | 2016 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2016 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,700,000

XML

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	$ 15.8	$ 10.0
Total Swap Liabilities	0.2	0.3
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.8	10.0
Total Swap Liabilities	0.2	0.3
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	0.1	0.1
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.8	10.0
Total Swap Liabilities	0.2	0.3
Level 2 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Level 2 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	0.1	0.1
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Tampa Electric Company [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Tampa Electric Company [Member] | Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Tampa Electric Company [Member] | Level 2 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	15.7	9.8
Total Swap Liabilities	0.1	0.2
Tampa Electric Company [Member] | Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	$ 0	$ 0

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Activity for Instruments Classified as Qualifying Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	$ 0	$ (0.6)
Amount of Gain/(Loss) Recognized in OCI	(0.1)	0.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.3)	(0.2)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0	(0.6)
Amount of Gain/(Loss) Recognized in OCI	(0.1)	0.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.1)	0
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0	0
Amount of Gain/(Loss) Recognized in OCI	0	0
Amount of Gain/(Loss) Reclassified From AOCI Into Income	$ (0.2)	$ (0.2)

XML

Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2014

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the derivatives that are designated as cash flow hedges at March 31, 2014 and Dec. 31, 2013:

Total Derivatives(1)
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	15.6	$	9.7
Long-term assets		0.2		0.3
Total assets	$	15.8	$	10.0
Current liabilities	$	0.1	$	0.1
Long-term liabilities		0.1		0.2
Total liabilities	$	0.2	$	0.3

(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.

Gross Amounts of Derivatives and Their Related Offset Amounts

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, 2014 and Dec. 31, 2013.  

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, 2014
Description
Derivative assets	$	16.1		$	(0.3	)	$	15.8
Derivative liabilities	$	(0.5	)	$	0.3		$	(0.2	)
Dec. 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)

Effect of Hedging Instruments on OCI and Income

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

	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
(millions)
Derivatives in Cash Flow Hedging Relationships		Effective Portion(1)				Effective Portion(1)
2014
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.1	)	Mining related costs		(0.1	)
Total	($	0.1	)		($	0.3	)
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	)

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

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

	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
(millions)
2014
Interest rate swaps	$	0.0		$	0.0		($	0.2	)
Diesel fuel derivatives		0.0			(0.1	)		(0.1	)
Total	$	0.0		($	0.1	)	($	0.3	)
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	)

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

Derivative Volumes Expected to Settle

The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		1.5		0.0		26.9
2015		0.0		0.0		0.0		18.5
2016		0.0		0.0		0.0		1.7
Total		0.0		1.5		0.0		47.1

Fair Value of Overall Contractual Contingent Liability Positions

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at March 31, 2014:

Contingent Features
(millions) At Mar. 31, 2014	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	0.1	)	($	0.1	)	$	0.0

Derivatives Designated as Hedging Instruments [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at March 31, 2014 and Dec. 31, 2013:

Derivatives Designated as Hedging Instruments
	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet Location		Fair Value		Balance Sheet Location	Fair Value
Mar. 31, 2014
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	0.1	Derivative liabilities	$	0.1
Long-term		Derivative assets		0.0	Derivative liabilities		0.0
Natural gas derivatives:
Current		Derivative assets		15.5	Derivative liabilities		0.0
Long-term		Derivative assets		0.2	Derivative liabilities		0.1
Total derivatives designated as hedging instruments			$	15.8		$	0.2

	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Dec. 31, 2013	Location		Value		Location		Value
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	0.2		Derivative liabilities	$	0.1
Long-term		Derivative assets		0.0		Derivative liabilities		0.0
Natural gas derivatives:
Current		Derivative assets		9.5		Derivative liabilities		0.0
Long-term		Derivative assets		0.3		Derivative liabilities		0.2
Total derivatives designated as hedging instruments			$	10.0			$	0.3

Natural Gas Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the derivative hedges of natural gas contracts at March 31, 2014 and Dec. 31, 2013 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, 2014		Dec. 31, 2013
Current assets	$	15.5	$	9.5
Long-term assets		0.2		0.3
Total assets	$	15.7	$	9.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.1	$	0.2

Diesel Fuel Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the derivative hedges of diesel fuel contracts at March 31, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	0.1	$	0.2
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.2
Current liabilities	$	0.1	$	0.1
Long-term liabilities		0.0		0.0
Total liabilities	$	0.1	$	0.1

Energy Related Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of March 31, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Mar. 31, 2014	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	15.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.1
Total		$	15.7		$	0.1
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Dec. 31, 2013	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Tampa Electric Company [Member]

Gross Amounts of Derivatives and Their Related Offset Amounts

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, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
	Gross Amounts			Gross Amounts offset on the Balance Sheet			Net Amounts of
	of Recognized						Assets (Liabilities)
	Assets						Presented on the
(millions)	(Liabilities)						Balance Sheet
Mar. 31, 2014
Description
Derivative assets	$	16.0		$	(0.3	)	$	15.7
Derivative liabilities	$	(0.4	)	$	0.3		$	(0.1	)
Dec. 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)

Effect of Hedging Instruments on OCI and Income

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)
2014
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Total	$	0.0			($	0.2	)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Total	$	0.0			($	0.2	)

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

Derivative Volumes Expected to Settle

The following table presents by commodity type TEC’s derivative volumes that, as of March 31, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

	Natural Gas Contracts (MMBTUs)
(millions)
Year	Physical		Financial
2014		0.0		26.9
2015		0.0		18.5
2016		0.0		1.7
Total		0.0		47.1

Tampa Electric Company [Member] | Natural Gas Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the derivative hedges of natural gas contracts at March 31, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	15.5	$	9.5
Long-term assets		0.2		0.3
Total assets	$	15.7	$	9.8
Current liabilities (1)	$	0.0	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.1	$	0.2

(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.

Tampa Electric Company [Member] | Energy Related Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of March 31, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Mar. 31, 2014	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	15.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.1
Total		$	15.7		$	0.1
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Dec. 31, 2013	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

XML

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 4.8	$ 4.9
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	12.3	12.6
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	4.4	9.1
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 4.7	$ 4.9

XML

Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2014

Accounting for Derivative Instruments and Hedging Activities

12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

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

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, 2014, 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, 2014 and Dec. 31, 2013:

Total Derivatives(1)
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	15.6	$	9.7
Long-term assets		0.2		0.3
Total assets	$	15.8	$	10.0
Current liabilities	$	0.1	$	0.1
Long-term liabilities		0.1		0.2
Total liabilities	$	0.2	$	0.3

(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 following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at March 31, 2014 and Dec. 31, 2013. 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, 2014
Description
Derivative assets	$	16.1		$	(0.3	)	$	15.8
Derivative liabilities	$	(0.5	)	$	0.3		$	(0.2	)
Dec. 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)

The following table presents the derivative hedges of diesel fuel contracts at March 31, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	0.1	$	0.2
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.2
Current liabilities	$	0.1	$	0.1
Long-term liabilities		0.0		0.0
Total liabilities	$	0.1	$	0.1

The following table presents the derivative hedges of natural gas contracts at March 31, 2014 and Dec. 31, 2013 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, 2014		Dec. 31, 2013
Current assets	$	15.5	$	9.5
Long-term assets		0.2		0.3
Total assets	$	15.7	$	9.8
Current liabilities	$	0.0	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.1	$	0.2

The ending balance in AOCI related to the cash flow hedges and interest rate swaps at March 31, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at March 31, 2014 and Dec. 31, 2013:

Derivatives Designated as Hedging Instruments
	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet Location		Fair Value		Balance Sheet Location	Fair Value
Mar. 31, 2014
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	0.1	Derivative liabilities	$	0.1
Long-term		Derivative assets		0.0	Derivative liabilities		0.0
Natural gas derivatives:
Current		Derivative assets		15.5	Derivative liabilities		0.0
Long-term		Derivative assets		0.2	Derivative liabilities		0.1
Total derivatives designated as hedging instruments			$	15.8		$	0.2

	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Dec. 31, 2013	Location		Value		Location		Value
Commodity Contracts:
Diesel fuel derivatives:
Current		Derivative assets	$	0.2		Derivative liabilities	$	0.1
Long-term		Derivative assets		0.0		Derivative liabilities		0.0
Natural gas derivatives:
Current		Derivative assets		9.5		Derivative liabilities		0.0
Long-term		Derivative assets		0.3		Derivative liabilities		0.2
Total derivatives designated as hedging instruments			$	10.0			$	0.3

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of March 31, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives				Liability Derivatives
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Mar. 31, 2014	Location (1)		Value		Location (1)		Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	15.5		Regulatory assets	$	0.0
Long-term		Regulatory liabilities		0.2		Regulatory assets		0.1
Total			$	15.7			$	0.1
(millions)	Balance Sheet		Fair		Balance Sheet		Fair
Dec. 31, 2013	Location (1)		Value		Location (1)		Value
Commodity Contracts:
Natural gas derivatives:
Current		Regulatory liabilities	$	9.5		Regulatory assets	$	0.0
Long-term		Regulatory liabilities		0.3		Regulatory assets		0.2
Total			$	9.8			$	0.2

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

Based on the fair value of the instruments at March 31, 2014, net pretax gains of $15.5 million are expected to be reclassified from regulatory assets or liabilities 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:

	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
(millions)
Derivatives in Cash Flow Hedging Relationships		Effective Portion(1)				Effective Portion(1)
2014
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.1	)	Mining related costs		(0.1	)
Total	($	0.1	)		($	0.3	)
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	)

(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, 2014 and 2013, 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:

	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
(millions)
2014
Interest rate swaps	$	0.0		$	0.0		($	0.2	)
Diesel fuel derivatives		0.0			(0.1	)		(0.1	)
Total	$	0.0		($	0.1	)	($	0.3	)
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	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of March 31, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		1.5		0.0		26.9
2015		0.0		0.0		0.0		18.5
2016		0.0		0.0		0.0		1.7
Total		0.0		1.5		0.0		47.1

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, 2014, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were 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 risk in determining the fair value of counterparty positions. 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 in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2014, substantially all positions with counterparties were net assets.

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, 2014:

Contingent Features
	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
(millions)
At Mar. 31, 2014
Credit Rating	($	0.1	)	($	0.1	)	$	0.0

Tampa Electric Company [Member]

Accounting for Derivative Instruments and Hedging Activities

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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 (see Note 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, 2014, 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, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Current assets	$	15.5	$	9.5
Long-term assets		0.2		0.3
Total assets	$	15.7	$	9.8
Current liabilities (1)	$	0.0	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.1	$	0.2

(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 ending balance in AOCI related to previously settled interest rate swaps at March 31, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

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, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
	Gross Amounts			Gross Amounts offset on the Balance Sheet			Net Amounts of
	of Recognized						Assets (Liabilities)
	Assets						Presented on the
(millions)	(Liabilities)						Balance Sheet
Mar. 31, 2014
Description
Derivative assets	$	16.0		$	(0.3	)	$	15.7
Derivative liabilities	$	(0.4	)	$	0.3		$	(0.1	)
Dec. 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of March 31, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Mar. 31, 2014	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	15.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.2	Regulatory assets		0.1
Total		$	15.7		$	0.1
(millions)	Balance Sheet	Fair		Balance Sheet	Fair
Dec. 31, 2013	Location (1)	Value		Location (1)	Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Based on the fair value of the instruments at March 31, 2014, net pretax losses of $15.5 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)
2014
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Total	$	0.0			($	0.2	)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.2	)
Total	$	0.0			($	0.2	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended March 31, 2014 and 2013, all hedges were effective.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of March 31, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

	Natural Gas Contracts (MMBTUs)
(millions)
Year	Physical		Financial
2014		0.0		26.9
2015		0.0		18.5
2016		0.0		1.7
Total		0.0		47.1

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, 2014, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were 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. TEC 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 risk in determining the fair value of counterparty positions. 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 in evaluating the potential impact of nonperformance risk to derivative positions. As of March 31, 2014, substantially all positions with counterparties were net assets.

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. Substantially all of TEC’s open positions with counterparties as of March 31, 2014 were asset positions.

XML

Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

Principles of Consolidation and Basis of Presentation

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 (see Note 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, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

As of March 31, 2014 and Dec. 31, 2013, unbilled revenues of $48.1 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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 $27.2 million and $25.4 million for the three months ended March 31, 2014 and 2013, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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

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.

Tampa Electric Company [Member]

Principles of Consolidation and Basis of Presentation

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 (see Note 13).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of March 31, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

As of March 31, 2014 and Dec. 31, 2013, unbilled revenues of $48.1 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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 $27.2 million and $25.4 million for the three months ended March 31, 2014 and 2013, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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

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.

XML

Other Comprehensive Income - Other Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross	$ (0.1)	$ 0.3
Reclassification from AOCI to net income, Gross	0.4	0.3
Gain on cash flow hedges, Gross	0.3	0.6
Amortization of unrecognized benefit costs, Gross	0.8	1.1
Increase in unrecognized post employment costs, Gross	(12.9)
Total other comprehensive income (loss), Gross	(11.8)	1.7
Unrealized gain on cash flow hedges, Tax	0	(0.1)
Reclassification from AOCI to net income, Tax	(0.1)	(0.1)
Gain on cash flow hedges, Tax	(0.1)	(0.2)
Amortization of unrecognized benefit costs, Tax	(0.3)	(0.4)
Increase in unrecognized post employment costs, Tax	4.7
Total other comprehensive income (loss), Tax	4.3	(0.6)
Unrealized gain (loss) on cash flow hedges, Net	(0.1)	0.2
Reclassification from AOCI to net income, Net	0.3	0.2
Gain on cash flow hedges, Net	0.2	0.4
Amortization of unrecognized benefit costs, Net	0.5	0.7
Increase in unrecognized post employment costs, Net	(8.2)	0
Other comprehensive income, net of tax	(7.5)	1.1
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain on cash flow hedges, Gross	0	0
Reclassification from AOCI to net income, Gross	0.4	0.4
Gain on cash flow hedges, Gross	0.4	0.4
Total other comprehensive income (loss), Gross	0.4	0.4
Unrealized gain on cash flow hedges, Tax	0	0
Reclassification from AOCI to net income, Tax	(0.2)	(0.2)
Gain on cash flow hedges, Tax	(0.2)	(0.2)
Total other comprehensive income (loss), Tax	(0.2)	(0.2)
Unrealized gain (loss) on cash flow hedges, Net	0	0
Reclassification from AOCI to net income, Net	0.2	0.2
Gain on cash flow hedges, Net	0.2	0.2
Other comprehensive income, net of tax	$ 0.2	$ 0.2

XML

Regulatory - Regulatory Assets and Related Recovery Periods (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory assets	$ 321.5	$ 327.4
Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	321.5	327.4
Clause Recoverable [Member]
Regulatory Assets [Line Items]
Regulatory assets	6.7	10.2
Clause Recoverable [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	6.7	10.2
Regulatory Tax Asset [Member]
Regulatory Assets [Line Items]
Regulatory assets	67.9	67.4
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	67.9	67.4
Capital Structure and Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	63.7	64.2
Capital Structure and Other [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	63.7	64.2
Components of Rate Base [Member]
Regulatory Assets [Line Items]
Regulatory assets	183.2	185.6
Components of Rate Base [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 183.2	$ 185.6

XML

Consolidated Condensed Statements of Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Statement [Abstract]
Franchise fees and gross receipts taxes	$ 27.2	$ 25.4

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2013 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 (see Note 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, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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, 2014 and Dec. 31, 2013, unbilled revenues of $48.1 million and $46.7 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 $27.2 million and $25.4 million for the three months ended March 31, 2014 and 2013, 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.

Tampa Electric Company [Member]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TEC’s 2013 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 (see Note 13).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of March 31, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended March 31, 2014 and 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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, 2014 and Dec. 31, 2013, unbilled revenues of $48.1 million and $46.7 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 $27.2 million and $25.4 million for the three months ended March 31, 2014 and 2013, 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.

XML

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Collateral posted with or received from any counterparties	$ 0	$ 0
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.6	7.8
Net pretax losses expected to be reclassified from regulatory assets or liabilities	15.5
Tampa Electric Company [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.6	7.8
Net pretax losses expected to be reclassified from regulatory assets or liabilities	15.5
Interest Rate Swap [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	$ 7.6	$ 7.8
Diesel Fuel [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Dec. 31, 2014
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Dec. 31, 2016

XML

Discontinued Operations - Components of Discontinued Operations (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 TECO Guatemala [Member]	Dec. 31, 2013 TECO Guatemala [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues			$ 0	$ 0
Income from operations			5.0	0.4
Income from discontinued operations	5.0	0.4	5.0	0.4
Provision for income taxes	1.9	0.1	1.9	0.1
Income from discontinued operations, net	$ 3.1	$ 0.3	$ 3.1	$ 0.3

XML

Regulatory (Tables)

3 Months Ended

Mar. 31, 2014

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of March 31, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2014		Dec. 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	67.9	$	67.4
Other:
Cost-recovery clauses		3.3		6.1
Postretirement benefit asset		180.2		182.7
Deferred bond refinancing costs (2)		7.8		8.0
Environmental remediation		51.4		51.4
Competitive rate adjustment		3.4		4.1
Other		7.5		7.7
Total other regulatory assets		253.6		260.0
Total regulatory assets		321.5		327.4
Less: Current portion		32.7		34.3
Long-term regulatory assets	$	288.8	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.8	$	9.8
Other:
Cost-recovery clauses		58.9		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.7		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve—cost of removal		591.8		594.0
Total other regulatory liabilities		709.3		707.4
Total regulatory liabilities		715.1		717.2
Less: Current portion		90.1		85.8
Long-term regulatory liabilities	$	625.0	$	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.

Regulatory Assets and Related Recovery Period

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

Regulatory Assets
	Mar. 31,		Dec. 31,
(millions)	2014		2013
Clause recoverable (1)	$	6.7	$	10.2
Components of rate base (2)		183.2		185.6
Regulatory tax assets (3)		67.9		67.4
Capital structure and other (3)		63.7		64.2
Total	$	321.5	$	327.4

(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.

Tampa Electric Company [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of March 31, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2014		Dec. 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	67.9	$	67.4
Other:
Cost-recovery clauses		3.3		6.1
Postretirement benefit asset		180.2		182.7
Deferred bond refinancing costs (2)		7.8		8.0
Environmental remediation		51.4		51.4
Competitive rate adjustment		3.4		4.1
Other		7.5		7.7
Total other regulatory assets		253.6		260.0
Total regulatory assets		321.5		327.4
Less: Current portion		32.7		34.3
Long-term regulatory assets	$	288.8	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.8	$	9.8
Other:
Cost-recovery clauses		58.9		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.7		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve—cost of removal		591.8		594.0
Total other regulatory liabilities		709.3		707.4
Total regulatory liabilities		715.1		717.2
Less: Current portion		90.1		85.8
Long-term regulatory liabilities	$	625.0	$	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.

Regulatory Assets and Related Recovery Period

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, 2014		Dec. 31, 2013
Clause recoverable (1)	$	6.7	$	10.2
Components of rate base (2)		183.2		185.6
Regulatory tax assets (3)		67.9		67.4
Capital structure and other (3)		63.7		64.2
Total	$	321.5	$	327.4

(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.

XML

Regulatory - Additional Information (Detail) (Tampa Electric Company [Member], USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Annual accrual storm damage reserve	$ 8.0
Storm damage reserve	$ 56.1	$ 56.1
Transmission and Delivery Storm Reserve [Member]
Storm damage cost recovery period	12 months	12 months

XML

Segment Information

3 Months Ended

Mar. 31, 2014

Segment Information

11. Segment Information

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

Segment Information (1)
(millions)	Tampa		Peoples		TECO			Other &			TECO
Three months ended Mar. 31,	Electric		Gas		Coal			Eliminations			Energy
2014
Revenues - external	$	452.9	$	122.4	$	106.1		$	2.7		$	684.1
Sales to affiliates		0.3		0.2		0.0			(0.5	)		0.0
Total revenues		453.2		122.6		106.1			2.2			684.1
Depreciation and amortization		62.1		13.3		9.0			0.5			84.9
Total interest charges(1)		22.0		3.4		1.5			14.2			41.1
Internally allocated interest (1)		0.0		0.0		1.5			(1.5	)		0.0
Provision (benefit) for income taxes		26.6		9.2		(2.2	)		(6.9	)		26.7
Net income (loss) from continuing operations		45.2		14.6		(1.6	)		(11.2	)		47.0
Income from discontinued operations, net		0.0		0.0		0.0			3.1			3.1
Net income (loss)	$	45.2	$	14.6	($	1.6	)	($	8.1	)	$	50.1
2013
Revenues - external	$	417.8	$	121.9	$	117.9		$	3.5		$	661.1
Sales to affiliates		0.2		0.0		0.0			(0.2	)		0.0
Total revenues		418.0		121.9		117.9			3.3			661.1
Depreciation and amortization		59.0		13.0		9.7			0.3			82.0
Total interest charges(1)		23.4		3.4		1.7			13.9			42.4
Internally allocated interest (1)		0.0		0.0		1.6			(1.6	)		0.0
Provision (benefit) for income taxes		19.8		8.7		(0.1	)		(5.2	)		23.2
Net income (loss) from continuing operations		31.8		13.8		3.0			(7.4	)		41.2
Income from discontinued operations, net		0.0		0.0		0.0			0.3			0.3
Net income (loss)	$	31.8	$	13.8	$	3.0		($	7.1	)	$	41.5
At Mar. 31, 2014
Total assets	$	6,120.8	$	1,031.1	$	319.5		($	40.7	)	$	7,430.7
At Dec. 31, 2013
Total assets	$	6,126.9	$	1,021.2	$	316.3		($	16.4	)	$	7,448.0

(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 2013 through March 2014 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.

Tampa Electric Company [Member]

Segment Information

9. Segment Information

(millions)	Tampa		Peoples		Other &			Tampa Electric
Three months ended Mar. 31,	Electric		Gas		Eliminations			Company
2014
Revenues - external	$	453.1	$	122.4	$	0.0		$	575.5
Sales to affiliates		0.1		0.2		(0.3	)		0.0
Total revenues		453.2		122.6		(0.3	)		575.5
Depreciation and amortization		62.1		13.3		0.0			75.4
Total interest charges		22.0		3.4		0.0			25.4
Provision for income taxes		26.6		9.2		0.0			35.8
Net income	$	45.2	$	14.6	$	0.0		$	59.8
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
Total assets at Mar. 31, 2014	$	5,871.0	$	999.4	($	5.1	)	$	6,865.3
Total assets at Dec. 31, 2013	$	5,895.4	$	989.3	($	8.9	)	$	6,875.8