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 Sept. 30, 2013

OR

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

For the transition period from                      to                     

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

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

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

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

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

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

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

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

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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of October 25, 2013 was 217,301,601. As of October 25, 2013, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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

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

Page 2 of 62

Index to Exhibits appears on page 62.

DEFINITIONS

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

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

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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.
NOL	net operating loss
Note	Note      to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
o&m expenses	operations and maintenance expenses
OATT	open access transmission tariff
OCI	other comprehensive income
OTC	over-the-counter
OTTI	other than temporary impairment
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PCIDA	Polk County Industrial Development Authority
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
REIT	real estate investment trust
REMIC	real estate mortgage investment conduit
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
RPS	renewable portfolio standards
RTO	regional transmission organization
SEC	U.S. Securities and Exchange Commission
SO2	sulfur dioxide
SERP	Supplemental Executive Retirement Plan
SPA	stock purchase agreement
STIF	short-term investment fund
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, a coal producing subsidiary of TECO Diversified
TECO Finance	TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.
TRC	TEC Receivables Company
VIE	variable interest entity
WRERA	The Worker, Retiree and Employer Recovery Act of 2008

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PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

TECO ENERGY, INC.

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and subsidiaries as of Sept. 30, 2013 and Dec. 31, 2012, and the results of their operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three month and nine month periods ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 and to the notes on pages 11 through 31 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sept. 30, 2013 and Dec. 31, 2012		5-6
Consolidated Condensed Statements of Income for the three month and nine month periods ended Sept.  30, 2013 and 2012		7-8
Consolidated Condensed Statements of Comprehensive Income for the three month and nine month periods ended Sept. 30, 2013 and 2012		9
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sept. 30, 2013 and 2012		10
Notes to Consolidated Condensed Financial Statements		11-31

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

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TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Sept. 30, 2013			Dec. 31, 2012
Current assets
Cash and cash equivalents	$	152.8		$	200.5
Receivables, less allowance for uncollectibles of $4.1 and $4.2 at Sept. 30, 2013 and Dec. 31, 2012, respectively		347.1			282.7
Inventories, at average cost
Fuel		119.6			123.6
Materials and supplies		83.0			82.1
Derivative assets		0.2			0.0
Regulatory assets		40.9			70.3
Deferred income taxes		28.5			63.3
Prepayments and other current assets		38.1			33.9
Income tax receivables		0.8			0.4
Total current assets		811.0			856.8
Property, plant and equipment
Utility plant in service
Electric		6,862.5			6,655.8
Gas		1,284.3			1,228.3
Construction work in progress		356.6			336.1
Other property		447.3			443.8
Property, plant and equipment, at original costs		8,950.7			8,664.0
Accumulated depreciation		(2,869.8	)		(2,695.5	)
Total property, plant and equipment, net		6,080.9			5,968.5
Other assets
Regulatory assets		370.5			382.6
Derivative assets		0.0			0.2
Deferred charges and other assets		131.7			126.8
Total other assets		502.2			509.6
Total assets	$	7,394.1		$	7,334.9

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

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)	Sept. 30, 2013			Dec. 31, 2012
Current liabilities
Long-term debt due within one year	$	83.3		$	0.0
Accounts payable		241.3			232.8
Customer deposits		164.5			162.9
Regulatory liabilities		81.3			105.6
Derivative liabilities		5.2			14.6
Interest accrued		55.4			33.2
Taxes accrued		79.3			32.1
Other		17.4			19.9
Total current liabilities		727.7			601.1
Other liabilities
Deferred income taxes		338.0			277.9
Investment tax credits		9.4			9.7
Regulatory liabilities		632.7			631.4
Derivative liabilities		1.5			0.6
Deferred credits and other liabilities		523.1			549.7
Long-term debt, less amount due within one year		2,837.8			2,972.7
Total other liabilities		4,342.5			4,442.0
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 217.3 million and 216.6 million shares outstanding at Sept. 30, 2013 and Dec. 31, 2012, respectively)		217.3			216.6
Additional paid in capital		1,578.8			1,564.5
Retained earnings		554.1			541.7
Accumulated other comprehensive loss		(26.3	)		(31.0	)
Total capital		2,323.9			2,291.8
Total liabilities and capital	$	7,394.1		$	7,334.9

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Sept. 30,
(millions, except per share amounts)		2013			2012
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $29.7 in 2013 and $31.0 in 2012)		$	639.6		$	670.1
Unregulated			126.3			188.5
Total revenues			765.9			858.6
Expenses
Regulated operations and maintenance
Fuel			202.8			209.1
Purchased power			15.7			25.8
Cost of natural gas sold			26.7			40.5
Other			127.0			115.4
Operation and maintenance other expense
Mining related costs			108.3			141.5
Other			3.6			1.5
Depreciation and amortization			85.4			83.4
Taxes, other than income			55.9			58.3
Total expenses			625.4			675.5
Income from continuing operations			140.5			183.1
Other income
Allowance for other funds used during construction			1.8			0.7
Other income			(0.3	)		2.7
Total other income			1.5			3.4
Interest charges
Interest expense			42.6			45.0
Allowance for borrowed funds used during construction			(1.1	)		(0.4	)
Total interest charges			41.5			44.6
Income from continuing operations before provision for income taxes			100.5			141.9
Provision for income taxes			37.6			51.7
Net income from continuing operations			62.9			90.2
Discontinued operations
Loss from discontinued operations			(0.2	)		(27.4	)
(Benefit) Provision for income taxes			(0.1	)		18.7
Loss from discontinued operations, net			(0.1	)		(46.1	)
Less: Income from discontinued operations attributable to noncontrolling interest			0.0			0.1
Loss from discontinued operations attributable to TECO Energy, net			(0.1	)		(46.2	)
Net income attributable to TECO Energy		$	62.8		$	44.0
Average common shares outstanding	– Basic		215.2			214.5
	– Diluted		215.6			215.4
Earnings per share from continuing operations	– Basic	$	0.29		$	0.42
	– Diluted	$	0.29		$	0.42
Earnings per share from discontinued operations	– Basic	$	0.00		$	(0.22	)
	– Diluted	$	0.00		$	(0.22	)
Earnings per share attributable to TECO Energy	– Basic	$	0.29		$	0.20
	– Diluted	$	0.29		$	0.20
Dividends paid per common share outstanding		$	0.22		$	0.22

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

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TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Nine months ended Sept. 30,
(millions, except per share amounts)		2013			2012
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $81.8 in 2013 and $85.4 in 2012)		$	1,782.7		$	1,826.8
Unregulated			380.2			481.4
Total revenues			2,162.9			2,308.2
Expenses
Regulated operations and maintenance
Fuel			517.3			534.5
Purchased power			50.8			85.2
Cost of natural gas sold			116.9			118.5
Other			377.4			342.2
Operation and maintenance other expense
Mining related costs			314.0			358.7
Other			8.3			4.4
Depreciation and amortization			251.3			246.9
Taxes, other than income			162.8			170.8
Total expenses			1,798.8			1,861.2
Income from continuing operations			364.1			447.0
Other income
Allowance for other funds used during construction			4.3			1.6
Other income			2.9			5.8
Total other income			7.2			7.4
Interest charges
Interest expense			129.1			141.7
Allowance for borrowed funds used during construction			(2.5	)		(0.9	)
Total interest charges			126.6			140.8
Income from continuing operations before provision for income taxes			244.7			313.6
Provision for income taxes			89.0			113.2
Net income from continuing operations			155.7			200.4
Discontinued operations
Loss from discontinued operations			0.0			(7.9	)
Provision for income taxes			0.0			24.6
Loss from discontinued operations, net			0.0			(32.5	)
Less: Income from discontinued operations attributable to noncontrolling interest			0.0			0.3
Loss from discontinued operations attributable to TECO Energy, net			0.0			(32.8	)
Net income attributable to TECO Energy		$	155.7		$	167.6
Average common shares outstanding	– Basic		214.9			214.2
	– Diluted		215.4			215.3
Earnings per share from continuing operations	– Basic	$	0.72		$	0.93
	– Diluted	$	0.72		$	0.93
Earnings per share from discontinued operations	– Basic	$	0.00		$	(0.15	)
	– Diluted	$	0.00		$	(0.15	)
Earnings per share attributable to TECO Energy	– Basic	$	0.72		$	0.78
	– Diluted	$	0.72		$	0.78
Dividends paid per common share outstanding		$	0.66		$	0.66

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Sept. 30,				Nine months ended Sept. 30,
(millions)	2013		2012		2013		2012
Net income attributable to TECO Energy	$	62.8	$	44.0	$	155.7	$	167.6
Other comprehensive income, net of tax
Net unrealized gains (loss) on cash flow hedges		0.8		1.7		1.1		(4.2	)
Amortization of unrecognized benefit costs		0.6		0.5		2.0		1.1
Recognized benefit costs due to settlement		1.6		0.0		1.6		0.0
Other comprehensive income (loss), net of tax		3.0		2.2		4.7		(3.1	)
Comprehensive income attributable to TECO Energy	$	65.8	$	46.2	$	160.4	$	164.5

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

9

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sept. 30,
(millions)	2013			2012
Cash flows from operating activities
Net income attributable to TECO Energy	$	155.7		$	167.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		251.3			253.2
Deferred income taxes		89.1			115.2
Investment tax credits		(0.3	)		(0.3	)
Allowance for other funds used during construction		(4.3	)		(1.6	)
Non-cash stock compensation		10.2			8.5
(Loss) gain on sales of business/assets, pretax		(0.3	)		14.5
Deferred recovery clauses		(3.8	)		(3.7	)
Asset impairment, pre-tax		0.0			17.4
Receivables, less allowance for uncollectibles		(64.4	)		(47.3	)
Inventories		3.1			7.9
Prepayments and other current assets		(4.2	)		(3.1	)
Taxes accrued		44.0			58.7
Interest accrued		22.2			23.6
Accounts payable		10.6			22.0
Other		(2.8	)		(25.0	)
Cash flows from operating activities		506.1			607.6
Cash flows from investing activities
Capital expenditures		(370.9	)		(355.2	)
Allowance for other funds used during construction		4.3			1.6
Net proceeds from sales of business/assets		0.4			7.4
Cash flows used in investing activities		(366.2	)		(346.2	)
Cash flows from financing activities
Dividends		(143.4	)		(142.8	)
Proceeds from the sale of common stock		7.4			3.2
Proceeds from long-term debt issuance		0.0			538.3
Repayment of long-term debt/Purchase in lieu of redemption		(51.6	)		(469.2	)
Dividends to noncontrolling interest		0.0			(0.3	)
Cash flows used in financing activities		(187.6	)		(70.8	)
Net (decrease) increase in cash and cash equivalents		(47.7	)		190.6
Cash and cash equivalents at beginning of the period		200.5			44.0
Cash and cash equivalents at end of the period	$	152.8		$	234.6

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

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See the company’s 2012 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries and the accounts of VIEs for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. For the periods presented, no VIEs have been consolidated in continuing operations (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 Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three and nine months ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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

Revenues

As of Sept. 30, 2013 and Dec. 31, 2012, unbilled revenues of $51.8 million and $49.0 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013, compared to $31.0 million and $85.4 million, respectively, for the three and nine months ended Sept. 30, 2012.

Cash Flows Related to Derivatives and Hedging Activities

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

Reclassifications

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

2. New Accounting Pronouncements

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

11

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 is effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. The guidance will have no effect on the company’s results of operations, financial position or cash flows.

Comprehensive Income

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

3. Regulatory

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

Base Rates-Tampa Electric

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

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

On Sept. 6, 2013, TEC and all of the intervenors in its Tampa Electric division base rate proceeding filed with the FPSC a joint motion for the FPSC to approve a stipulation and settlement agreement, which would resolve all matters in Tampa Electric’s pending base rate proceeding.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved Tampa Electric’s base rate proceeding.

Storm Damage Cost Recovery

Tampa Electric is 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. Tampa Electric’s storm reserve was $55.4 million and $50.4 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively. Effective Nov. 1, 2013, Tampa Electric will cease accruing for this storm damage reserve as a settlement provision of the base rate proceeding mentioned above. 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 the level as of Oct. 31, 2013.

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Regulatory Assets and Liabilities

Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the 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 Sept. 30, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.2	$	67.2
Other:
Cost-recovery clauses		14.4		42.9
Postretirement benefit asset		263.8		276.1
Deferred bond refinancing costs (2)		8.3		9.2
Environmental remediation		47.8		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5
Total other regulatory assets		344.2		385.7
Total regulatory assets		411.4		452.9
Less: Current portion		40.9		70.3
Long-term regulatory assets	$	370.5	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	13.7	$	14.6
Other:
Cost-recovery clauses		49.4		73.9
Transmission and delivery storm reserve		55.4		50.4
Deferred gain on property sales (3)		2.3		3.4
Other		1.3		1.0
Accumulated reserve - cost of removal		591.9		593.7
Total other regulatory liabilities		700.3		722.4
Total regulatory liabilities		714.0		737.0
Less: Current portion		81.3		105.6
Long-term regulatory liabilities	$	632.7	$	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.

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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)	Sept. 30, 2013		Dec. 31, 2012
Clause recoverable (1)	$	18.6	$	47.0
Components of rate base (2)		266.7		279.1
Regulatory tax assets (3)		67.2		67.2
Capital structure and other (3)		58.9		59.6
Total	$	411.4	$	452.9

(1) To be recovered through recovery mechanisms 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.

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4. Income Taxes

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2011 consolidated federal income tax return during 2012. The statute of limitations remains open for years 2010 and forward. Years 2012 and 2013 are currently being examined by the IRS under their Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2013. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2009 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation & maintenance other expense-Other” on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. For the nine months ended Sept. 30, 2013 and Sept. 30, 2012, the company recorded $0.1 million and $0.1 million of interest charges respectively. No amounts were recorded in continuing operations for penalties for the nine months ended Sept. 30, 2013 or Sept. 30, 2012.

The company expects to recognize the remaining unrecognized tax benefits by the end of 2013 as a result of a lapse of the statute of limitations, which would affect the annual effective tax rate.

During the three months ended Sept. 30, 2012, the company incurred an after-tax charge of $22.6 million for foreign tax credits associated with its Guatemalan operations being reclassified as an asset held for sale. See Note 15 for more information.

The effective tax rate for continuing operations increased to 36.37% for the nine months ended Sept. 30, 2013 from 36.09% for the same period in 2012. The increase is principally due to decreased depletion.

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 Sept. 30,	2013			2012			2013			2012
Components of net periodic benefit expense
Service cost	$	4.5		$	4.3		$	0.7		$	0.6
Interest cost on projected benefit obligations		7.3			7.5			2.3			2.5
Expected return on assets		(9.6	)		(9.3	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			0.4
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		0.2
Actuarial loss		5.1			3.9			0.2			0.1
Settlement cost		1.0			0.0			0.0			0.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	8.2		$	6.3		$	3.1		$	3.8
Nine months ended Sept. 30,
Components of net periodic benefit expense
Service cost	$	13.6		$	12.8		$	1.9		$	1.8
Interest cost on projected benefit obligations		21.7			22.5			7.0			7.6
Expected return on assets		(28.8	)		(27.8	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			1.3
Prior service (benefit) cost		(0.3	)		(0.3	)		(0.3	)		0.6
Actuarial loss		15.4			11.5			0.7			0.1
Settlement cost		1.0			0.0			0.0			0.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	22.6		$	18.7		$	9.3		$	11.4

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For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. The SERP was remeasured as of Jun. 30, 2013 using a discount rate of 4.96% due to a settlement. Additionally, TECO Energy made contributions of $32.9 million to its pension plan for the nine months ended Sept. 30, 2013.

For the three and nine months ended Sept. 30, 2013, TECO Energy and its subsidiaries reclassed $1.0 million and $3.2 million pretax, respectively, of unamortized transition obligation, prior service cost and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and nine months ended Sept. 30, 2013, TEC reclassed $4.1 million and $12.3 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

6. Short-Term Debt

At Sept. 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Sept. 30, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	1.5	$	675.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

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

At Sept. 30, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at Sept. 30, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

Amendment of TECO Energy/TECO Finance Credit Facility

On June 24, 2013, TECO Energy and TECO Finance entered into an Amendment No. 1 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011 (TECO Credit Facility). Pursuant to the TECO Credit Facility, TECO Finance may borrow up to $200 million from time to time on a revolving basis. The TECO Credit Facility matures on Oct. 25, 2016.

The Amendment was entered into to accommodate the acquisition of NMGI, as described in Note 16 herein, by (i) temporarily changing the total debt-to-total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closes, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changing the definition of Permitted Liens as defined in the TECO Credit Facility to permit the acquisition of a significant subsidiary that carries secured debt and making other changes matching the corresponding covenant in the Bridge Facility, as described in Note 16 herein. More specifically, the Amendment adds to the definition of Permitted Liens, (i) liens existing on any property or asset prior to the acquisition thereof by any significant subsidiary or existing on any property or assets of any person that becomes a significant subsidiary after the date of the Amendment prior to the time such person becomes a significant subsidiary, (ii) liens on assets

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subject to existing liens to secure additional obligations and (iii) mortgage bonds issued by certain regulated significant subsidiaries including NMGC in a principal amount not exceeding 66 2/3% of the value of such significant subsidiary’s plant, property and equipment. The Amendment also contains other minor changes to the TECO Credit Facility.

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,178.1 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,439.4 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are level 2 instruments.

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007B

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

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

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

On March 26, 2008, TEC purchased in lieu of redemption $20 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C.

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Sept. 30, 2013 to provide an opportunity to evaluate refinancing alternatives.

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8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and nine months ended Sept. 30, 2013 and 2012, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2013
Unrealized gain on cash flow hedges	$	1.1	$	(0.4	)	$	0.7	$	0.7		$	(0.3	)	$	0.4
Reclassification from AOCI to net income (1)		0.1		0.0			0.1		1.0			(0.3	)		0.7
Gain on cash flow hedges		1.2		(0.4	)		0.8		1.7			(0.6	)		1.1
Amortization of unrecognized benefit costs (2)		1.0		(0.4	)		0.6		3.2			(1.2	)		2.0
Recognized benefit costs due to settlement		2.6		(1.0	)		1.6		2.6			(1.0	)		1.6
Total other comprehensive income	$	4.8	$	(1.8	)	$	3.0	$	7.5		$	(2.8	)	$	4.7
2012
Unrealized gain (loss) on cash flow hedges	$	2.5	$	(0.9	)	$	1.6	$	(7.2	)	$	2.7		$	(4.5	)
Reclassification from AOCI to net income (1)		0.2		(0.1	)		0.1		0.5			(0.2	)		0.3
Gain (Loss) on cash flow hedges		2.7		(1.0	)		1.7		(6.7	)		2.5			(4.2	)
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5		2.3			(1.2	)		1.1
Total other comprehensive income (loss)	$	3.5	$	(1.3	)	$	2.2	$	(4.4	)	$	1.3		$	(3.1	)

(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.

Accumulated Other Comprehensive (Loss) Income
(millions)	Sept. 30, 2013			Dec. 31, 2012
Unrecognized pension loss and prior service (benefit) credit (1)	$	(29.3	)	$	(32.9	)
Unrecognized other benefit loss, prior service (benefit) cost and transition obligation (2)		11.1			11.1
Net unrealized losses from cash flow hedges (3)		(8.1	)		(9.2	)
Total accumulated other comprehensive loss	$	(26.3	)	$	(31.0	)

(1) Net of tax benefit of $17.9 million and $20.1 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(2) Net of tax expense of $6.7 million and $6.7 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax benefit of $5.2 million and $5.8 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

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9. Earnings Per Share

	For the three months ended Sept. 30,						For the nine months ended Sept. 30,
(millions, except per share amounts)	2013			2012			2013			2012
Basic earnings per share
Net income from continuing operations	$	62.9		$	90.2		$	155.7		$	200.4
Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)		(0.5	)		(0.7	)
Income before discontinued operations available to common shareholders - Basic	$	62.7		$	89.9		$	155.2		$	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0		($	32.8	)
Amount allocated to nonvested participating shareholders		0.0			0.1			0.0			0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Basic	($	0.1	)	($	46.1	)	$	0.0		($	32.7	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7		$	167.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.5	)		(0.6	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	62.6		$	43.8		$	155.2		$	167.0
Average common shares outstanding - Basic		215.2			214.5			214.9			214.2
Earnings per share from continuing operations available to common shareholders - Basic	$	0.29		$	0.42		$	0.72		$	0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		($	0.22	)	$	0.00		($	0.15	)
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.29		$	0.20		$	0.72		$	0.78
Diluted earnings per share
Net income from continuing operations	$	62.9		$	90.2		$	155.7		$	200.4
Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)		(0.5	)		(0.7	)
Income before discontinued operations available to common shareholders - Diluted	$	62.7		$	89.9		$	155.2		$	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0		($	32.8	)
Amount allocated to nonvested participating shareholders		0.0			0.1			0.0			0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	($	0.1	)	($	46.1	)	$	0.0		($	32.7	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7		$	167.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.5	)		(0.6	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	62.6		$	43.8		$	155.2		$	167.0
Unadjusted average common shares outstanding - Diluted		215.2			214.5			214.9			214.2
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.4			0.9			0.5			1.1
Average common shares outstanding - Diluted		215.6			215.4			215.4			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.29		$	0.42		$	0.72		$	0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		($	0.22	)	$	0.00		($	0.15	)
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.29		$	0.20		$	0.72		$	0.78
Anti-dilutive shares		0.0			0.0			0.0			0.6

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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. Two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim. The Court recently denied plaintiffs’ motion for reconsideration of the ruling. PGS’s suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident remains pending, as does the Posen Construction counter-claim against PGS alleging negligence. In addition, the suit filed by the Posen Construction employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees are 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 recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected sometime in 2014.

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2013, TEC has estimated its ultimate financial liability to be $37.2 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.

Environmental Protection Agency Section 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station in Polk County, Florida with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter. TEC responded with the requested information on April 26, 2013 and has not received any response from the EPA on this matter.

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Environmental Protection Agency Administrative Order

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal, received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. A consent agreement and final order with the EPA with respect to this matter became effective on July 23, 2013, the costs associated with which were not material to the financial results or financial position of TECO Energy.

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 Sept. 30, 2013 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2013		2014-2017		After (1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
TECO Coal
Fuel purchase related (2)	$	0.0	$	1.4	$	4.0	$	5.4	$	2.3
Other subsidiaries
Guaranty under sale agreement (3)		0.0		4.9		0.0		4.9		4.9
Fuel purchase/energy management (2)		0.0		10.0		94.3		104.3		0.4
Total	$	0.0	$	16.3	$	98.3	$	114.6	$	7.6

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After (1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
Tampa Electric (2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sept. 30, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement of the TECO Guatemala equity interests.

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 Sept. 30, 2013, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

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

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Segment Information (1)
(millions) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		TECO Coal			TECO Guatemala (2)			Other & Eliminations			TECO Energy
2013
Revenues - external	$	556.2	$	83.1	$	123.7		$	0.0		$	2.9		$	765.9
Sales to affiliates		0.2		0.3		0.0			0.0			(0.5	)		0.0
Total revenues		556.4		83.4		123.7			0.0			2.4			765.9
Depreciation and amortization		62.2		13.4		9.3			0.0			0.5			85.4
Total interest charges (1)		22.8		3.4		1.6			0.0			13.7			41.5
Internally allocated interest (1)		0.0		0.0		1.5			0.0			(1.5	)		0.0
Provision (benefit) for income taxes		42.7		3.4		(1.2	)		0.0			(7.3	)		37.6
Net income from continuing operations		68.7		5.4		(1.4	)		0.0			(9.8	)		62.9
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0			(0.1	)		(0.1	)
Net income attributable to TECO Energy	$	68.7	$	5.4	($	1.4	)	$	0.0		($	9.9	)	$	62.8
2012
Revenues - external	$	574.9	$	95.2	$	186.0		$	0.0		$	2.5		$	858.6
Sales to affiliates		0.3		0.0		0.0			0.0			(0.3	)		0.0
Total revenues		575.2		95.2		186.0			0.0			2.2			858.6
Depreciation and amortization		60.2		12.7		10.2			0.0			0.3			83.4
Total interest charges (1)		26.7		3.7		1.9			0.0			12.3			44.6
Internally allocated interest (1)		0.0		0.0		1.7			0.0			(1.7	)		0.0
Provision (benefit) for income taxes		45.7		4.4		6.0			0.0			(4.4	)		51.7
Net income from continuing operations		73.5		7.0		17.4			0.0			(7.7	)		90.2
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			(42.6	)		(3.6	)		(46.2	)
Net income attributable to TECO Energy	$	73.5	$	7.0	$	17.4		($	42.6	)	($	11.3	)	$	44.0
(millions) Nine months ended Sept. 30,
2013
Revenues - external	$	1,476.6	$	306.3	$	370.0		$	0.0		$	10.0		$	2,162.9
Sales to affiliates		0.7		0.8		0.0			0.0			(1.5	)		0.0
Total revenues		1,477.3		307.1		370.0			0.0			8.5			2,162.9
Depreciation and amortization		182.0		39.6		28.5			0.0			1.2			251.3
Total interest charges (1)		69.5		10.1		5.0			0.0			42.0			126.6
Internally allocated interest (1)		0.0		0.0		4.8			0.0			(4.8	)		0.0
Provision (benefit) for income taxes		94.0		17.1		(2.2	)		0.0			(19.9	)		89.0
Net income from continuing operations		151.1		27.1		2.3			0.0			(24.8	)		155.7
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0			0.0			0.0
Net income attributable to TECO Energy	$	151.1	$	27.1	$	2.3		$	0.0		($	24.8	)	$	155.7
2012
Revenues - external	$	1,527.8	$	298.9	$	474.1		$	0.0		$	7.4		$	2,308.2
Sales to affiliates		0.8		1.3		0.0			0.0			(2.1	)		0.0
Total revenues		1,528.6		300.2		474.1			0.0			5.3			2,308.2
Depreciation and amortization		177.2		37.7		31.0			0.0			1.0			246.9
Total interest charges (1)		86.2		12.6		5.5			0.0			36.5			140.8
Internally allocated interest (1)		0.0		0.0		5.2			0.0			(5.2	)		0.0
Provision (benefit) for income taxes		96.5		17.0		13.2			0.0			(13.5	)		113.2
Net income from continuing operations		156.9		27.0		39.4			0.0			(22.9	)		200.4
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			(28.6	)		(4.2	)		(32.8	)
Net income attributable to TECO Energy	$	156.9	$	27.0	$	39.4		($	28.6	)	($	27.1	)	$	167.6

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Segment Information (1)
(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala (2)		Other & Eliminations			TECO Energy
At Sept. 30, 2013
Total assets	$	6,149.8	$	1,014.3	$	339.3	$	0.0	($	109.3	)	$	7,394.1
At Dec. 31, 2012
Total assets	$	6,042.3	$	1,009.9	$	356.6	$	164.9	($	238.8	)	$	7,334.9

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2012 through September 2013 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala, Inc. and certain charges at Parent that directly relate to TECO Guatemala, Inc. Revenues for TECO Guatemala, Inc. that were reclassified to discontinued operations were $31.5 million and $100.4 million for the three and nine months ended Sept. 30, 2012, respectively. There were no revenues reclassified for the three or nine months ended Sept. 30, 2013. See Note 15 for additional information.

12. Accounting for Derivative Instruments and Hedging Activities

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

• to limit the cash flow 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 has designated all derivatives as cash flow hedges.

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 Sept. 30, 2013, all of the company’s physical contracts qualify for the NPNS exception.

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The following table presents the derivatives that are designated as cash flow hedges at Sept. 30, 2013 and Dec. 31, 2012:

Total Derivatives(1)
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.2	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.2	$	0.2
Current liabilities	$	5.2	$	14.6
Long-term liabilities		1.5		0.6
Total liabilities	$	6.7	$	15.2

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

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Sept. 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Sept. 30, 2013
Description
Derivative assets	$	1.2		$	(1.0	)	$	0.2
Derivative liabilities	$	(7.7	)	$	1.0		$	(6.7	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

The following table presents the derivative hedges of diesel fuel contracts at Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.0
Current liabilities	$	0.3	$	0.5
Long-term liabilities		0.1		0.4
Total liabilities	$	0.4	$	0.9

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The following table presents the derivative hedges of natural gas contracts at Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.1	$	0.2
Current liabilities	$	4.9	$	14.1
Long-term liabilities		1.4		0.2
Total liabilities	$	6.3	$	14.3

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at Sept. 30, 2013 is a net loss of $8.1 million after tax and accumulated amortization. This compares to a net loss of $9.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at Sept. 30, 2013 and Dec. 31, 2012:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.3
Long-term	Derivative assets		0.0	Derivative liabilities		0.1
Natural gas derivatives:
Current	Derivative assets		0.1	Derivative liabilities		4.9
Long-term	Derivative assets		0.0	Derivative liabilities		1.4
Total derivatives designated as hedging instruments		$	0.2		$	6.7

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

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The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sept. 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.1	Regulatory assets	$	4.9
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.4
Total		$	0.1		$	6.3

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

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

Based on the fair value of the instruments at Sept. 30, 2013, net pretax losses of $4.8 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 and nine months ended Sept. 30:

For the three months ended Sept. 30:	Amount of			Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.7	Mining related costs		0.1
Total	$	0.7		($	0.1	)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		1.6	Mining related costs		0.1
Total	$	1.6		($	0.1	)

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

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For the nine months ended Sept. 30:	Amount of				Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)				Effective Portion (1)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.7	)
Commodity contracts:
Diesel fuel derivatives		0.4		Mining related costs		0.0
Total	$	0.4			($	0.7	)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.6	)
Commodity contracts:
Diesel fuel derivatives		0.4		Mining related costs		0.3
Total	($	4.5	)		($	0.3	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the nine months ended Sept. 30, 2013 and 2012, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sept. 30:

(millions)	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2013
Interest rate swaps	$	0.0		$	0.0		($	0.7	)
Diesel fuel derivatives		(0.3	)		0.4			0.0
Total	($	0.3	)	$	0.4		($	0.7	)
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.6	)
Diesel fuel derivatives		(0.2	)		0.4			0.3
Total	($	0.2	)	($	4.5	)	($	0.3	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2015 for financial natural gas and Dec. 31, 2014 for financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of Sept. 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2013		0.0		1.8		0.0		9.8
2014		0.0		2.0		0.0		35.0
2015		0.0		0.0		0.0		5.9
Total		0.0		3.8		0.0		50.7

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The company is exposed to credit risk primarily through entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with diesel fuel and natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and 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 Sept. 30, 2013, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

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

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

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at Sept. 30, 2013:

Contingent Features
(millions) At Sept. 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	6.6	)	($	6.6	)	$	0.0

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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 Sept. 30, 2013 and Dec. 31, 2012. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Sept. 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
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
Liabilities
Natural gas swaps	$	0.0	$	6.3	$	0.0	$	6.3
Diesel fuel swaps		0.0		0.4		0.0		0.4
Total	$	0.0	$	6.7	$	0.0	$	6.7

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

Natural gas and diesel fuel swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (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 Sept. 30, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

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14. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $6.5 million and $16.4 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2013, respectively, and $19.0 million and $62.3 million for the three and nine months ended Sept. 30, 2012, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC was required to make an exhaustive effort to obtain sufficient information to determine if this entity was a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity were not willing to provide the information necessary to make these determinations, had no obligation to do so and the information was not available publicly. As a result, TEC was unable to determine if this entity was a VIE and, if so, which variable interest holder, if any, was the primary beneficiary. TEC had no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC was the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $13.1 million and $38.3 million for the three and nine months ended Sept. 30, 2012, respectively, under this PPA. This PPA expired on Dec. 31, 2012.

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

15. Discontinued Operations

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

Components of income from discontinued operations attributable to TECO Energy	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions)	2013			2012			2013		2012
Revenues	$	0.0		$	31.5		$	0.0	$	100.4
(Loss) Income from operations		(0.2	)		3.8			0.0		23.3
(Loss) gain on assets sold, including transaction costs		0.0			(31.2	)		0.0		(31.2	)
(Loss) Income from discontinued operations		(0.2	)		(27.4	)		0.0		(7.9	)
(Benefit) Provision for income taxes		(0.1	)		18.7			0.0		24.6
(Loss) Income from discontinued operations, net		(0.1	)		(46.1	)		0.0		(32.5	)
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.1			0.0		0.3
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0	($	32.8	)

16. Pending Acquisition of New Mexico Gas Company

Stock Purchase Agreement

On May 25, 2013, the company entered into an SPA by and among the company, NMGI and Continental Energy Systems LLC (CES). NMGI is the parent company of NMGC. Pursuant to the terms and subject to the conditions set forth in the SPA, the company will acquire from CES all of the outstanding capital stock of its subsidiary, NMGI, for an aggregate purchase price of $950 million, which includes the assumption of $200 million of senior secured notes at NMGC. The purchase price is subject to certain closing adjustments in accordance with the terms of the SPA. The permanent financing is expected to be a combination of TECO Energy common equity, cash on hand and long-term debt at NMGI and NMGC.

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The closing of the acquisition is subject to various customary closing conditions, including, among others (i) clearance under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) receipt of all required regulatory approvals from the New Mexico Public Regulation Commission, and (iii) subject to certain materiality exceptions, the accuracy of the representations and warranties made by the parties to the SPA and compliance with their respective obligations under the SPA. The Hart-Scott-Rodino waiting period expired without any further request for information. The company filed for approval from the New Mexico Public Regulation Commission on July 9, 2013. The closing of the acquisition is expected to occur either late in the first quarter or early in the second of 2014, subject to satisfaction of closing conditions.

The SPA contains customary representations and warranties of the parties, and covenants to, among other things, cooperate on seeking necessary regulatory approvals and access to information. NMGI also agreed to conduct its business and the business of its subsidiary, NMGC, in the ordinary course until the acquisition is consummated and has agreed to cooperate with the company’s efforts to obtain permanent financing. The acquisition is not subject to any financing condition and the company has entered into a credit agreement to provide bridge financing, as described in the section titled TECO Finance Bridge Facility below. The parties have agreed to indemnify each other for breaches of representations, warranties and covenants. Subject to certain exceptions, CES’s aggregate liability with respect to such indemnification obligations is capped at $30 million (subject to a $9.25 million deductible), which will be placed initially into an escrow account at closing to be available to fund indemnification claims.

The SPA contains certain termination rights for CES and the company, including, among others, the right to terminate if the acquisition is not completed by May 25, 2014 (subject to up to a four month extension under certain circumstances related to obtaining required regulatory approvals).

TECO Finance Bridge Facility

On June 24, 2013, the company and TECO Finance entered into a $1.075 billion Senior Unsecured Bridge Credit Agreement (Bridge Facility) among the company as guarantor, TECO Finance as borrower, Morgan Stanley as administrative agent, sole lead arranger and sole book runner, and the lenders named in the Bridge Facility. The Bridge Facility is sized to cover the $950 million purchase price and provide a $125 million credit facility for the operations of NMGC. Under the terms of the Bridge Facility, as of the closing of the NMGI acquisition, the Bridge Facility permits NMGC to be added to the Bridge Facility as a borrower.

Pursuant to the Bridge Facility, upon satisfaction of certain conditions precedent contained therein, the borrowers may borrow up to $1.075 billion. TECO Finance’s obligations under the Bridge Facility are unconditionally guaranteed by the company. The Bridge Facility matures 364 days after the closing of the acquisition. Repaid amounts under the Bridge Facility may not be reborrowed.

The availability of funds under the Bridge Facility is subject to certain conditions including, among others, and in each case, subject to certain exceptions: (i) the absence of a “material adverse effect” on NMGC, consistent with the definitions in the SPA; (ii) the accuracy of the representations and warranties in the Bridge Facility; (iii) the consummation of the acquisition and the absence of certain changes or waivers to the SPA; (iv) the absence of defaults under the Bridge Facility and under certain other credit facilities of the company and its subsidiaries (Existing Credit Facilities); (v) the delivery of certain financial information pertaining to the company and its subsidiaries; (vi) the solvency of the company and its subsidiaries on a consolidated basis, and compliance, on a pro forma basis after giving effect to the acquisition, with all covenants in the Existing Credit Facilities of the company and its subsidiaries; (vii) the amendment of the TECO Credit Agreement to permit the acquisition (which amendment has been completed, as described in Note 6); (viii) the payment of certain transaction fees; and (ix) the delivery of customary closing documents.

The interest rate applicable to the Bridge Facility is, at the borrower’s option, either a floating base rate or a floating Eurodollar rate, in each case, plus an applicable margin ranging from 0.25% to 2.0% depending on the company’s credit rating, and subject to a 0.25% increase for each 90-day period that elapses after the closing of the acquisition.

The Bridge Facility contains certain covenants that, among other things, restrict (i) certain mergers, consolidations, liquidations and dissolutions of the company and certain subsidiaries, (ii) sales by the company and certain subsidiaries of all or a substantial part of its assets and, (iii) certain liens by of the company or certain subsidiaries on all or substantially all of such party’s assets, in each case subject to exceptions substantially similar to those exceptions in the TECO Credit Facility. Under the Bridge Facility, the company must maintain, on a consolidated basis, a total debt to total capitalization ratio of no greater than 0.65 to 1.00 (except with respect to the four fiscal quarters commencing with the quarter in which the acquisition closes, during which it must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00).

Additionally, the Bridge Facility also contains customary events of default, including, without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness, certain events of bankruptcy and insolvency, certain ERISA events, judgments in excess of specified amounts, certain impairments to the guarantee and changes in control.

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TAMPA ELECTRIC COMPANY

In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC and its subsidiaries as of Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended as of Sept. 30, 2013 and 2012. The results of operations for the three month and nine month periods ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013. References should be made to the explanatory notes affecting the consolidated financial statements contained in TEC’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 and to the notes on pages 38 through 50 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, Sept. 30, 2013 and Dec. 31, 2012		33-34
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and nine month periods ended Sept. 30, 2013 and 2012		35-36
Consolidated Condensed Statements of Cash Flows for the nine month periods ended Sept. 30, 2013 and 2012		37
Notes to Consolidated Condensed Financial Statements		38-50

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

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Sept. 30, 2013			Dec. 31, 2012
Property, plant and equipment
Utility plant in service
Electric	$	6,862.5		$	6,654.5
Gas		1,227.9			1,171.9
Construction work in progress		351.7			335.0
Utility plant in service, at original costs		8,442.1			8,161.4
Accumulated depreciation		(2,528.1	)		(2,373.6	)
		5,914.0			5,787.8
Other property, net		8.1			7.3
Total property, plant and equipment, net		5,922.1			5,795.1
Current assets
Cash and cash equivalents		14.3			45.2
Receivables, less allowance for uncollectibles of $1.4 and $1.5 at Sept. 30, 2013 and Dec. 31, 2012, respectively		275.3			213.8
Inventories, at average cost
Fuel		90.2			89.1
Materials and supplies		73.9			72.4
Regulatory assets		40.9			70.3
Derivative assets		0.1			0.0
Taxes receivable		0.0			22.1
Deferred income taxes		22.6			20.0
Prepayments and other current assets		16.6			11.5
Total current assets		533.9			544.4
Deferred debits
Unamortized debt expense		0.1			16.1
Regulatory assets		370.5			382.6
Derivative assets		0.0			0.2
Other		21.3			6.2
Total deferred debits		391.9			405.1
Total assets	$	6,847.9		$	6,744.6

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

33

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization (millions)	Sept. 30, 2013			Dec. 31, 2012
Capitalization
Common stock	$	1,990.4		$	1,970.4
Accumulated other comprehensive loss		(8.0	)		(8.7	)
Retained earnings		335.1			304.6
Total capital		2,317.5			2,266.3
Long-term debt, less amount due within one year		1,797.6			1,932.6
Total capitalization		4,115.1			4,198.9
Current liabilities
Long-term debt due within one year		83.3			0.0
Accounts payable		192.7			188.6
Customer deposits		164.5			163.0
Regulatory liabilities		81.3			105.6
Derivative liabilities		4.9			14.1
Interest accrued		37.3			17.3
Taxes accrued		81.2			13.7
Other		11.8			11.8
Total current liabilities		657.0			514.1
Deferred credits
Deferred income taxes		1,042.7			980.9
Investment tax credits		9.4			9.7
Derivative liabilities		1.4			0.2
Regulatory liabilities		632.7			631.4
Other		389.6			409.4
Total deferred credits		2,075.8			2,031.6
Commitments and Contingencies (see Note 9)
Total liabilities and capitalization	$	6,847.9		$	6,744.6

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

34

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Sept. 30,
(millions)	2013			2012
Revenues
Electric (includes franchise fees and gross receipts taxes of $25.6 in 2013 and $26.7 in 2012)	$	556.3		$	575.1
Gas (includes franchise fees and gross receipts taxes of $4.1 in 2013 and $4.3 in 2012)		83.1			95.2
Total revenues		639.4			670.3
Expenses
Regulated operations and maintenance
Fuel		202.8			209.1
Purchased power		15.7			25.8
Cost of natural gas sold		27.0			40.5
Other		126.8			115.5
Depreciation and amortization		75.6			72.9
Taxes, other than income		48.2			48.3
Total expenses		496.1			512.1
Income from operations		143.3			158.2
Other income
Allowance for other funds used during construction		1.8			0.7
Other income, net		1.3			2.1
Total other income		3.1			2.8
Interest charges
Interest on long-term debt		26.3			30.0
Other interest		1.0			0.8
Allowance for borrowed funds used during construction		(1.1	)		(0.4	)
Total interest charges		26.2			30.4
Income before provision for income taxes		120.2			130.6
Provision for income taxes		46.1			50.1
Net income		74.1			80.5
Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges		0.2			0.2
Total other comprehensive income (loss), net of tax		0.2			0.2
Comprehensive income	$	74.3		$	80.7

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

35

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Nine months ended Sept. 30,
(millions)	2013			2012
Revenues
Electric (includes franchise fees and gross receipts taxes of $66.1 in 2013 and $70.0 in 2012)	$	1,477.0		$	1,528.3
Gas (includes franchise fees and gross receipts taxes of $15.7 in 2013 and $15.4 in 2012)		306.3			298.9
Total revenues		1,783.3			1,827.2
Expenses
Regulated operations and maintenance
Fuel		517.3			534.5
Purchased power		50.8			85.2
Cost of natural gas sold		117.4			118.6
Other		376.9			341.8
Depreciation and amortization		221.6			214.9
Taxes, other than income		138.5			140.6
Total expenses		1,422.5			1,435.6
Income from operations		360.8			391.6
Other income
Allowance for other funds used during construction		4.3			1.6
Other income, net		3.8			3.0
Total other income		8.1			4.6
Interest charges
Interest on long-term debt		79.2			93.0
Other interest		2.9			6.7
Allowance for borrowed funds used during construction		(2.5	)		(0.9	)
Total interest charges		79.6			98.8
Income before provision for income taxes		289.3			297.4
Provision for income taxes		111.1			113.5
Net income		178.2			183.9
Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges		0.7			(4.3	)
Total other comprehensive income (loss), net of tax		0.7			(4.3	)
Comprehensive income	$	178.9		$	179.6

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

36

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Nine months ended Sept. 30,
(millions)	2013			2012
Cash flows from operating activities
Net income	$	178.2		$	183.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		221.6			214.9
Deferred income taxes		57.7			92.6
Investment tax credits		(0.3	)		(0.2	)
Allowance for funds used during construction		(4.3	)		(1.6	)
Gain on sale of business/assets, pretax		0.0			(0.2	)
Deferred recovery clauses		(3.8	)		(3.7	)
Receivables, less allowance for uncollectibles		(61.5	)		(64.0	)
Inventories		(2.6	)		5.8
Prepayments		(5.1	)		(4.3	)
Taxes accrued		89.6			78.2
Interest accrued		20.0			19.4
Accounts payable		6.2			22.9
Other		1.4			4.5
Cash flows from operating activities		497.1			548.2
Cash flows from investing activities
Capital expenditures		(353.1	)		(318.3	)
Allowance for funds used during construction		4.3			1.6
Net proceeds from sale of assets		0.0			0.3
Cash flows used in investing activities		(348.8	)		(316.4	)
Cash flows from financing activities
Capital contributions		20.0			53.0
Proceeds from long-term debt issuance		0.0			538.3
Repayment of long-term debt/Purchase in lieu of redemption		(51.6	)		(460.9	)
Dividends		(147.6	)		(149.5	)
Cash flows used in financing activities		(179.2	)		(19.1	)
Net (decrease) increase in cash and cash equivalents		(30.9	)		212.7
Cash and cash equivalents at beginning of period		45.2			13.9
Cash and cash equivalents at end of period	$	14.3		$	226.6

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

37

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2012 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (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 Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three and nine months ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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

Revenues

As of Sept. 30, 2013 and Dec. 31, 2012, unbilled revenues of $51.8 million and $49.0 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013, compared to $31.0 million and $85.4 million, respectively, for the three and nine months ended Sept. 30, 2012.

Cash Flows Related to Derivatives and Hedging Activities

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

Reclassifications

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

2. New Accounting Pronouncements

Comprehensive Income

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

38

3. Regulatory

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

Base Rates-Tampa Electric

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

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

On Sept. 6, 2013, TEC and all of the intervenors in its Tampa Electric division base rate proceeding filed with the FPSC a joint motion for the FPSC to approve a stipulation and settlement agreement, which would resolve all matters in Tampa Electric’s pending base rate proceeding.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved Tampa Electric’s base rate proceeding.

Storm Damage Cost Recovery

Tampa Electric is 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. Tampa Electric’s storm reserve was $55.4 million and $50.4 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively. Effective Nov. 1, 2013, Tampa Electric will cease accruing for this storm damage reserve as a settlement provision of the base rate proceeding mentioned above. 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 the level as of Oct. 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.

39

Details of the regulatory assets and liabilities as of Sept. 30, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.2	$	67.2
Other:
Cost-recovery clauses		14.4		42.9
Postretirement benefit asset		263.8		276.1
Deferred bond refinancing costs (2)		8.3		9.2
Environmental remediation		47.8		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5
Total other regulatory assets		344.2		385.7
Total regulatory assets		411.4		452.9
Less: Current portion		40.9		70.3
Long-term regulatory assets	$	370.5	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	13.7	$	14.6
Other:
Cost-recovery clauses		49.4		73.9
Transmission and delivery storm reserve		55.4		50.4
Deferred gain on property sales (3)		2.3		3.4
Other		1.3		1.0
Accumulated reserve - cost of removal		591.9		593.7
Total other regulatory liabilities		700.3		722.4
Total regulatory liabilities		714.0		737.0
Less: Current portion		81.3		105.6
Long-term regulatory liabilities	$	632.7	$	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)	Sept. 30, 2013		Dec. 31, 2012
Clause recoverable (1)	$	18.6	$	47.0
Components of rate base (2)		266.7		279.1
Regulatory tax assets (3)		67.2		67.2
Capital structure and other (3)		58.9		59.6
Total	$	411.4	$	452.9

(1) To be recovered through recovery mechanisms 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.

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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 nine months ended Sept. 30, 2013 and 2012 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of the company’s 2011 consolidated federal income tax return during 2012. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2012 and 2013 are currently being examined by the IRS under the Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2013. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2009 and 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 Sept. 30, 2013 and 2012, respectively, was $5.4 million and $4.5 million for pension benefits, and $2.5 million and $3.1 million for other postretirement benefits. TEC’s portion of the net pension expense for the nine months ended Sept. 30, 2013 and 2012, respectively, was $16.3 million and $13.7 million for pension benefits, and $7.5 million and $9.3 million for other postretirement benefits.

For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. The SERP was remeasured as of Jun. 30, 2013 using a discount rate of 4.96% due to a settlement. Additionally, TECO Energy made contributions of $32.9 million to its pension plan in the nine months ended Sept. 30, 2013. TEC’s portion of the contributions was $26.1 million.

Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2013, TEC reclassed $4.1 million and $12.3 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

At Sept. 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Sept. 30, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	0.0	$	1.5	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

At Sept. 30, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at Sept. 30, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

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7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2013, total long-term debt had a carrying amount of $1,880.9 million and an estimated fair market value of $2,031.4 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $1,932.6 million and an estimated fair market value of $2,270.3 million. 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.

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007B

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

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

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

On March 26, 2008, TEC purchased in lieu of redemption $20 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C.

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Sept. 30, 2013 to provide an opportunity to evaluate refinancing alternatives.

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8. Other Comprehensive Income

Other Comprehensive Income	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2013
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		0.4		(0.2	)		0.2		1.1			(0.4	)		0.7
Gain on cash flow hedges		0.4		(0.2	)		0.2		1.1			(0.4	)		0.7
Total other comprehensive income	$	0.4	($	0.2	)	$	0.2	$	1.1		($	0.4	)	$	0.7
2012
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		0.4		(0.2	)		0.2		1.0			(0.4	)		0.6
Gain (Loss) on cash flow hedges		0.4		(0.2	)		0.2		(7.0	)		2.7			(4.3	)
Total other comprehensive income (loss)	$	0.4	($	0.2	)	$	0.2	($	7.0	)	$	2.7		($	4.3	)

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2013			Dec. 31, 2012
Net unrealized losses from cash flow hedges (1)	($	8.0	)	($	8.7	)
Total accumulated other comprehensive loss	($	8.0	)	($	8.7	)

(1) Net of tax benefit of $5.1 million and $5.5 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

9. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. Two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim. The Court recently denied plaintiffs’ motion for reconsideration of the ruling. PGS’s suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident remains pending, as does the Posen Construction counter-claim against PGS alleging negligence. In addition, the suit filed by the Posen Construction employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees are 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 recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected sometime in 2014.

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 Sept. 30, 2013, TEC has estimated its ultimate financial liability to be $37.2 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.

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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.

Environmental Protection Agency Section 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station in Polk County, Florida with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter. TEC responded with the requested information on April 26, 2013 and has not received any response from the EPA on this matter.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Sept. 30, 2013 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After(1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
Tampa Electric (2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at Sept. 30, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2013, TEC was in compliance with all applicable financial covenants.

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10. Segment Information

(millions) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2013
Revenues - external	$	556.3	$	83.1	$	0.0		$	639.4
Sales to affiliates		0.1		0.3		(0.4	)		0.0
Total revenues		556.4		83.4		(0.4	)		639.4
Depreciation and amortization		62.2		13.4		0.0			75.6
Total interest charges		22.8		3.4		0.0			26.2
Provision for income taxes		42.7		3.4		0.0			46.1
Net income	$	68.7	$	5.4	$	0.0		$	74.1
2012
Revenues - external	$	575.1	$	95.2	$	0.0		$	670.3
Sales to affiliates		0.1		0.0		(0.1	)		0.0
Total revenues		575.2		95.2		(0.1	)		670.3
Depreciation and amortization		60.2		12.7		0.0			72.9
Total interest charges		26.7		3.7		0.0			30.4
Provision for income taxes		45.7		4.4		0.0			50.1
Net income	$	73.5	$	7.0	$	0.0		$	80.5
Nine months ended Sept. 30,
2013
Revenues - external	$	1,477.0	$	306.3	$	0.0		$	1,783.3
Sales to affiliates		0.3		0.8		(1.1	)		0.0
Total revenues		1,477.3		307.1		(1.1	)		1,783.3
Depreciation and amortization		182.0		39.6		0.0			221.6
Total interest charges		69.5		10.1		0.0			79.6
Provision for income taxes		94.0		17.1		0.0			111.1
Net income	$	151.1	$	27.1	$	0.0		$	178.2
Total assets at Sept. 30, 2013	$	5,885.5	$	979.1	($	16.7	)	$	6,847.9
2012
Revenues - external	$	1,528.3	$	298.9	$	0.0		$	1,827.2
Sales to affiliates		0.3		1.3		(1.6	)		0.0
Total revenues		1,528.6		300.2		(1.6	)		1,827.2
Depreciation and amortization		177.2		37.7		0.0			214.9
Total interest charges		86.2		12.6		0.0			98.8
Provision for income taxes		96.5		17.0		0.0			113.5
Net income	$	156.9	$	27.0	$	0.0		$	183.9
Total assets at Dec. 31, 2012	$	5,760.4	$	970.9	$	13.3		$	6,744.6

11. 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 cash flow 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

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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 has designated all derivatives as cash flow hedges.

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 Sept. 30, 2013, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.1	$	0.2
Current liabilities (1)	$	4.9	$	14.1
Long-term liabilities		1.4		0.2
Total liabilities	$	6.3	$	14.3

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

The ending balance in AOCI related to previously settled interest rate swaps at Sept. 30, 2013 is a net loss of $8.0 million after tax and accumulated amortization. This compares to a net loss of $8.7 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Sept. 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Sept. 30, 2013
Description
Derivative assets	$	1.1		$	(1.0	)	$	0.1
Derivative liabilities	$	(7.3	)	$	1.0		$	(6.3	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

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The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sept. 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.1	Regulatory assets	$	4.9
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.4
Total		$	0.1		$	6.3

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

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

Based on the fair value of the instruments at Sept. 30, 2013, net pretax losses of $4.8 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next 12 months.

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

For the three months ended Sept. 30:	Amount of			Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)

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

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For the nine months ended Sept. 30:	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)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.7	)
Total	$	0.0			($	0.7	)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.6	)
Total	($	4.9	)		($	0.6	)

(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 nine months ended Sept. 30:

(millions)	Fair Value Asset/ (Liability)		Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2013
Interest rate swaps	$	0.0	$	0.0		($	0.7	)
Total	$	0.0	$	0.0		($	0.7	)
2012
Interest rate swaps	$	0.0	($	4.9	)	($	0.6	)
Total	$	0.0	($	4.9	)	($	0.6	)

(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 and nine months ended Sept. 30, 2013 and 2012, 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, 2015 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of Sept. 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2013		0.0		9.8
2014		0.0		35.0
2015		0.0		5.9
Total		0.0		50.7

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 Sept. 30, 2013, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio are rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

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

The table below presents the fair value of the overall contractual contingent liability positions for TEC’s derivative activity at Sept. 30, 2013:

Contingent Features
(millions) Sept. 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	6.3	)	($	6.3	)	$	0.0

12. 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 Sept. 30, 2013 and Dec. 31, 2012. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below, the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Sept. 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Total	$	0.0	$	0.1	$	0.0	$	0.1
Liabilities
Natural gas swaps	$	0.0	$	6.3	$	0.0	$	6.3
Total	$	0.0	$	6.3	$	0.0	$	6.3

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

Natural gas swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 11).

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 Sept. 30, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

13. Variable Interest Entities

In the determination of a VIE’s primary beneficiary, the primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $6.5 million and $16.4 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2013, respectively, and $19.0 million and $62.3 million for the three and nine months ended Sept. 30, 2012, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC was required to make an exhaustive effort to obtain sufficient information to determine if this entity was a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity were not willing to provide the information necessary to make these determinations, had no obligation to do so and the information was not available publicly. As a result, TEC was unable to determine if this entity was a VIE and, if so, which variable interest holder, if any, was the primary beneficiary. TEC had no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC was the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $13.1 million and $38.3 million for the three and nine months ended Sept. 30, 2012, respectively, under this PPA. This PPA expired on Dec. 31, 2012.

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

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

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this MD&A, 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 not be consummated; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required, including for 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; continuation of weak market 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; and 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, 2012, and as updated in subsequent filings with the Securities and Exchange Commission.

Earnings Summary - Unaudited
	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions, except per share amounts)	2013			2012			2013		2012
Consolidated revenues	$	765.9		$	858.6		$	2,162.9	$	2,308.2
Discontinued operations attributable to TECO Energy		(0.1	)		(46.2	)		0.0		(32.8	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7	$	167.6
Average common shares outstanding
Basic		215.2			214.5			214.9		214.2
Diluted		215.6			215.4			215.4		215.3
Earnings per share - basic
Continuing operations	$	0.29		$	0.42		$	0.72	$	0.93
Discontinued operations		0.00			(0.22	)		0.00		(0.15	)
Earnings per share attributable to TECO Energy - Basic	$	0.29		$	0.20		$	0.72	$	0.78
Earnings per share - diluted
Continuing operations	$	0.29		$	0.42		$	0.72	$	0.93
Discontinued operations		0.00			(0.22	)		0.00		(0.15	)
Earnings per share attributable to TECO Energy - Diluted	$	0.29		$	0.20		$	0.72	$	0.78

Operating Results

Three Months Ended Sept. 30, 2013

TECO Energy, Inc. reported third-quarter 2013 net income of $62.8 million, or $0.29 per share, compared with $44.0 million, or $0.20 per share, in the third quarter of 2012. Net income from continuing operations was $62.9 million, or $0.29 per share, in the 2013 third quarter, compared with $90.2 million, or $0.42 per share, for the same period in 2012. Net income in the quarter included $2.1 million of costs associated with the pending acquisition of NMGC. The 2013 third-quarter cost of $0.1 million reported in discontinued operations was related to the 2012 sale of TECO Guatemala.

Nine Months Ended Sept. 30, 2013

Year-to-date 2013 net income was $155.7 million, or $0.72 per share, compared with $167.6 million, or $0.78 per share, in the same period in 2012. Net income from continuing operations was $155.7 million, or $0.72 per share, in the 2013 year-to-date period, compared with $200.4 million, or $0.93 per share, for the same period in 2012. Year-to-date 2013 net income included $3.9 million of costs associated with the pending acquisition of NMGC.

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Operating Company Results

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

Tampa Electric - Electric Division

Tampa Electric’s net income for the third quarter of 2013 was $68.7 million, compared with $73.5 million for the same period in 2012. Results for the quarter reflected a 1.6% higher average number of customers, lower energy sales primarily due to lower sales to commercial and phosphate customers, and almost $1.0 million lower earnings on assets recovered through the Environmental Cost Recovery Clause (ECRC) due to an FPSC rule revising the return on investment calculation effective Jan. 1, 2013. Higher depreciation and operations and maintenance expenses were partially offset by lower interest expense. Third-quarter net income in 2013 included $1.8 million of AFUDC equity, which represents allowed equity cost capitalized to construction costs, compared with $0.7 million in the 2012 quarter.

Total degree days in Tampa Electric’s service area in the third quarter of 2013 were 1% below normal, and unchanged from last year. In the third quarter, rainfall, which typically reduces energy sales, in the Tampa area was almost 40% above normal and 28% above the 2012 period. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 1.0% in the third quarter of 2013 compared with the same period in 2012. Pretax base revenues were $1.7 million lower than in the 2012 period. The quarterly energy sales shown on the statistical summary that accompanies this Form 10-Q reflect the energy sales based on the timing of billing cycles, which can vary period to period. Sales to residential customers increased 1.2%, primarily reflecting customer growth. Sales to commercial customers decreased in the third quarter of 2013 as a result of the reclassification of some commercial customers to the industrial category, and lower usage primarily due to improvements in lighting efficiency. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased. Sales to other utilities decreased significantly due to the expiration of two wholesale contracts at the end of 2012.

Operations and maintenance expense, excluding all FPSC-approved cost-recovery clauses, increased $3.1 million in the 2013 quarter, reflecting primarily higher costs to operate and maintain the transmission and distribution systems, and higher employee pension and benefit costs. Depreciation and amortization expense increased $1.2 million in 2013 due to additions to facilities to serve customers. Interest expense decreased $2.4 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

Year-to-date net income was $151.1 million, compared with $156.9 million in the 2012 period, driven primarily by lower energy sales due to generally milder weather early in the year, $2.6 million lower earnings on assets recovered through the ECRC, and higher depreciation and operations and maintenance expenses partially offset by lower interest expense, and 1.5% higher average number of customers.

Year-to-date total degree days in Tampa Electric’s service area were 1% below normal, and 4% below the prior year-to-date period, reflecting generally milder weather early in the year. Pretax base revenue was more than $7 million lower than in 2012, primarily reflecting lower sales to weather-sensitive residential and commercial customers.

In the 2013 year-to-date period, total net energy for load was 1.6% lower than in the same period in 2012. In addition to the third quarter factors discussed above, milder winter and spring weather reduced sales to higher-margin and weather-sensitive residential and commercial customers while industrial-other sales were higher, reflecting improvements in the Florida economy.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, increased $8.1 million in the 2013 year-to-date period, reflecting the same factors as in the third quarter. Compared to the 2012 year-to-date period, depreciation and amortization expense increased $2.9 million, reflecting additions to facilities to serve customers, partially offset by a $1.0 million favorable adjustment to depreciation expense related to combustion turbine repairs. Interest expense decreased $10.3 million, due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

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A summary of Tampa Electric’s regulated operating statistics for the nine months ended Sept. 30, 2013 and 2012 follows:

	Operating Revenues									Kilowatt-hour sales
(millions, except average customers)	2013			2012			% Change			2013		2012		% Change
Three months ended Sept. 30,
By Customer Type
Residential	$	293.5		$	301.6			(2.7	)		2,674.5		2,641.8		1.2
Commercial		160.6			170.4			(5.8	)		1,714.1		1,748.2		(2.0	)
Industrial - Phosphate		17.0			19.2			(11.5	)		210.0		232.5		(9.7	)
Industrial - Other		26.2			26.4			(0.8	)		297.2		285.1		4.2
Other sales of electricity		46.1			49.3			(6.5	)		484.7		496.0		(2.3	)
Deferred and other revenues (1)		(4.1	)		(13.3	)		69.2
		539.3			553.6			(2.6	)		5,380.5		5,403.6		(0.4	)
Sales for resale		1.6			6.2			(74.2	)		40.9		99.2		(58.8	)
Other operating revenue		15.5			15.4			0.6
	$	556.4		$	575.2			(3.3	)		5,421.4		5,502.8		(1.5	)
Average customers (thousands)		696.1			685.5			1.5
Retail net energy for load (kilowatt hours)											5,591.6		5,646.7		(1.0	)
Nine months ended Sept. 30,
By Customer Type
Residential	$	709.3		$	747.6			(5.1	)		6,461.6		6,546.5		(1.3	)
Commercial		434.8			467.0			(6.9	)		4,568.4		4,730.0		(3.4	)
Industrial - Phosphate		53.7			56.4			(4.8	)		667.1		681.0		(2.0	)
Industrial - Other		75.0			76.8			(2.3	)		847.6		828.2		2.3
Other sales of electricity		131.9			138.0			(4.4	)		1,365.5		1,370.5		(0.4	)
Deferred and other revenues (1)		19.0			(12.8	)		248.4
		1,423.7			1,473.0			(3.3	)		13,910.2		14,156.2		(1.7	)
Sales for resale		6.5			12.9			(49.6	)		170.3		216.7		(21.4	)
Other operating revenue		47.1			42.7			10.3
	$	1,477.3		$	1,528.6			(3.4	)		14,080.5		14,372.9		(2.0	)
Average customers (thousands)		693.4			683.4			1.5
Retail net energy for load (kilowatt hours)											14,708.5		14,946.4		(1.6	)

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

Tampa Electric Company - Natural Gas Division (PGS)

Peoples Gas System reported net income of $5.4 million for the third quarter, compared with $7.0 million in 2012. Third-quarter results in 2013 reflected $2.4 million higher non-fuel operations and maintenance expense that was partially offset by lower interest expense. Average customer growth was 1.3% in the quarter, and therm sales increased to all retail customer classes. Therms sold to commercial and industrial customers increased due to improving economic conditions. Sales to power generation customers and off-system sales decreased due to the expiration of two contracts with power generators, new participants in the market, and higher natural gas prices in 2013 compared to 2012.

Peoples Gas reported net income of $27.1 million for the year-to-date period, compared with $27.0 million in the same period in 2012. Non-fuel operations and maintenance expense increased $3.7 million compared to the 2012 period. Interest expense decreased $1.5 million, due to lower long-term debt interest rates and a lower interest rate on customer deposits. Results also reflect a 1.3% higher average number of customers, and higher therm sales to all retail customer classes due to more normal winter weather and improving economic conditions. Sales to power generation customers and off-system sales decreased due to the same reasons as in the third quarter.

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A summary of PGS’s regulated operating statistics for the nine months ended Sept. 30, 2013 and 2012 follows:

	Operating Revenues							Therms
(millions, except average customers)	2013		2012		% Change			2013		2012		% Change
Three months ended Sept. 30,
By Customer Type
Residential	$	25.0	$	24.5		2.0			11.0		11.0		—
Commercial		29.1		29.9		(2.7	)		98.2		94.8		3.6
Industrial		3.3		2.4		37.5			63.3		55.5		14.1
Off system sales		12.5		26.0		(51.9	)		32.3		73.0		(55.8	)
Power generation		2.3		2.9		(20.7	)		189.3		247.1		(23.4	)
Other revenues		9.0		7.5		20.0
	$	81.2	$	93.2		(12.9	)		394.1		481.4		(18.1	)
By Sales Type
System supply	$	46.0	$	61.0		(24.6	)		50.6		93.2		(45.7	)
Transportation		26.2		24.7		6.1			343.5		388.2		(11.5	)
Other revenues		9.0		7.5		20.0
	$	81.2	$	93.2		(12.9	)		394.1		481.4		(18.1	)
Average customers (thousands)		347.3		342.7		1.3
Nine months ended Sept. 30,
By Customer Type
Residential	$	96.9	$	93.4		3.7			56.9		52.0		9.4
Commercial		101.3		100.6		0.7			330.3		313.7		5.3
Industrial		9.9		7.0		41.4			203.0		168.8		20.3
Off system sales		51.2		58.1		(11.9	)		129.5		183.2		(29.3	)
Power generation		7.9		9.6		(17.7	)		574.6		730.6		(21.4	)
Other revenues		32.2		25.6		25.8
	$	299.4	$	294.3		1.7			1,294.3		1,448.3		(10.6	)
By Sales Type
System supply	$	180.5	$	187.9		(3.9	)		211.1		265.1		(20.4	)
Transportation		86.7		80.9		7.2			1,083.2		1,183.2		(8.5	)
Other revenues		32.2		25.5		26.3
	$	299.4	$	294.3		1.7			1,294.3		1,448.3		(10.6	)
Average customers (thousands)		347.2		342.6		1.3

TECO Coal

TECO Coal reported a third-quarter loss of $1.4 million on sales of 1.5 million tons, compared with net income of $17.4 million on sales of 1.9 million tons in the same period in 2012. In 2013, third-quarter results reflect an average net per-ton selling price, excluding transportation allowances, of almost $82 per ton, compared to more than $96 per ton in 2012. In the third quarter of 2013, the all-in total per-ton cost of sales was almost $84 per ton, within the full-year guidance range and lower than in prior quarters. The cost of sales in September was below the full year 2013 cost guidance range. Due to the effects of tax-percentage depletion, TECO Coal recorded a $1.2 million income tax benefit in the third quarter of 2013, compared with a 26% effective income tax rate, or a $6.0 million tax expense, in the 2012 period.

TECO Coal recorded year-to-date 2013 net income of $2.3 million on sales of 4.2 million tons, compared with $39.4 million on sales of 4.9 million tons in the 2012 period. The 2013 year-to-date average net per-ton selling price was more than $85 per ton, compared with almost $96 per ton in 2012. The all-in total per-ton cost of sales was more than $85 per ton, which was essentially unchanged from 2012. The cost of sales in the first quarter of 2013 included some higher-cost tons from December inventory that included costs associated with personnel reductions and with idling certain mining operations. Due to the effects of tax-percentage depletion, TECO Coal recorded a $2.2 million income tax benefit in 2013, compared with a 25% effective income tax rate, or a $13.2 million tax expense, in the 2012 period.

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Parent & other

The cost for Parent & other in the third quarter of 2013 was $9.9 million, compared with a cost of $11.3 million in the same period in 2012. The cost from continuing operations for Parent & other in 2013 included $2.1 million of costs associated with the pending acquisition of NMGC.

The 2013 year-to-date cost for Parent & other was $24.8 million, compared with $27.1 million for the 2012 period. The year-to-date cost from continuing operations for Parent & other in 2013 included $3.9 million of costs associated with the pending acquisition of NMGC. Results from continuing operations in 2012 excluded costs associated with the sale of TECO Guatemala.

The $0.1 million loss from discontinued operations for the quarter represents costs and benefits recorded at Parent & other related to the 2012 sale of TECO Guatemala.

2013 Guidance

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

Tampa Electric expects to record higher revenues in November and December as a result of its September rate case settlement agreement. It expects continued customer growth consistent with year-to-date trends, and expects total retail energy sales growth to be lower than customer growth due to lower average customer usage. Operations and maintenance expenses are expected to be higher than in 2012 due to increased expenses to operate the system and reliably serve customers, higher employee-related expenses including the accrual of performance-based compensation for all employees based on expected financial results, and higher pension expense driven by lower discount rate assumptions in the current interest-rate environment.

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, which is in line with the trends experienced in the year-to-date period. It also expects to benefit from continued interest from customers utilizing petroleum and other fuel sources to convert to natural gas due to the attractive economics.

TECO Coal has 95% of its expected sales of between 5.2 million and 5.7 million tons contracted for 2013. The unsold tons are primarily High-Vol-A coal, which are forecast to be sold in the fourth quarter, but at lower prices than previously expected. On an operating basis, TECO Coal expects full-year results to be significantly lower than previously expected. Operating results are expected to be break-even in the fourth quarter, but financial results are expected to reflect additional tax benefits in the fourth quarter.

New Mexico Gas Intermediate, Inc. Acquisition

In May, the company announced that it had entered into an agreement to purchase the outstanding stock of NMGI, the parent company of NMGC, for a purchase price of $950 million, including the assumption of $200 million of existing NMGC debt (see Note 16 to the TECO Energy, Inc. Consolidated Condensed Financial Statements).

The company subsequently filed for antitrust approval through a Hart-Scott-Rodino filing. The waiting period for comments has expired. On July 9, the company filed with the New Mexico Public Regulation Commission for approval of the transaction. Integration planning among the two companies is in progress.

Income Taxes

The provision for income taxes from continuing operations for the nine month periods ended Sept. 30, 2013 and 2012 were $89.0 million and $113.2 million, respectively. The provision for income taxes in the nine months ended Sept. 30, 2013 was impacted by lower operating income, decreased state income taxes, and decreased depletion at TECO Coal.

Liquidity and Capital Resources

The table below sets forth the Sept. 30, 2013 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and TEC credit facilities.

At Sept. 30, 2013
(millions)	Consolidated		Tampa Electric Company		Other Companies		TECO Finance/Parent
Credit facilities	$	675.0	$	475.0	$	0.0	$	200.0
Drawn amounts/Letters of Credit		1.5		1.5		0.0		0.0
Available credit facilities		673.5		473.5		0.0		200.0
Cash and short-term investments		152.8		14.3		3.7		134.8
Total liquidity	$	826.3	$	487.8	$	3.7	$	334.8

On May 25, 2013, TECO Energy entered into a SPA to purchase all of the outstanding capital stock of NMGI, for an aggregate purchase price of $950 million, which includes the assumption of $200 million of senior secured notes at NMGC,

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NMGI’s wholly-owned subsidiary. On June 24, 2013, TECO Energy and TECO Finance entered into a $1.075 billion syndicated bridge facility, with Morgan Stanley as administrative agent, in order to fund the acquisition. Permanent financing is expected to be a combination of common equity, cash on hand and long-term debt at NMGI and NMGC. See Note 16 to the TECO Energy, Inc. Consolidated Condensed Financial Statements.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements (see the Liquidity and Capital Resources section above). In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2013, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Sept. 30, 2013. Reference is made to the specific agreements and instruments for more details.

Significant Financial Covenants
(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Sept. 30, 2013
TEC
Credit facility(2)	Debt/capital	Cannot exceed 65%		44.7	%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%		44.7	%
6.25% senior notes	Debt/capital	Cannot exceed 60%		44.7	%
	Limit on liens(3)	Cannot exceed $700	$	0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	Debt/capital	Cannot exceed 65%		55.4	%
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, including the June 24, 2013 amendment.

(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 Sept. 30, 2013
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	A3	A-
TECO Energy/TECO Finance	BBB	Baa2	BBB

Upon announcing the acquisition of NMGC, Standard & Poor’s and Moody’s Investors Service affirmed the current credit ratings of TECO Energy, TECO Finance and Tampa Electric, and Fitch placed the ratings on ratings watch negative. In October 2013, Fitch ratings removed Tampa Electric Company from ratings watch negative and affirmed its existing credit ratings with a stable outlook.

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

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

56

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 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 Sept. 30, 2013, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of critical accounting policies, see TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2012.

57

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to the decrease in the average market price component of the company’s outstanding natural gas swaps of approximately 4% from Dec. 31, 2012 to Sept. 30, 2013. For natural gas, the company maintained a similar volume hedged as of Sept. 30, 2013 from Dec. 31, 2012.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the nine month period ended Sept. 30, 2013:

Changes in Fair Value of Derivatives (millions)
Net fair value of derivatives as of Dec. 31, 2012	$	(15.0	)
Additions and net changes in unrealized fair value of derivatives		(6.8	)
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		15.3
Net fair value of derivatives as of Sept. 30, 2013	$	(6.5	)
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec. 31, 2012	$	(15.0	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		(6.8	)
Recorded in earnings		0.0
Realized net settlement of derivatives		15.3
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Sept. 30, 2013	$	(6.5	)

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at Sept. 30, 2013:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) (millions)
Contracts Maturing in	Current			Non-current			Total Fair Value
Source of fair value
Actively quoted prices	$	0.0		$	0.0		$	0.0
Other external sources (1)		(5.0	)		(1.5	)		(6.5	)
Model prices (2)		0.0			0.0			0.0
Total	$	(5.0	)	$	(1.5	)	$	(6.5	)

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

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

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

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.

58

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.

59

PART II. OTHER INFORMATION

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

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

	(a) Total Number of Shares (or Units) Purchased (1)		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or  Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be  Purchased Under the Plans or Programs
July 1, 2013 - July 31, 2013		468	$	17.48		0.0	$	0.0
Aug. 1, 2013 - Aug. 31, 2013		7,522	$	16.66		0.0	$	0.0
Sept. 1, 2013 - Sept. 30, 2013		490	$	16.74		0.0	$	0.0
Total 3rd Quarter 2013		8,480	$	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 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 62.

60

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)
	By:	/s/ S. W. CALLAHAN
Date: November 1, 2013		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)
	By:	/s/ S. W. CALLAHAN
Date: November 1, 2013		S. W. CALLAHAN
		Vice President-Finance and Accounting
		and Chief Financial Officer
		(Chief Accounting Officer)
		(Principal Financial and Accounting Officer)

61

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).	*
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.

62

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.

(millions)	9-months ended Sept. 30,		12-months ended Sept. 30,		Year Ended Dec. 31,
	2013		2013		2012		2011		2010			2009			2008
Income from continuing operations, before income taxes	$	244.7	$	314.9	$	383.8	$	393.5	$	321.2		$	268.3		$	205.1
Add:
Interest expense		133.0		177.5		189.6		202.4		221.5			223.4			219.1
Deduct:
Income from equity investments, net		0.0		0.0		0.0		0.0		(2.8	)		(0.6	)		0.4
Earnings before taxes and fixed charges	$	377.7	$	492.4	$	573.4	$	595.9	$	545.5		$	492.3		$	423.8
Interest expense	$	133.0	$	177.5	$	189.6	$	202.4	$	221.5		$	223.4		$	219.1
Total fixed charges	$	133.0	$	177.5	$	189.6	$	202.4	$	221.5		$	223.4		$	219.1
Ratio of earnings to fixed charges		2.84x		2.77x		3.02x		2.94x		2.46x			2.20x			1.93x

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.

	9-months ended Sept. 30,			12-months ended Sept. 30,			Year Ended Dec. 31,
(millions)	2013			2013			2012			2011			2010			2009			2008
Income from continuing operations, before income taxes	$	289.3		$	360.8		$	368.9		$	380.7		$	386.6		$	303.7		$	261.9
Interest expense		84.8			113.1			129.9			141.9			143.9			141.2			135.8
Earnings before taxes and fixed charges	$	374.1		$	473.9		$	498.8		$	522.6		$	530.5		$	444.9		$	397.7
Interest expense	$	84.8		$	113.1		$	129.9		$	141.9		$	143.9		$	141.2		$	135.8
Total fixed charges	$	84.8		$	113.1		$	129.9		$	141.9		$	143.9		$	141.2		$	135.8
Ratio of earnings to fixed charges		4.41	x		4.19	x		3.84	x		3.68	x		3.69	x		3.15	x		2.93	x

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: November 1, 2013	/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: November 1, 2013	/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: November 1, 2013	/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: November 1, 2013	/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 Sept. 30, 2013 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: November 1, 2013	/s/ J. B. RAMIL
	J. B. RAMIL
	President, Chief Executive Officer and Director
	(Principal Executive Officer)
Date: November 1, 2013	/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 Sept. 30, 2013 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: November 1, 2013	/s/ J. B. RAMIL
	J. B. RAMIL
	President, Chief Executive Officer and Director
	(Principal Executive Officer)
Date: November 1, 2013	/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 Sept. 30, 2013 (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	$	0		0		7		0		0
15-18524		0		0		0		0		0		0		0		0		0		0
15-19396		0		0		0		0		0		0		0		0		0		0
44-03010		2		0		0		0		0		2		0		1		0		2
44-07108		0		0		0		0		0		0		0		4		0		0
40-07199		5		0		0		0		0		5		0		8		1		0
YGX (5)		0		0		0		0		0		0		0		3		0		0
Totals		7		0		0		0		0	$	7		0		23		1		2
Perry County
15-05485		2		0		0		0		0	$	3		0		24		4		3
15-18565 (7)		8		0		0		0		0		30		0		61		16		40
15-18662 (8)		5		0		0		0		0		16		0		67		3		180
15-19015 (9)		11		0		0		0		0		17		0		34		12		99
Totals		26		0		0		0		0	$	66		0		186		35		322
Premier Elkhorn
15-16470		0		0		0		0		0	$	0		0		0		0		11
15-17360		0		0		0		0		0		0		0		0		0		0
15-18784		2		0		0		0		0		0		0		0		0		0
15-18823		2		0		0		0		0		3		0		6		6		0
15-18892		0		0		0		0		0		0		0		0		0		0
15-18946		2		0		0		0		0		3		0		0		0		0
15-19411		0		0		0		0		0		0		0		0		0		0
15-19590		0		0		0		0		0		0		0		0		0		0
15-19622		0		0		0		0		0		1		0		0		0		0
15-19642		0		0		0		0		0		0		0		0		0		0
15-19649		0		0		0		0		0		0		0		0		0		0
15-19650		0		0		0		0		0		0		0		0		0		0
A906 (6)		0		0		0		0		0		0		0		18		0		0
Totals		6		0		0		0		0	$	7		0		24		6		11
Grand Totals		39		0		0		0		0	$	80		0		233		42		335

1. Based on data obtained from MSHA Mine Data Retrieval System as of Oct. 1, 2013 for the quarter ended Sept. 30, 2013.

2. No TECO Coal Corporation mining entity has received written notice that it meets the requirements of a Pattern of Violations (POV) during the period, nor indicates a POV status on MSHA’s MDRS system as of Oct.1, 2013.

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. 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.

6. 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.

7. In addition to the number of “Legal Actions Resolved During the Period,” two vacated citations that were shown “In Contest” in the previous quarterly report are no longer within the MSHA Mine Data Retrieval System, and are therfore no longer reflected on this report. Also, two citations were transferred by MSHA to a third party.

8. In addition to the number of “Legal Actions Resolved During the Period,” two vacated citations that were shown “In Contest” in the previous quarterly report are no longer within the MSHA Mine Data Retrieval System, and are therfore no longer reflected on this report.

9. In addition to the number of “Legal Actions Resolved During the Period,” three vacated citations that were shown “In Contest” in the previous quarterly report are no longer within the MSHA Mine Data Retrieval System, and are therfore no longer reflected on this report.

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2013

Other Comprehensive Income

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and nine months ended Sept. 30, 2013 and 2012, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2013
Unrealized gain on cash flow hedges	$	1.1	$	(0.4	)	$	0.7	$	0.7		$	(0.3	)	$	0.4
Reclassification from AOCI to net income (1)		0.1		0.0			0.1		1.0			(0.3	)		0.7
Gain on cash flow hedges		1.2		(0.4	)		0.8		1.7			(0.6	)		1.1
Amortization of unrecognized benefit costs (2)		1.0		(0.4	)		0.6		3.2			(1.2	)		2.0
Recognized benefit costs due to settlement		2.6		(1.0	)		1.6		2.6			(1.0	)		1.6
Total other comprehensive income	$	4.8	$	(1.8	)	$	3.0	$	7.5		$	(2.8	)	$	4.7
2012
Unrealized gain (loss) on cash flow hedges	$	2.5	$	(0.9	)	$	1.6	$	(7.2	)	$	2.7		$	(4.5	)
Reclassification from AOCI to net income (1)		0.2		(0.1	)		0.1		0.5			(0.2	)		0.3
Gain (Loss) on cash flow hedges		2.7		(1.0	)		1.7		(6.7	)		2.5			(4.2	)
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5		2.3			(1.2	)		1.1
Total other comprehensive income (loss)	$	3.5	$	(1.3	)	$	2.2	$	(4.4	)	$	1.3		$	(3.1	)

(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.

Accumulated Other Comprehensive (Loss) Income
(millions)	Sept. 30, 2013			Dec. 31, 2012
Unrecognized pension loss and prior service (benefit) credit (1)	$	(29.3	)	$	(32.9	)
Unrecognized other benefit loss, prior service (benefit) cost and transition obligation (2)		11.1			11.1
Net unrealized losses from cash flow hedges (3)		(8.1	)		(9.2	)
Total accumulated other comprehensive loss	$	(26.3	)	$	(31.0	)

(1) Net of tax benefit of $17.9 million and $20.1 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(2) Net of tax expense of $6.7 million and $6.7 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax benefit of $5.2 million and $5.8 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

8. Other Comprehensive Income

Other Comprehensive Income	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2013
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		0.4		(0.2	)		0.2		1.1			(0.4	)		0.7
Gain on cash flow hedges		0.4		(0.2	)		0.2		1.1			(0.4	)		0.7
Total other comprehensive income	$	0.4	($	0.2	)	$	0.2	$	1.1		($	0.4	)	$	0.7
2012
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		0.4		(0.2	)		0.2		1.0			(0.4	)		0.6
Gain (Loss) on cash flow hedges		0.4		(0.2	)		0.2		(7.0	)		2.7			(4.3	)
Total other comprehensive income (loss)	$	0.4	($	0.2	)	$	0.2	($	7.0	)	$	2.7		($	4.3	)

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2013			Dec. 31, 2012
Net unrealized losses from cash flow hedges (1)	($	8.0	)	($	8.7	)
Total accumulated other comprehensive loss	($	8.0	)	($	8.7	)

(1) Net of tax benefit of $5.1 million and $5.5 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

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Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	138 Months Ended		35 Months Ended
	Sep. 30, 2013 PGS [Member] Plaintiff	Jun. 30, 2013 PGS [Member] Plaintiff	Sep. 30, 2013 Tampa Electric Company [Member] Plaintiff
Site Contingency [Line Items]
Number of commercial PGS customers filing on behalf of PGS customers	2	2	3
Ultimate financial liability to superfund sites and former MGP sites	$ 37.2

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Consolidated Condensed Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues
Regulated electric and gas	$ 639.6	$ 670.1	$ 1,782.7	$ 1,826.8
Unregulated	126.3	188.5	380.2	481.4
Total revenues	765.9	858.6	2,162.9	2,308.2
Expenses
Fuel	202.8	209.1	517.3	534.5
Purchased power	15.7	25.8	50.8	85.2
Cost of natural gas sold	26.7	40.5	116.9	118.5
Other	127.0	115.4	377.4	342.2
Operation and maintenance other expense
Mining related costs	108.3	141.5	314.0	358.7
Other	3.6	1.5	8.3	4.4
Depreciation and amortization	85.4	83.4	251.3	246.9
Taxes, other than income	55.9	58.3	162.8	170.8
Total expenses	625.4	675.5	1,798.8	1,861.2
Income from continuing operations	140.5	183.1	364.1	447.0
Other income
Allowance for other funds used during construction	1.8	0.7	4.3	1.6
Other income	(0.3)	2.7	2.9	5.8
Total other income	1.5	3.4	7.2	7.4
Interest charges
Interest expense	42.6	45.0	129.1	141.7
Allowance for borrowed funds used during construction	(1.1)	(0.4)	(2.5)	(0.9)
Total interest charges	41.5	44.6	126.6	140.8
Income from continuing operations before provision for income taxes	100.5	141.9	244.7	313.6
Provision for income taxes	37.6	51.7	89.0	113.2
Net income from continuing operations	62.9	90.2	155.7	200.4
Discontinued operations
Loss from discontinued operations	(0.2)	(27.4)	0	(7.9)
(Benefit) Provision for income taxes	(0.1)	18.7	0	24.6
Loss from discontinued operations, net	(0.1)	(46.1)	0	(32.5)
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.1	0	0.3
Loss from discontinued operations attributable to TECO Energy, net	(0.1)	(46.2)	0	(32.8)
Net income attributable to TECO Energy	$ 62.8	$ 44.0	$ 155.7	$ 167.6
Average common shares outstanding - Basic	215.2	214.5	214.9	214.2
Average common shares outstanding - Diluted	215.6	215.4	215.4	215.3
Earnings per share from continuing operations - Basic	$ 0.29	$ 0.42	$ 0.72	$ 0.93
Earnings per share from continuing operations - Diluted	$ 0.29	$ 0.42	$ 0.72	$ 0.93
Earnings per share from discontinued operations - Basic	$ 0.00	$ (0.22)	$ 0.00	$ (0.15)
Earnings per share from discontinued operations - Diluted	$ 0.00	$ (0.22)	$ 0.00	$ (0.15)
Earnings per share attributable to TECO Energy - Basic	$ 0.29	$ 0.20	$ 0.72	$ 0.78
Earnings per share attributable to TECO Energy - Diluted	$ 0.29	$ 0.20	$ 0.72	$ 0.78
Dividends paid per common share outstanding	$ 0.22	$ 0.22	$ 0.66	$ 0.66

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See the company’s 2012 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

The consolidated condensed financial statements include the accounts of TECO Energy, Inc., its majority-owned and controlled subsidiaries and the accounts of VIEs for which it is the primary beneficiary (TECO Energy or the company). TECO Energy is considered to be the primary beneficiary of VIEs if it has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. For the periods presented, no VIEs have been consolidated in continuing operations (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 Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three and nine months ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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

Revenues

As of Sept. 30, 2013 and Dec. 31, 2012, unbilled revenues of $51.8 million and $49.0 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013, compared to $31.0 million and $85.4 million, respectively, for the three and nine months ended Sept. 30, 2012.

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 2012 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (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 Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three and nine months ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

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

Revenues

As of Sept. 30, 2013 and Dec. 31, 2012, unbilled revenues of $51.8 million and $49.0 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013, compared to $31.0 million and $85.4 million, respectively, for the three and nine months ended Sept. 30, 2012.

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.

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Discontinued Operations

9 Months Ended

Sep. 30, 2013

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations

15. Discontinued Operations

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

Components of income from discontinued operations attributable to TECO Energy	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions)	2013			2012			2013		2012
Revenues	$	0.0		$	31.5		$	0.0	$	100.4
(Loss) Income from operations		(0.2	)		3.8			0.0		23.3
(Loss) gain on assets sold, including transaction costs		0.0			(31.2	)		0.0		(31.2	)
(Loss) Income from discontinued operations		(0.2	)		(27.4	)		0.0		(7.9	)
(Benefit) Provision for income taxes		(0.1	)		18.7			0.0		24.6
(Loss) Income from discontinued operations, net		(0.1	)		(46.1	)		0.0		(32.5	)
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.1			0.0		0.3
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0	($	32.8	)

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Fair Value Measurements - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	$ 0.2	$ 0.2
Total Swap Liabilities	6.7	15.2
Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0.2	0.2
Total Swap Liabilities	6.7	15.2
Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	6.3	14.3
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	6.3	14.3
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

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Segment Information - Schedule of Segment Information (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Segment Reporting Information [Line Items]
Internally allocated interest costs, pre tax rate			6.00%
Capital structure assumption, debt to equity ratio			50.00%
TECO Guatemala [Member]
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 31.5	$ 0	$ 100.4

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Earnings Per Share

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

9. Earnings Per Share

	For the three months ended Sept. 30,						For the nine months ended Sept. 30,
(millions, except per share amounts)	2013			2012			2013			2012
Basic earnings per share
Net income from continuing operations	$	62.9		$	90.2		$	155.7		$	200.4
Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)		(0.5	)		(0.7	)
Income before discontinued operations available to common shareholders - Basic	$	62.7		$	89.9		$	155.2		$	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0		($	32.8	)
Amount allocated to nonvested participating shareholders		0.0			0.1			0.0			0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Basic	($	0.1	)	($	46.1	)	$	0.0		($	32.7	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7		$	167.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.5	)		(0.6	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	62.6		$	43.8		$	155.2		$	167.0
Average common shares outstanding - Basic		215.2			214.5			214.9			214.2
Earnings per share from continuing operations available to common shareholders - Basic	$	0.29		$	0.42		$	0.72		$	0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		($	0.22	)	$	0.00		($	0.15	)
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.29		$	0.20		$	0.72		$	0.78
Diluted earnings per share
Net income from continuing operations	$	62.9		$	90.2		$	155.7		$	200.4
Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)		(0.5	)		(0.7	)
Income before discontinued operations available to common shareholders - Diluted	$	62.7		$	89.9		$	155.2		$	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0		($	32.8	)
Amount allocated to nonvested participating shareholders		0.0			0.1			0.0			0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	($	0.1	)	($	46.1	)	$	0.0		($	32.7	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7		$	167.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.5	)		(0.6	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	62.6		$	43.8		$	155.2		$	167.0
Unadjusted average common shares outstanding - Diluted		215.2			214.5			214.9			214.2
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.4			0.9			0.5			1.1
Average common shares outstanding - Diluted		215.6			215.4			215.4			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.29		$	0.42		$	0.72		$	0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		($	0.22	)	$	0.00		($	0.15	)
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.29		$	0.20		$	0.72		$	0.78
Anti-dilutive shares		0.0			0.0			0.0			0.6

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Long-Term Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended			1 Months Ended	9 Months Ended			1 Months Ended				9 Months Ended	1 Months Ended				9 Months Ended	1 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Mar. 01, 2011 Tampa Electric Company [Member]	Sep. 30, 2013 Tampa Electric Company [Member]	Sep. 30, 2012 Tampa Electric Company [Member]	Dec. 31, 2012 Tampa Electric Company [Member]	Sep. 01, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Sep. 03, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Mar. 15, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Mar. 26, 2008 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Sep. 30, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Sep. 01, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Sep. 03, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Mar. 15, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Mar. 26, 2008 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Sep. 30, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Mar. 01, 2011 PCIDA Bonds [Member]	Mar. 01, 2011 PCIDA Bonds [Member] Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount	$ 2,921.1		$ 2,972.7		$ 1,880.9		$ 1,932.6
Estimated fair value	3,178.1		3,439.4		2,031.4		2,270.3
Purchase in lieu of redemption	$ 51.6	$ 469.2		$ 75.0	$ 51.6	$ 460.9			$ 51.6	$ 86.0	$ 20.0	$ 232.6		$ 51.6	$ 86.0	$ 20.0	$ 232.6	$ 75.0	$ 75.0
Interest at the initial term rate per annum								5.15%		5.00%			5.15%		5.00%			1.50%	1.50%

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Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Current assets	$ 0.2	$ 0
Long-term assets	0	0.2
Total assets	0.2	0.2
Current liabilities	5.2	14.6
Long-term liabilities	1.5	0.6
Total liabilities	6.7	15.2
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1	0
Long-term assets	0	0.2
Current liabilities	4.9	14.1
Long-term liabilities	1.4	0.2
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1	0
Long-term assets	0	0
Total assets	0.1	0
Current liabilities	0.3	0.5
Long-term liabilities	0.1	0.4
Total liabilities	0.4	0.9
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1	0
Long-term assets	0	0.2
Total assets	0.1	0.2
Current liabilities	4.9	14.1
Long-term liabilities	1.4	0.2
Total liabilities	6.3	14.3
Natural Gas Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1	0
Long-term assets	0	0.2
Total assets	0.1	0.2
Current liabilities	4.9	14.1
Long-term liabilities	1.4	0.2
Total liabilities	$ 6.3	$ 14.3

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Regulatory - Additional Information (Detail) (USD $)	1 Months Ended	9 Months Ended
	Feb. 28, 2013	Sep. 30, 2013	Apr. 05, 2013	Dec. 31, 2012
Percentage of return on equity		11.25%
Allowed equity in the capital structure		54.00%
Period of average base rate		13 months
Revenue due to average base rate		$ 3,400,000,000
Increase in revenue by modification in base rate		33,500,000
Additional Revenue generated from increase in service charge			134,800,000
Return on equity maximum range	11.25%
Potential increase in ROE		10.25%
Return on equity range		Range of plus or minus 1%
Amortization period for computer software under regulatory requirement description		Tampa Electric will begin using a 15-year amortization period for all computer software
Annual accrual storm damage reserve		8,000,000
Storm damage reserve		55,400,000		50,400,000
Condition One [Member]
ROE lower range limit		9.25%
ROE upper range limit		11.25%
Condition Two [Member]
ROE lower range limit		9.50%
ROE upper range limit		11.50%
November 1, 2013 [Member]
Additional Revenue generated from increase in service charge		57,500,000
November 1, 2014
Additional Revenue generated from increase in service charge		7,500,000
November 1, 2015
Additional Revenue generated from increase in service charge		5,000,000
January 1,2017
Additional Revenue generated from increase in service charge		110,000,000
Transmission and Delivery Storm Reserve [Member]
Storm damage cost recovery period		12 months
Tampa Electric Company [Member]
Percentage of return on equity		11.25%
Allowed equity in the capital structure		54.00%
Period of average base rate		13 months
Revenue due to average base rate		3,400,000,000
Increase in revenue by modification in base rate		33,500,000
Additional Revenue generated from increase in service charge			134,800,000
Return on equity maximum range	11.25%
Potential increase in ROE		10.25%
Return on equity range		Range of plus or minus 1%
Amortization period for computer software under regulatory requirement description		Tampa Electric will begin using a 15-year amortization period for all computer software
Annual accrual storm damage reserve		8,000,000
Storm damage reserve		55,400,000		50,400,000
Tampa Electric Company [Member] | Condition One [Member]
ROE lower range limit		9.25%
ROE upper range limit		11.25%
Tampa Electric Company [Member] | Condition Two [Member]
ROE lower range limit		9.50%
ROE upper range limit		11.50%
Tampa Electric Company [Member] | November 1, 2013 [Member]
Additional Revenue generated from increase in service charge		57,500,000
Tampa Electric Company [Member] | November 1, 2014
Additional Revenue generated from increase in service charge		7,500,000
Tampa Electric Company [Member] | November 1, 2015
Additional Revenue generated from increase in service charge		5,000,000
Tampa Electric Company [Member] | January 1,2017
Additional Revenue generated from increase in service charge		110,000,000
Tampa Electric Company [Member] | Transmission and Delivery Storm Reserve [Member]
Storm damage cost recovery period		12 months
Maximum [Member]
Higher Revenue Requirements		104,000,000
Return on equity maximum range	12.25%
Potential increase in ROE		10.50%
Maximum [Member] | Tampa Electric Company [Member]
Higher Revenue Requirements		$ 104,000,000
Return on equity maximum range	12.25%
Potential increase in ROE		10.50%
Minimum [Member]
Return on equity maximum range	10.25%
Minimum [Member] | Tampa Electric Company [Member]
Return on equity maximum range	10.25%

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Regulatory (Tables)

9 Months Ended

Sep. 30, 2013

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of Sept. 30, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.2	$	67.2
Other:
Cost-recovery clauses		14.4		42.9
Postretirement benefit asset		263.8		276.1
Deferred bond refinancing costs (2)		8.3		9.2
Environmental remediation		47.8		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5
Total other regulatory assets		344.2		385.7
Total regulatory assets		411.4		452.9
Less: Current portion		40.9		70.3
Long-term regulatory assets	$	370.5	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	13.7	$	14.6
Other:
Cost-recovery clauses		49.4		73.9
Transmission and delivery storm reserve		55.4		50.4
Deferred gain on property sales (3)		2.3		3.4
Other		1.3		1.0
Accumulated reserve - cost of removal		591.9		593.7
Total other regulatory liabilities		700.3		722.4
Total regulatory liabilities		714.0		737.0
Less: Current portion		81.3		105.6
Long-term regulatory liabilities	$	632.7	$	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)	Sept. 30, 2013		Dec. 31, 2012
Clause recoverable (1)	$	18.6	$	47.0
Components of rate base (2)		266.7		279.1
Regulatory tax assets (3)		67.2		67.2
Capital structure and other (3)		58.9		59.6
Total	$	411.4	$	452.9

(1) To be recovered through recovery mechanisms 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 Sept. 30, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.2	$	67.2
Other:
Cost-recovery clauses		14.4		42.9
Postretirement benefit asset		263.8		276.1
Deferred bond refinancing costs (2)		8.3		9.2
Environmental remediation		47.8		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5
Total other regulatory assets		344.2		385.7
Total regulatory assets		411.4		452.9
Less: Current portion		40.9		70.3
Long-term regulatory assets	$	370.5	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	13.7	$	14.6
Other:
Cost-recovery clauses		49.4		73.9
Transmission and delivery storm reserve		55.4		50.4
Deferred gain on property sales (3)		2.3		3.4
Other		1.3		1.0
Accumulated reserve - cost of removal		591.9		593.7
Total other regulatory liabilities		700.3		722.4
Total regulatory liabilities		714.0		737.0
Less: Current portion		81.3		105.6
Long-term regulatory liabilities	$	632.7	$	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)	Sept. 30, 2013		Dec. 31, 2012
Clause recoverable (1)	$	18.6	$	47.0
Components of rate base (2)		266.7		279.1
Regulatory tax assets (3)		67.2		67.2
Capital structure and other (3)		58.9		59.6
Total	$	411.4	$	452.9

(1) To be recovered through recovery mechanisms 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.

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

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 Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three and nine months ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

Use of Estimates

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 Sept. 30, 2013 and Dec. 31, 2012, unbilled revenues of $51.8 million and $49.0 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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 $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013, compared to $31.0 million and $85.4 million, respectively, for the three and nine months ended Sept. 30, 2012.

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 Sept. 30, 2013 and Dec. 31, 2012, and the results of operations and cash flows for the periods ended Sept. 30, 2013 and 2012. The results of operations for the three and nine months ended Sept. 30, 2013 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2013.

Use of Estimates

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 Sept. 30, 2013 and Dec. 31, 2012, unbilled revenues of $51.8 million and $49.0 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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 $29.7 million and $81.8 million, respectively, for the three and nine months ended Sept. 30, 2013, compared to $31.0 million and $85.4 million, respectively, for the three and nine months ended Sept. 30, 2012.

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.

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Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	9 Months Ended
	Sep. 30, 2013
Line of Credit Facility [Line Items]
Credit facility maturity date	Oct. 25, 2016
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit facility maturity date	Oct. 25, 2016

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Accounting for Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2013

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 Sept. 30, 2013 and Dec. 31, 2012:

Total Derivatives(1)
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.2	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.2	$	0.2
Current liabilities	$	5.2	$	14.6
Long-term liabilities		1.5		0.6
Total liabilities	$	6.7	$	15.2

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

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 Sept. 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Sept. 30, 2013
Description
Derivative assets	$	1.2		$	(1.0	)	$	0.2
Derivative liabilities	$	(7.7	)	$	1.0		$	(6.7	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

Effect of Hedging Instruments on OCI and Income

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

For the three months ended Sept. 30:	Amount of			Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.7	Mining related costs		0.1
Total	$	0.7		($	0.1	)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		1.6	Mining related costs		0.1
Total	$	1.6		($	0.1	)

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

For the nine months ended Sept. 30:	Amount of				Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)				Effective Portion (1)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.7	)
Commodity contracts:
Diesel fuel derivatives		0.4		Mining related costs		0.0
Total	$	0.4			($	0.7	)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.6	)
Commodity contracts:
Diesel fuel derivatives		0.4		Mining related costs		0.3
Total	($	4.5	)		($	0.3	)

(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 Sept. 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2013		0.0		1.8		0.0		9.8
2014		0.0		2.0		0.0		35.0
2015		0.0		0.0		0.0		5.9
Total		0.0		3.8		0.0		50.7

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 Sept. 30, 2013:

Contingent Features
(millions) At Sept. 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	6.6	)	($	6.6	)	$	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 Sept. 30, 2013 and Dec. 31, 2012:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.3
Long-term	Derivative assets		0.0	Derivative liabilities		0.1
Natural gas derivatives:
Current	Derivative assets		0.1	Derivative liabilities		4.9
Long-term	Derivative assets		0.0	Derivative liabilities		1.4
Total derivatives designated as hedging instruments		$	0.2		$	6.7

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

Cash Flow Hedging [Member]

Effect of Hedging Instruments on OCI and Income

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sept. 30:

(millions)	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2013
Interest rate swaps	$	0.0		$	0.0		($	0.7	)
Diesel fuel derivatives		(0.3	)		0.4			0.0
Total	($	0.3	)	$	0.4		($	0.7	)
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.6	)
Diesel fuel derivatives		(0.2	)		0.4			0.3
Total	($	0.2	)	($	4.5	)	($	0.3	)

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

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 Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.0
Current liabilities	$	0.3	$	0.5
Long-term liabilities		0.1		0.4
Total liabilities	$	0.4	$	0.9

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 Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.1	$	0.2
Current liabilities	$	4.9	$	14.1
Long-term liabilities		1.4		0.2
Total liabilities	$	6.3	$	14.3

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 Sheet as of Sept. 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.1	Regulatory assets	$	4.9
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.4
Total		$	0.1		$	6.3

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

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

Tampa Electric Company [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 Sheet as of Sept. 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.1	Regulatory assets	$	4.9
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.4
Total		$	0.1		$	6.3

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

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

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 Sept. 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Sept. 30, 2013
Description
Derivative assets	$	1.1		$	(1.0	)	$	0.1
Derivative liabilities	$	(7.3	)	$	1.0		$	(6.3	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

Effect of Hedging Instruments on OCI and Income

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

For the three months ended Sept. 30:	Amount of			Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)

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

For the nine months ended Sept. 30:	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)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.7	)
Total	$	0.0			($	0.7	)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.6	)
Total	($	4.9	)		($	0.6	)

(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 Sept. 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2013		0.0		9.8
2014		0.0		35.0
2015		0.0		5.9
Total		0.0		50.7

Fair Value of Overall Contractual Contingent Liability Positions

The table below presents the fair value of the overall contractual contingent liability positions for TEC’s derivative activity at Sept. 30, 2013:

Contingent Features
(millions) Sept. 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	6.3	)	($	6.3	)	$	0.0

Tampa Electric Company [Member] | Cash Flow Hedging [Member]

Effect of Hedging Instruments on OCI and Income

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sept. 30:

(millions)	Fair Value Asset/ (Liability)		Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2013
Interest rate swaps	$	0.0	$	0.0		($	0.7	)
Total	$	0.0	$	0.0		($	0.7	)
2012
Interest rate swaps	$	0.0	($	4.9	)	($	0.6	)
Total	$	0.0	($	4.9	)	($	0.6	)

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

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 Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.1	$	0.2
Current liabilities (1)	$	4.9	$	14.1
Long-term liabilities		1.4		0.2
Total liabilities	$	6.3	$	14.3

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

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Amortization period	5-year	5-year
Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Amortization period	5-year	5-year

XML

Other Comprehensive Income - Other Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	$ 1.1	$ 2.5	$ 0.7	$ (7.2)
Reclassification from AOCI to net income, Gross	0.1	0.2	1.0	0.5
Gain (Loss) Gain on cash flow hedges, Gross	1.2	2.7	1.7	(6.7)
Amortization of unrecognized benefit costs, Gross	1.0	0.8	3.2	2.3
Recognized benefit costs due to settlement, Gross	2.6		2.6
Total other comprehensive income (loss) , Gross	4.8	3.5	7.5	(4.4)
Unrealized gain (loss) on cash flow hedges, Tax	(0.4)	(0.9)	(0.3)	2.7
Reclassification from AOCI to net income, Tax	0	(0.1)	(0.3)	(0.2)
Gain (Loss) on cash flow hedges, Tax	(0.4)	(1.0)	(0.6)	2.5
Amortization of unrecognized benefit costs, Tax	(0.4)	(0.3)	(1.2)	(1.2)
Recognized benefit costs due to settlement, Tax	(1.0)		(1.0)
Total other comprehensive income (loss) , Tax	(1.8)	(1.3)	(2.8)	1.3
Unrealized gain (loss) on cash flow hedges, Net	0.7	1.6	0.4	(4.5)
Reclassification from AOCI to net income, Net	0.1	0.1	0.7	0.3
Gain (Loss) on cash flow hedges, Net	0.8	1.7	1.1	(4.2)
Amortization of unrecognized benefit costs, Net	0.6	0.5	2.0	1.1
Recognized benefit costs due to settlement, Net	1.6		1.6
Other comprehensive income (loss), net of tax	3.0	2.2	4.7	(3.1)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	0	0	0	(8.0)
Reclassification from AOCI to net income, Gross	0.4	0.4	1.1	1.0
Gain (Loss) Gain on cash flow hedges, Gross	0.4	0.4	1.1	(7.0)
Total other comprehensive income (loss) , Gross	0.4	0.4	1.1	(7.0)
Unrealized gain (loss) on cash flow hedges, Tax	0	0	0	3.1
Reclassification from AOCI to net income, Tax	(0.2)	(0.2)	(0.4)	(0.4)
Gain (Loss) on cash flow hedges, Tax	(0.2)	(0.2)	(0.4)	2.7
Total other comprehensive income (loss) , Tax	(0.2)	(0.2)	(0.4)	2.7
Unrealized gain (loss) on cash flow hedges, Net	0	0	0	(4.9)
Reclassification from AOCI to net income, Net	0.2	0.2	0.7	0.6
Gain (Loss) on cash flow hedges, Net	0.2	0.2	0.7	(4.3)
Other comprehensive income (loss), net of tax	$ 0.2	$ 0.2	$ 0.7	$ (4.3)

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

	For the three months ended Sept. 30,						For the nine months ended Sept. 30,
(millions, except per share amounts)	2013			2012			2013			2012
Basic earnings per share
Net income from continuing operations	$	62.9		$	90.2		$	155.7		$	200.4
Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)		(0.5	)		(0.7	)
Income before discontinued operations available to common shareholders - Basic	$	62.7		$	89.9		$	155.2		$	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0		($	32.8	)
Amount allocated to nonvested participating shareholders		0.0			0.1			0.0			0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Basic	($	0.1	)	($	46.1	)	$	0.0		($	32.7	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7		$	167.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.5	)		(0.6	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	62.6		$	43.8		$	155.2		$	167.0
Average common shares outstanding - Basic		215.2			214.5			214.9			214.2
Earnings per share from continuing operations available to common shareholders - Basic	$	0.29		$	0.42		$	0.72		$	0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		($	0.22	)	$	0.00		($	0.15	)
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.29		$	0.20		$	0.72		$	0.78
Diluted earnings per share
Net income from continuing operations	$	62.9		$	90.2		$	155.7		$	200.4
Amount allocated to nonvested participating shareholders		(0.2	)		(0.3	)		(0.5	)		(0.7	)
Income before discontinued operations available to common shareholders - Diluted	$	62.7		$	89.9		$	155.2		$	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0		($	32.8	)
Amount allocated to nonvested participating shareholders		0.0			0.1			0.0			0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	($	0.1	)	($	46.1	)	$	0.0		($	32.7	)
Net income attributable to TECO Energy	$	62.8		$	44.0		$	155.7		$	167.6
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.5	)		(0.6	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	62.6		$	43.8		$	155.2		$	167.0
Unadjusted average common shares outstanding - Diluted		215.2			214.5			214.9			214.2
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.4			0.9			0.5			1.1
Average common shares outstanding - Diluted		215.6			215.4			215.4			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.29		$	0.42		$	0.72		$	0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		($	0.22	)	$	0.00		($	0.15	)
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.29		$	0.20		$	0.72		$	0.78
Anti-dilutive shares		0.0			0.0			0.0			0.6

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Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Sep. 30, 2013 gal
Diesel Fuel Derivatives [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2013 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,800,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2013 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,800,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,000,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2015 [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] | Physical [Member] | 2013 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2013 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2014 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2015 [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	50,700,000
Natural Gas Contracts [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	50,700,000
Natural Gas Contracts [Member] | Financial [Member] | 2013 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,800,000
Natural Gas Contracts [Member] | Financial [Member] | 2013 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	9,800,000
Natural Gas Contracts [Member] | Financial [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35,000,000
Natural Gas Contracts [Member] | Financial [Member] | 2014 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	35,000,000
Natural Gas Contracts [Member] | Financial [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,900,000
Natural Gas Contracts [Member] | Financial [Member] | 2015 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,900,000

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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		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	$ (0.3)	$ (0.2)	$ (0.3)	$ (0.2)
Amount of Gain/(Loss) Recognized in OCI	0.7	1.6	0.4	(4.5)
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.1)	(0.1)	(0.7)	(0.3)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	(0.3)	(0.2)	(0.3)	(0.2)
Amount of Gain/(Loss) Recognized in OCI	0.7	1.6	0.4	0.4
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0.1	0.1	0	0.3
Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0	0	0	0
Amount of Gain/(Loss) Recognized in OCI	0		0	(4.9)
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.2)		(0.7)	(0.6)
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0	0	0	0
Amount of Gain/(Loss) Recognized in OCI			0	(4.9)
Amount of Gain/(Loss) Reclassified From AOCI Into Income			(0.7)	(0.6)
Interest Rate Swap [Member] | Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0	0	0	0
Amount of Gain/(Loss) Recognized in OCI			0	(4.9)
Amount of Gain/(Loss) Reclassified From AOCI Into Income			$ (0.7)	$ (0.6)

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Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4.5	$ 4.3	$ 13.6	$ 12.8
Interest cost on projected benefit obligations	7.3	7.5	21.7	22.5
Expected return on assets	(9.6)	(9.3)	(28.8)	(27.8)
Amortization of:
Transition obligation	0	0	0	0
Prior service (benefit) cost	(0.1)	(0.1)	(0.3)	(0.3)
Actuarial loss	5.1	3.9	15.4	11.5
Settlement cost	1.0	0	1.0	0
Net pension expense recognized in the Consolidated Condensed Statements of Income	8.2	6.3	22.6	18.7
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.7	0.6	1.9	1.8
Interest cost on projected benefit obligations	2.3	2.5	7.0	7.6
Expected return on assets	0	0	0	0
Amortization of:
Transition obligation	0	0.4	0	1.3
Prior service (benefit) cost	(0.1)	0.2	(0.3)	0.6
Actuarial loss	0.2	0.1	0.7	0.1
Settlement cost	0	0	0	0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$ 3.1	$ 3.8	$ 9.3	$ 11.4

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Discontinued Operations - Components of Discontinued Operations (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
(Loss) Income from discontinued operations	$ (0.2)	$ (27.4)	$ 0	$ (7.9)
(Benefit) Provision for income taxes	0.1	(18.7)	0	(24.6)
(Loss) Income from discontinued operations, net	(0.1)	(46.1)	0	(32.5)
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.1	0	0.3
(Loss) Income from discontinued operations attributable to TECO Energy, net	(0.1)	(46.2)	0	(32.8)
TECO Guatemala [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	0	31.5	0	100.4
(Loss) Income from operations	(0.2)	3.8	0	23.3
(Loss) gain on assets sold, including transaction costs	0	(31.2)	0	(31.2)
(Loss) Income from discontinued operations	(0.2)	(27.4)	0	(7.9)
(Benefit) Provision for income taxes	(0.1)	18.7	0	24.6
(Loss) Income from discontinued operations, net	(0.1)	(46.1)	0	(32.5)
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.1	0	0.3
(Loss) Income from discontinued operations attributable to TECO Energy, net	$ (0.1)	$ (46.2)	$ 0	$ (32.8)

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Pending Acquisition of New Mexico Gas Company

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Pending Acquisition of New Mexico Gas Company

16. Pending Acquisition of New Mexico Gas Company

Stock Purchase Agreement

On May 25, 2013, the company entered into an SPA by and among the company, NMGI and Continental Energy Systems LLC (CES). NMGI is the parent company of NMGC. Pursuant to the terms and subject to the conditions set forth in the SPA, the company will acquire from CES all of the outstanding capital stock of its subsidiary, NMGI, for an aggregate purchase price of $950 million, which includes the assumption of $200 million of senior secured notes at NMGC. The purchase price is subject to certain closing adjustments in accordance with the terms of the SPA. The permanent financing is expected to be a combination of TECO Energy common equity, cash on hand and long-term debt at NMGI and NMGC.

The closing of the acquisition is subject to various customary closing conditions, including, among others (i) clearance under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) receipt of all required regulatory approvals from the New Mexico Public Regulation Commission, and (iii) subject to certain materiality exceptions, the accuracy of the representations and warranties made by the parties to the SPA and compliance with their respective obligations under the SPA. The Hart-Scott-Rodino waiting period expired without any further request for information. The company filed for approval from the New Mexico Public Regulation Commission on July 9, 2013. The closing of the acquisition is expected to occur either late in the first quarter or early in the second of 2014, subject to satisfaction of closing conditions.

The SPA contains customary representations and warranties of the parties, and covenants to, among other things, cooperate on seeking necessary regulatory approvals and access to information. NMGI also agreed to conduct its business and the business of its subsidiary, NMGC, in the ordinary course until the acquisition is consummated and has agreed to cooperate with the company’s efforts to obtain permanent financing. The acquisition is not subject to any financing condition and the company has entered into a credit agreement to provide bridge financing, as described in the section titled TECO Finance Bridge Facility below. The parties have agreed to indemnify each other for breaches of representations, warranties and covenants. Subject to certain exceptions, CES’s aggregate liability with respect to such indemnification obligations is capped at $30 million (subject to a $9.25 million deductible), which will be placed initially into an escrow account at closing to be available to fund indemnification claims.

The SPA contains certain termination rights for CES and the company, including, among others, the right to terminate if the acquisition is not completed by May 25, 2014 (subject to up to a four month extension under certain circumstances related to obtaining required regulatory approvals).

TECO Finance Bridge Facility

On June 24, 2013, the company and TECO Finance entered into a $1.075 billion Senior Unsecured Bridge Credit Agreement (Bridge Facility) among the company as guarantor, TECO Finance as borrower, Morgan Stanley as administrative agent, sole lead arranger and sole book runner, and the lenders named in the Bridge Facility. The Bridge Facility is sized to cover the $950 million purchase price and provide a $125 million credit facility for the operations of NMGC. Under the terms of the Bridge Facility, as of the closing of the NMGI acquisition, the Bridge Facility permits NMGC to be added to the Bridge Facility as a borrower.

Pursuant to the Bridge Facility, upon satisfaction of certain conditions precedent contained therein, the borrowers may borrow up to $1.075 billion. TECO Finance’s obligations under the Bridge Facility are unconditionally guaranteed by the company. The Bridge Facility matures 364 days after the closing of the acquisition. Repaid amounts under the Bridge Facility may not be reborrowed.

The availability of funds under the Bridge Facility is subject to certain conditions including, among others, and in each case, subject to certain exceptions: (i) the absence of a “material adverse effect” on NMGC, consistent with the definitions in the SPA; (ii) the accuracy of the representations and warranties in the Bridge Facility; (iii) the consummation of the acquisition and the absence of certain changes or waivers to the SPA; (iv) the absence of defaults under the Bridge Facility and under certain other credit facilities of the company and its subsidiaries (Existing Credit Facilities); (v) the delivery of certain financial information pertaining to the company and its subsidiaries; (vi) the solvency of the company and its subsidiaries on a consolidated basis, and compliance, on a pro forma basis after giving effect to the acquisition, with all covenants in the Existing Credit Facilities of the company and its subsidiaries; (vii) the amendment of the TECO Credit Agreement to permit the acquisition (which amendment has been completed, as described in Note 6); (viii) the payment of certain transaction fees; and (ix) the delivery of customary closing documents.

The interest rate applicable to the Bridge Facility is, at the borrower’s option, either a floating base rate or a floating Eurodollar rate, in each case, plus an applicable margin ranging from 0.25% to 2.0% depending on the company’s credit rating, and subject to a 0.25% increase for each 90-day period that elapses after the closing of the acquisition.

The Bridge Facility contains certain covenants that, among other things, restrict (i) certain mergers, consolidations, liquidations and dissolutions of the company and certain subsidiaries, (ii) sales by the company and certain subsidiaries of all or a substantial part of its assets and, (iii) certain liens by of the company or certain subsidiaries on all or substantially all of such party’s assets, in each case subject to exceptions substantially similar to those exceptions in the TECO Credit Facility. Under the Bridge Facility, the company must maintain, on a consolidated basis, a total debt to total capitalization ratio of no greater than 0.65 to 1.00 (except with respect to the four fiscal quarters commencing with the quarter in which the acquisition closes, during which it must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00).

Additionally, the Bridge Facility also contains customary events of default, including, without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness, certain events of bankruptcy and insolvency, certain ERISA events, judgments in excess of specified amounts, certain impairments to the guarantee and changes in control.

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Consolidated Condensed Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement Of Income And Comprehensive Income [Abstract]
Net income attributable to TECO Energy	$ 62.8	$ 44.0	$ 155.7	$ 167.6
Other comprehensive income, net of tax
Net unrealized gains (loss) on cash flow hedges	0.8	1.7	1.1	(4.2)
Amortization of unrecognized benefit costs	0.6	0.5	2.0	1.1
Recognized benefit costs due to settlement	1.6	0	1.6	0
Other comprehensive income (loss), net of tax	3.0	2.2	4.7	(3.1)
Comprehensive income attributable to TECO Energy	$ 65.8	$ 46.2	$ 160.4	$ 164.5

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Consolidated Condensed Statements of Income and Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues
Total revenues	$ 765.9	$ 858.6	$ 2,162.9	$ 2,308.2
Expenses
Fuel	202.8	209.1	517.3	534.5
Purchased power	15.7	25.8	50.8	85.2
Cost of natural gas sold	26.7	40.5	116.9	118.5
Other	127.0	115.4	377.4	342.2
Depreciation and amortization	85.4	83.4	251.3	246.9
Taxes, other than income	55.9	58.3	162.8	170.8
Total expenses	625.4	675.5	1,798.8	1,861.2
Income from operations	140.5	183.1	364.1	447.0
Other income
Allowance for other funds used during construction	1.8	0.7	4.3	1.6
Total other income	1.5	3.4	7.2	7.4
Interest charges
Interest on long-term debt	42.6	45.0	129.1	141.7
Allowance for borrowed funds used during construction	(1.1)	(0.4)	(2.5)	(0.9)
Total interest charges	41.5	44.6	126.6	140.8
Income before provision for income taxes	100.5	141.9	244.7	313.6
Provision for income taxes	37.6	51.7	89.0	113.2
Net income attributable to TECO Energy	62.8	44.0	155.7	167.6
Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges	0.8	1.7	1.1	(4.2)
Other comprehensive income (loss), net of tax	3.0	2.2	4.7	(3.1)
Comprehensive income	65.8	46.2	160.4	164.5
Tampa Electric Company [Member]
Revenues
Electric (includes franchise fees and gross receipts taxes of three months ended $25.6 in 2013 and $26.7 in 2012, nine months ended 66.1 in 2013 and $70.0 in 2012)	556.3	575.1	1,477.0	1,528.3
Gas (includes franchise fees and gross receipts taxes of three months ended $4.1 in 2013 and $4.3 in 2012 nine months ended $15.7 in 2013 and $15.4 in 2012)	83.1	95.2	306.3	298.9
Total revenues	639.4	670.3	1,783.3	1,827.2
Expenses
Fuel	202.8	209.1	517.3	534.5
Purchased power	15.7	25.8	50.8	85.2
Cost of natural gas sold	27.0	40.5	117.4	118.6
Other	126.8	115.5	376.9	341.8
Depreciation and amortization	75.6	72.9	221.6	214.9
Taxes, other than income	48.2	48.3	138.5	140.6
Total expenses	496.1	512.1	1,422.5	1,435.6
Income from operations	143.3	158.2	360.8	391.6
Other income
Allowance for other funds used during construction	1.8	0.7	4.3	1.6
Other income, net	1.3	2.1	3.8	3.0
Total other income	3.1	2.8	8.1	4.6
Interest charges
Interest on long-term debt	26.3	30.0	79.2	93.0
Other interest	1.0	0.8	2.9	6.7
Allowance for borrowed funds used during construction	(1.1)	(0.4)	(2.5)	(0.9)
Total interest charges	26.2	30.4	79.6	98.8
Income before provision for income taxes	120.2	130.6	289.3	297.4
Provision for income taxes	46.1	50.1	111.1	113.5
Net income attributable to TECO Energy	74.1	80.5	178.2	183.9
Other comprehensive income, net of tax
Net unrealized gain (loss) on cash flow hedges	0.2	0.2	0.7	(4.3)
Other comprehensive income (loss), net of tax	0.2	0.2	0.7	(4.3)
Comprehensive income	$ 74.3	$ 80.7	$ 178.9	$ 179.6

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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2013

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 is effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. The guidance will have no effect on the company’s results of operations, financial position or cash flows.

Comprehensive Income

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

Tampa Electric Company [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Comprehensive Income

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

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Consolidated Condensed Statements of Income and Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Franchise fees and gross receipts taxes	$ 29.7	$ 31.0	$ 81.8	$ 85.4
Tampa Electric Company [Member]
Franchise fees and gross receipts taxes	29.7	31.0	81.8	85.4
Tampa Electric Company [Member] | Electric [Member]
Franchise fees and gross receipts taxes	25.6	26.7	66.1	70.0
Tampa Electric Company [Member] | Gas [Member]
Franchise fees and gross receipts taxes	$ 4.1	$ 4.3	$ 15.7	$ 15.4

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Regulatory - Regulatory Assets and Related Recovery Periods (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory assets	$ 411.4	$ 452.9
Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	411.4	452.9
Clause Recoverable [Member]
Regulatory Assets [Line Items]
Regulatory assets	18.6	47.0
Clause Recoverable [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	18.6	47.0
Components of Rate Base [Member]
Regulatory Assets [Line Items]
Regulatory assets	266.7	279.1
Components of Rate Base [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	266.7	279.1
Regulatory Tax Asset [Member]
Regulatory Assets [Line Items]
Regulatory assets	67.2	67.2
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	67.2	67.2
Capital Structure and Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	58.9	59.6
Capital Structure and Other [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 58.9	$ 59.6

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Employee Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

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 Sept. 30,	2013			2012			2013			2012
Components of net periodic benefit expense
Service cost	$	4.5		$	4.3		$	0.7		$	0.6
Interest cost on projected benefit obligations		7.3			7.5			2.3			2.5
Expected return on assets		(9.6	)		(9.3	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			0.4
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		0.2
Actuarial loss		5.1			3.9			0.2			0.1
Settlement cost		1.0			0.0			0.0			0.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	8.2		$	6.3		$	3.1		$	3.8
Nine months ended Sept. 30,
Components of net periodic benefit expense
Service cost	$	13.6		$	12.8		$	1.9		$	1.8
Interest cost on projected benefit obligations		21.7			22.5			7.0			7.6
Expected return on assets		(28.8	)		(27.8	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			1.3
Prior service (benefit) cost		(0.3	)		(0.3	)		(0.3	)		0.6
Actuarial loss		15.4			11.5			0.7			0.1
Settlement cost		1.0			0.0			0.0			0.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	22.6		$	18.7		$	9.3		$	11.4

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2013

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 Sept. 30, 2013 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2013		2014-2017		After (1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
TECO Coal
Fuel purchase related (2)	$	0.0	$	1.4	$	4.0	$	5.4	$	2.3
Other subsidiaries
Guaranty under sale agreement (3)		0.0		4.9		0.0		4.9		4.9
Fuel purchase/energy management (2)		0.0		10.0		94.3		104.3		0.4
Total	$	0.0	$	16.3	$	98.3	$	114.6	$	7.6

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After (1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
Tampa Electric (2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sept. 30, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement of the TECO Guatemala equity interests.

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 Sept. 30, 2013 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After(1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
Tampa Electric (2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at Sept. 30, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Tampa Electric Company [Member]	Sep. 30, 2012 Tampa Electric Company [Member]	Sep. 30, 2013 Tampa Electric Company [Member]	Sep. 30, 2012 Tampa Electric Company [Member]	Sep. 30, 2013 Unbilled Revenues [Member]	Dec. 31, 2012 Unbilled Revenues [Member]	Sep. 30, 2013 Unbilled Revenues [Member] Tampa Electric Company [Member]	Dec. 31, 2012 Unbilled Revenues [Member] Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues									$ 51.8	$ 49.0	$ 51.8	$ 49.0
Franchise fees and gross receipts taxes	$ 29.7	$ 31.0	$ 81.8	$ 85.4	$ 29.7	$ 31.0	$ 81.8	$ 85.4

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Pending Acquisition of New Mexico Gas Company - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended			9 Months Ended		9 Months Ended
	May 25, 2013	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Bridge Facility [Member]	Jun. 24, 2013 Bridge Facility [Member]	Sep. 30, 2013 Bridge Facility [Member] Minimum [Member]	Sep. 30, 2013 Bridge Facility [Member] Maximum [Member]	Sep. 30, 2013 New Mexico Gas Company [Member] Bridge Facility [Member]
Loans At Acquisition Date [Line Items]
Aggregate Purchase Price	$ 950			$ 950
Senior Secured Notes at NMGC	200
Aggregate liability with respect to such indemnification obligations		30
Aggregate liability with respect to such indemnification obligations deductible		9.25
Credit agreement amount		$ 675.0	$ 675.0		$ 1,075.0			$ 125.0
Maturity period				364 days
Interest rate margin						0.25%	2.00%
Increase on variable rate for each period that elapses after acquisition closing				0.25%
Period after which company is subject to an increase in variable rate				90 days
Total capitalization ratio				0.70
Normal capitalization ratio				0.65

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Segment Information - Schedule of Segment Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues	$ 765.9	$ 858.6	$ 2,162.9	$ 2,308.2
Depreciation and amortization	85.4	83.4	251.3	246.9
Total interest charges	41.5	44.6	126.6	140.8
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	37.6	51.7	89.0	113.2
Net income from continuing operations	62.9	90.2	155.7	200.4
Loss from discontinued operations attributable to TECO Energy	(0.1)	(46.2)	0	(32.8)
Net income	62.8	44.0	155.7	167.6
Total assets	7,394.1		7,394.1		7,334.9
Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	765.9	858.6	2,162.9	2,308.2
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0		0
Sales to affiliates	0		0
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Revenues	556.4	575.2	1,477.3	1,528.6
Depreciation and amortization	62.2	60.2	182.0	177.2
Total interest charges	22.8	26.7	69.5	86.2
Provision (benefit) for income taxes	42.7	45.7	94.0	96.5
Net income	68.7	73.5	151.1	156.9
Total assets	5,885.5		5,885.5		5,760.4
Tampa Electric [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	556.3	575.1	1,477.0	1,528.3
Tampa Electric [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0.1		0.3
Sales to affiliates	0.1		0.3
Tampa Electric [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Revenues	556.4	575.2	1,477.3	1,528.6
Depreciation and amortization	62.2	60.2	182.0	177.2
Total interest charges	22.8	26.7	69.5	86.2
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	42.7	45.7	94.0	96.5
Net income from continuing operations	68.7	73.5	151.1	156.9
Loss from discontinued operations attributable to TECO Energy	0	0	0	0
Net income	68.7	73.5	151.1	156.9
Total assets	6,149.8		6,149.8		6,042.3
Tampa Electric [Member] | Reportable Legal Entities [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	556.2	574.9	1,476.6	1,527.8
Tampa Electric [Member] | Reportable Legal Entities [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0.3		0.8
Sales to affiliates	0.2		0.7
Peoples Gas [Member]
Segment Reporting Information [Line Items]
Revenues	83.4	95.2	307.1	300.2
Depreciation and amortization	13.4	12.7	39.6	37.7
Total interest charges	3.4	3.7	10.1	12.6
Provision (benefit) for income taxes	3.4	4.4	17.1	17.0
Net income	5.4	7.0	27.1	27.0
Total assets	979.1		979.1		970.9
Peoples Gas [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	83.1	95.2	306.3	298.9
Peoples Gas [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0		1.3
Sales to affiliates	0.3		0.8
Peoples Gas [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Revenues	83.4	95.2	307.1	300.2
Depreciation and amortization	13.4	12.7	39.6	37.7
Total interest charges	3.4	3.7	10.1	12.6
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	3.4	4.4	17.1	17.0
Net income from continuing operations	5.4	7.0	27.1	27.0
Loss from discontinued operations attributable to TECO Energy	0	0	0	0
Net income	5.4	7.0	27.1	27.0
Total assets	1,014.3		1,014.3		1,009.9
Peoples Gas [Member] | Reportable Legal Entities [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	83.1	95.2	306.3	298.9
Peoples Gas [Member] | Reportable Legal Entities [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0		1.3
Sales to affiliates	0.3		0.8
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Revenues	639.4	670.3	1,783.3	1,827.2
Depreciation and amortization	75.6	72.9	221.6	214.9
Total interest charges	26.2	30.4	79.6	98.8
Provision (benefit) for income taxes	46.1	50.1	111.1	113.5
Net income	74.1	80.5	178.2	183.9
Total assets	6,847.9		6,847.9		6,744.6
Tampa Electric Company [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	639.4	670.3	1,783.3	1,827.2
Tampa Electric Company [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0		0
Sales to affiliates	0		0
Tampa Electric Company [Member] | Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(0.4)	(0.1)	(1.1)	(1.6)
Depreciation and amortization	0	0	0	0
Total interest charges	0	0	0	0
Provision (benefit) for income taxes	0	0	0	0
Net income	0	0	0	0
Total assets	(16.7)		(16.7)		13.3
Tampa Electric Company [Member] | Consolidation, Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
Tampa Electric Company [Member] | Consolidation, Eliminations [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		(0.1)		(1.6)
Sales to affiliates	(0.4)		(1.1)
TECO Coal [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Revenues	123.7	186.0	370.0	474.1
Depreciation and amortization	9.3	10.2	28.5	31.0
Total interest charges	1.6	1.9	5.0	5.5
Internally allocated interest	1.5	1.7	4.8	5.2
Provision (benefit) for income taxes	(1.2)	6.0	(2.2)	13.2
Net income from continuing operations	(1.4)	17.4	2.3	39.4
Loss from discontinued operations attributable to TECO Energy	0	0	0	0
Net income	(1.4)	17.4	2.3	39.4
Total assets	339.3		339.3		356.6
TECO Coal [Member] | Reportable Legal Entities [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	123.7	186.0	370.0	474.1
TECO Coal [Member] | Reportable Legal Entities [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0		0
Sales to affiliates	0		0
TECO Guatemala [Member] | Reportable Legal Entities [Member]
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
Depreciation and amortization	0	0	0	0
Total interest charges	0	0	0	0
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	0	0	0	0
Net income from continuing operations	0	0	0	0
Loss from discontinued operations attributable to TECO Energy	0	(42.6)	0	(28.6)
Net income	0	(42.6)	0	(28.6)
Total assets	0		0		164.9
TECO Guatemala [Member] | Reportable Legal Entities [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
TECO Guatemala [Member] | Reportable Legal Entities [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		0		0
Sales to affiliates	0		0
Consolidation, Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	2.4	2.2	8.5	5.3
Depreciation and amortization	0.5	0.3	1.2	1.0
Total interest charges	13.7	12.3	42.0	36.5
Internally allocated interest	(1.5)	(1.7)	(4.8)	(5.2)
Provision (benefit) for income taxes	(7.3)	(4.4)	(19.9)	(13.5)
Net income from continuing operations	(9.8)	(7.7)	(24.8)	(22.9)
Loss from discontinued operations attributable to TECO Energy	(0.1)	(3.6)	0	(4.2)
Net income	(9.9)	(11.3)	(24.8)	(27.1)
Consolidation, Eliminations [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Revenues	2.9	2.5	10.0	7.4
Consolidation, Eliminations [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Revenues		(0.3)		(2.1)
Sales to affiliates	(0.5)		(1.5)
Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total assets	$ (109.3)		$ (109.3)		$ (238.8)

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	$ (8.1)	$ (9.2)
Total accumulated other comprehensive loss	(26.3)	(31.0)
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit loss, prior service (benefit) cost and transition obligation	(29.3)	(32.9)
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit loss, prior service (benefit) cost and transition obligation	11.1	11.1
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	(8.0)	(8.7)
Total accumulated other comprehensive loss	$ (8.0)	$ (8.7)

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Short-Term Debt - Credit Facilities (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Feb. 15, 2013	Dec. 31, 2012
Line of Credit Facility [Line Items]
Credit Facilities	$ 675.0		$ 675.0
Borrowings Outstanding	0		0
Letters of Credit Outstanding	1.5		1.5
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit Facilities	475.0		475.0
Borrowings Outstanding	0		0
Letters of Credit Outstanding	1.5		1.5
Tampa Electric Company [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	325.0		325.0
Borrowings Outstanding	0		0
Letters of Credit Outstanding	1.5		1.5
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	0		0
Letters of Credit Outstanding	0		0
TECO ENERGY, INC. [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

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Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Allowance for uncollectibles	$ 4.1	$ 4.2
Common equity, shares authorized	400.0	400.0
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	217.3	216.6
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 1.4	$ 1.5

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Employee Postretirement Benefits

9 Months Ended

Sep. 30, 2013

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 Sept. 30,	2013			2012			2013			2012
Components of net periodic benefit expense
Service cost	$	4.5		$	4.3		$	0.7		$	0.6
Interest cost on projected benefit obligations		7.3			7.5			2.3			2.5
Expected return on assets		(9.6	)		(9.3	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			0.4
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		0.2
Actuarial loss		5.1			3.9			0.2			0.1
Settlement cost		1.0			0.0			0.0			0.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	8.2		$	6.3		$	3.1		$	3.8
Nine months ended Sept. 30,
Components of net periodic benefit expense
Service cost	$	13.6		$	12.8		$	1.9		$	1.8
Interest cost on projected benefit obligations		21.7			22.5			7.0			7.6
Expected return on assets		(28.8	)		(27.8	)		0.0			0.0
Amortization of:
Transition obligation		0.0			0.0			0.0			1.3
Prior service (benefit) cost		(0.3	)		(0.3	)		(0.3	)		0.6
Actuarial loss		15.4			11.5			0.7			0.1
Settlement cost		1.0			0.0			0.0			0.0
Net pension expense recognized in the Consolidated Condensed Statements of Income	$	22.6		$	18.7		$	9.3		$	11.4

For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. The SERP was remeasured as of Jun. 30, 2013 using a discount rate of 4.96% due to a settlement. Additionally, TECO Energy made contributions of $32.9 million to its pension plan for the nine months ended Sept. 30, 2013.

For the three and nine months ended Sept. 30, 2013, TECO Energy and its subsidiaries reclassed $1.0 million and $3.2 million pretax, respectively, of unamortized transition obligation, prior service cost and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and nine months ended Sept. 30, 2013, TEC reclassed $4.1 million and $12.3 million, respectively, of unamortized transition obligation, prior service cost 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 Sept. 30, 2013 and 2012, respectively, was $5.4 million and $4.5 million for pension benefits, and $2.5 million and $3.1 million for other postretirement benefits. TEC’s portion of the net pension expense for the nine months ended Sept. 30, 2013 and 2012, respectively, was $16.3 million and $13.7 million for pension benefits, and $7.5 million and $9.3 million for other postretirement benefits.

For the fiscal 2013 plan year, TECO Energy assumed a long-term EROA of 7.50% and a discount rate of 4.196% for pension benefits under its qualified pension plan, and a discount rate of 4.180% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. The SERP was remeasured as of Jun. 30, 2013 using a discount rate of 4.96% due to a settlement. Additionally, TECO Energy made contributions of $32.9 million to its pension plan in the nine months ended Sept. 30, 2013. TEC’s portion of the contributions was $26.1 million.

Included in the benefit expenses discussed above, for the three and nine months ended Sept. 30, 2013, TEC reclassed $4.1 million and $12.3 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

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Consolidated Condensed Statements of Income (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement [Abstract]
Franchise fees and gross receipts taxes	$ 29.7	$ 31.0	$ 81.8	$ 85.4

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Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012
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	8.1	8.1	9.2
Net pretax losses expected to be reclassified from regulatory assets or liabilities		4.8
Interest Rate Swap [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	8.1	8.1	9.2
Tampa Electric Company [Member]
Derivative [Line Items]
Collateral posted with or received from any counterparties	0	0	0
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	8.0	8.0	8.7
Net pretax losses expected to be reclassified from regulatory assets or liabilities		$ 4.8

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Consolidated Condensed Balance Sheets (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 152.8	$ 200.5
Receivables, less allowance for uncollectibles	347.1	282.7
Inventories, at average cost
Fuel	119.6	123.6
Materials and supplies	83.0	82.1
Regulatory assets	40.9	70.3
Derivative assets	0.2	0
Income tax receivables	0.8	0.4
Deferred income taxes	28.5	63.3
Prepayments and other current assets	38.1	33.9
Total current assets	811.0	856.8
Property, plant and equipment
Electric	6,862.5	6,655.8
Gas	1,284.3	1,228.3
Construction work in progress	356.6	336.1
Other property	447.3	443.8
Property, plant and equipment, at original costs	8,950.7	8,664.0
Accumulated depreciation	(2,869.8)	(2,695.5)
Total property, plant and equipment, net	6,080.9	5,968.5
Other assets
Regulatory assets	370.5	382.6
Derivative assets	0	0.2
Deferred charges and other assets	131.7	126.8
Total other assets	502.2	509.6
Total assets	7,394.1	7,334.9
Current liabilities
Long-term debt due within one year	83.3	0
Accounts payable	241.3	232.8
Customer deposits	164.5	162.9
Regulatory liabilities	81.3	105.6
Derivative liabilities	5.2	14.6
Interest accrued	55.4	33.2
Taxes accrued	79.3	32.1
Other	17.4	19.9
Total current liabilities	727.7	601.1
Other liabilities
Deferred income taxes	338.0	277.9
Investment tax credits	9.4	9.7
Regulatory liabilities	632.7	631.4
Derivative liabilities	1.5	0.6
Deferred credits and other liabilities	523.1	549.7
Long-term debt, less amount due within one year	2,837.8	2,972.7
Total other liabilities	4,342.5	4,442.0
Commitments and Contingencies
Capital
Common equity	217.3	216.6
Additional paid in capital	1,578.8	1,564.5
Retained earnings	554.1	541.7
Accumulated other comprehensive loss	(26.3)	(31.0)
Total capital	2,323.9	2,291.8
Long-term debt, less amount due within one year	2,837.8	2,972.7
Total liabilities and capital	7,394.1	7,334.9
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	14.3	45.2
Receivables, less allowance for uncollectibles	275.3	213.8
Inventories, at average cost
Fuel	90.2	89.1
Materials and supplies	73.9	72.4
Regulatory assets	40.9	70.3
Derivative assets	0.1	0
Income tax receivables	0	22.1
Deferred income taxes	22.6	20.0
Prepayments and other current assets	16.6	11.5
Total current assets	533.9	544.4
Property, plant and equipment
Electric	6,862.5	6,654.5
Gas	1,227.9	1,171.9
Construction work in progress	351.7	335.0
Property, plant and equipment, at original costs	8,442.1	8,161.4
Accumulated depreciation	(2,528.1)	(2,373.6)
Public utilities, property, plant and equipment, net	5,914.0	5,787.8
Other property, net	8.1	7.3
Total property, plant and equipment, net	5,922.1	5,795.1
Other assets
Unamortized debt expense	0.1	16.1
Regulatory assets	370.5	382.6
Derivative assets	0	0.2
Other	21.3	6.2
Total other assets	391.9	405.1
Total assets	6,847.9	6,744.6
Current liabilities
Long-term debt due within one year	83.3	0
Accounts payable	192.7	188.6
Customer deposits	164.5	163.0
Regulatory liabilities	81.3	105.6
Derivative liabilities	4.9	14.1
Interest accrued	37.3	17.3
Taxes accrued	81.2	13.7
Other	11.8	11.8
Total current liabilities	657.0	514.1
Other liabilities
Deferred income taxes	1,042.7	980.9
Investment tax credits	9.4	9.7
Regulatory liabilities	632.7	631.4
Derivative liabilities	1.4	0.2
Other	389.6	409.4
Long-term debt, less amount due within one year	1,797.6	1,932.6
Total other liabilities	2,075.8	2,031.6
Commitments and Contingencies
Capital
Common equity	1,990.4	1,970.4
Retained earnings	335.1	304.6
Accumulated other comprehensive loss	(8.0)	(8.7)
Total capital	2,317.5	2,266.3
Long-term debt, less amount due within one year	1,797.6	1,932.6
Total capitalization	4,115.1	4,198.9
Total liabilities and capital	$ 6,847.9	$ 6,744.6

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 5.2	$ 5.8
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)	17.9	20.1
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)	6.7	6.7
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 5.1	$ 5.5

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Short-Term Debt (Tables)

9 Months Ended

Sep. 30, 2013

Short-Term Debt Credit Facilities

At Sept. 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Sept. 30, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	1.5	$	675.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

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

Tampa Electric Company [Member]

Short-Term Debt Credit Facilities

At Sept. 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Sept. 30, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	0.0	$	1.5	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

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Variable Interest Entities

9 Months Ended

Sep. 30, 2013

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 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $6.5 million and $16.4 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2013, respectively, and $19.0 million and $62.3 million for the three and nine months ended Sept. 30, 2012, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC was required to make an exhaustive effort to obtain sufficient information to determine if this entity was a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity were not willing to provide the information necessary to make these determinations, had no obligation to do so and the information was not available publicly. As a result, TEC was unable to determine if this entity was a VIE and, if so, which variable interest holder, if any, was the primary beneficiary. TEC had no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC was the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $13.1 million and $38.3 million for the three and nine months ended Sept. 30, 2012, respectively, under this PPA. This PPA expired on Dec. 31, 2012.

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

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 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $6.5 million and $16.4 million of capacity pursuant to PPAs for the three and nine months ended Sept. 30, 2013, respectively, and $19.0 million and $62.3 million for the three and nine months ended Sept. 30, 2012, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC was required to make an exhaustive effort to obtain sufficient information to determine if this entity was a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity were not willing to provide the information necessary to make these determinations, had no obligation to do so and the information was not available publicly. As a result, TEC was unable to determine if this entity was a VIE and, if so, which variable interest holder, if any, was the primary beneficiary. TEC had no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC was the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $13.1 million and $38.3 million for the three and nine months ended Sept. 30, 2012, respectively, under this PPA. This PPA expired on Dec. 31, 2012.

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

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Employee Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013 Tampa Electric Company [Member]	Sep. 30, 2013 Tampa Electric Company [Member]	Sep. 30, 2013 Pension Benefits [Member]	Sep. 30, 2013 Pension Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2012 Pension Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2013 Pension Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2012 Pension Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2013 Other Postretirement Benefits [Member]	Sep. 30, 2013 Other Postretirement Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2012 Other Postretirement Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2013 Other Postretirement Benefits [Member] Tampa Electric Company [Member]	Sep. 30, 2012 Other Postretirement Benefits [Member] Tampa Electric Company [Member]	Jun. 30, 2013 SERP [Member]	Jun. 30, 2013 SERP [Member] Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA		7.50%		7.50%
Discount rate					4.196%	4.196%		4.196%		4.18%	4.18%		4.18%		4.96%	4.96%
Contributions to pension plan		$ 32.9		$ 26.1
Reclassification of AOCI to net income as part of periodic benefit expense	1.0	3.2
Reclassification of regulatory assets to net income as part of periodic benefit expense	4.1	12.3	4.1	12.3
Net pension expense						$ 5.4	$ 4.5	$ 16.3	$ 13.7		$ 2.5	$ 3.1	$ 7.5	$ 9.3

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Commitments and Contingencies - Letters of Credit and Guarantees (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Guarantor Obligations [Line Items]
2013	$ 0
2014-2017	16.3
After 2017	98.3
Total	114.6
Liabilities Recognized at Sep 30, 2013	7.6
TECO Coal [Member] | Guarantees for Benefit of Fuel purchase related [Member]
Guarantor Obligations [Line Items]
2013	0
2014-2017	1.4
After 2017	4.0
Total	5.4
Liabilities Recognized at Sep 30, 2013	2.3
Other Subsidiaries [Member] | Guaranty Under Sale Agreement [Member]
Guarantor Obligations [Line Items]
2013	0
2014-2017	4.9
After 2017	0
Total	4.9
Liabilities Recognized at Sep 30, 2013	4.9
Other Subsidiaries [Member] | Fuel purchase/energy management [Member]
Guarantor Obligations [Line Items]
2013	0
2014-2017	10.0
After 2017	94.3
Total	104.3
Liabilities Recognized at Sep 30, 2013	0.4
Tampa Electric Company [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
2013	0.8
2014-2017	0
After 2017	0.7
Total	1.5
Liabilities Recognized at Sep 30, 2013	$ 0.3

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Accounting for Derivative Instruments and Hedging Activities - Fair Value of Overall Contractual Contingent Liability Positions (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Credit Derivatives [Line Items]
Fair Value Asset/ (Liability)	$ (6.6)
Derivative Exposure Asset/ (Liability)	(6.6)
Posted Collateral	0
Tampa Electric Company [Member]
Credit Derivatives [Line Items]
Fair Value Asset/ (Liability)	(6.3)
Derivative Exposure Asset/ (Liability)	(6.3)
Posted Collateral	$ 0

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Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Regulatory assets:
Regulatory assets	$ 411.4	$ 452.9
Less: Current portion	40.9	70.3
Long-term regulatory assets	370.5	382.6
Regulatory liabilities
Regulatory liabilities	714.0	737.0
Regulatory liabilities	714.0	737.0
Less: Current portion	81.3	105.6
Long-term regulatory liabilities	632.7	631.4
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	411.4	452.9
Less: Current portion	40.9	70.3
Long-term regulatory assets	370.5	382.6
Regulatory liabilities
Regulatory liabilities	714.0	737.0
Regulatory liabilities	714.0	737.0
Less: Current portion	81.3	105.6
Long-term regulatory liabilities	632.7	631.4
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	67.2	67.2
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	67.2	67.2
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	14.4	42.9
Regulatory liabilities
Regulatory liabilities	49.4	73.9
Regulatory liabilities	49.4	73.9
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	14.4	42.9
Regulatory liabilities
Regulatory liabilities	49.4	73.9
Regulatory liabilities	49.4	73.9
Postretirement Benefit Asset [Member]
Regulatory assets:
Regulatory assets	263.8	276.1
Postretirement Benefit Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	263.8	276.1
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	8.3	9.2
Deferred Bond Refinancing Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	8.3	9.2
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	47.8	46.9
Environmental Remediation [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	47.8	46.9
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	4.2	4.1
Competitive Rate Adjustment [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	4.2	4.1
Other [Member]
Regulatory assets:
Regulatory assets	5.7	6.5
Other [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	5.7	6.5
Total Other Regulatory Assets [Member]
Regulatory assets:
Regulatory assets	344.2	385.7
Total Other Regulatory Assets [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	344.2	385.7
Regulatory Tax Liability [Member]
Regulatory liabilities
Regulatory liabilities	13.7	14.6
Regulatory liabilities	13.7	14.6
Regulatory Tax Liability [Member] | Tampa Electric Company [Member]
Regulatory liabilities
Regulatory liabilities	13.7	14.6
Regulatory liabilities	13.7	14.6
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities
Regulatory liabilities	55.4	50.4
Regulatory liabilities	55.4	50.4
Transmission and Delivery Storm Reserve [Member] | Tampa Electric Company [Member]
Regulatory liabilities
Regulatory liabilities	55.4	50.4
Regulatory liabilities	55.4	50.4
Deferred Gain on Property Sales [Member]
Regulatory liabilities
Regulatory liabilities	2.3	3.4
Regulatory liabilities	2.3	3.4
Deferred Gain on Property Sales [Member] | Tampa Electric Company [Member]
Regulatory liabilities
Regulatory liabilities	2.3	3.4
Regulatory liabilities	2.3	3.4
Other [Member]
Regulatory liabilities
Regulatory liabilities	1.3	1.0
Regulatory liabilities	1.3	1.0
Other [Member] | Tampa Electric Company [Member]
Regulatory liabilities
Regulatory liabilities	1.3	1.0
Regulatory liabilities	1.3	1.0
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities
Regulatory liabilities	591.9	593.7
Regulatory liabilities	591.9	593.7
Accumulated Reserve - Cost of Removal [Member] | Tampa Electric Company [Member]
Regulatory liabilities
Regulatory liabilities	591.9	593.7
Regulatory liabilities	591.9	593.7
Total Other Regulatory Liabilities [Member]
Regulatory liabilities
Regulatory liabilities	700.3	722.4
Regulatory liabilities	700.3	722.4
Total Other Regulatory Liabilities [Member] | Tampa Electric Company [Member]
Regulatory liabilities
Regulatory liabilities	700.3	722.4
Regulatory liabilities	$ 700.3	$ 722.4

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

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 Sept. 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
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
Liabilities
Natural gas swaps	$	0.0	$	6.3	$	0.0	$	6.3
Diesel fuel swaps		0.0		0.4		0.0		0.4
Total	$	0.0	$	6.7	$	0.0	$	6.7

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

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 Sept. 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Total	$	0.0	$	0.1	$	0.0	$	0.1
Liabilities
Natural gas swaps	$	0.0	$	6.3	$	0.0	$	6.3
Total	$	0.0	$	6.3	$	0.0	$	6.3

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

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

9 Months Ended

Sep. 30, 2013

TECO Guatemala [Member]

Components of Discontinued Operations

The following table provides selected components of discontinued operations:

Components of income from discontinued operations attributable to TECO Energy	Three months ended Sept. 30,						Nine months ended Sept. 30,
(millions)	2013			2012			2013		2012
Revenues	$	0.0		$	31.5		$	0.0	$	100.4
(Loss) Income from operations		(0.2	)		3.8			0.0		23.3
(Loss) gain on assets sold, including transaction costs		0.0			(31.2	)		0.0		(31.2	)
(Loss) Income from discontinued operations		(0.2	)		(27.4	)		0.0		(7.9	)
(Benefit) Provision for income taxes		(0.1	)		18.7			0.0		24.6
(Loss) Income from discontinued operations, net		(0.1	)		(46.1	)		0.0		(32.5	)
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.1			0.0		0.3
(Loss) Income from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	46.2	)	$	0.0	($	32.8	)

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Taxes

4. Income Taxes

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2011 consolidated federal income tax return during 2012. The statute of limitations remains open for years 2010 and forward. Years 2012 and 2013 are currently being examined by the IRS under their Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2013. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2009 and forward.

The company recognizes interest and penalties associated with uncertain tax positions in “Operation & maintenance other expense-Other” on the Consolidated Condensed Statements of Income in accordance with standards for accounting for uncertainty in income taxes. For the nine months ended Sept. 30, 2013 and Sept. 30, 2012, the company recorded $0.1 million and $0.1 million of interest charges respectively. No amounts were recorded in continuing operations for penalties for the nine months ended Sept. 30, 2013 or Sept. 30, 2012.

The company expects to recognize the remaining unrecognized tax benefits by the end of 2013 as a result of a lapse of the statute of limitations, which would affect the annual effective tax rate.

During the three months ended Sept. 30, 2012, the company incurred an after-tax charge of $22.6 million for foreign tax credits associated with its Guatemalan operations being reclassified as an asset held for sale. See Note 15 for more information.

The effective tax rate for continuing operations increased to 36.37% for the nine months ended Sept. 30, 2013 from 36.09% for the same period in 2012. The increase is principally due to decreased depletion.

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 nine months ended Sept. 30, 2013 and 2012 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of the company’s 2011 consolidated federal income tax return during 2012. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2012 and 2013 are currently being examined by the IRS under the Compliance Assurance Program. TECO Energy does not expect the settlement of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2013. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2009 and forward.

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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		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ 0.7	$ 1.6	$ 0.4	$ (4.5)
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.1)	(0.1)	(0.7)	(0.3)
Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0		0	(4.9)
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.2)		(0.7)	(0.6)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0.7	1.6	0.4	0.4
Location of Gain/(Loss) Reclassified From AOCI Into Income	Mining related costs	Mining related costs	Mining related costs	Mining related costs
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0.1	0.1	0	0.3
Interest rate contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	0	0	(4.9)
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense	Interest expense	Interest expense	Interest expense
Amount of Gain/(Loss) on Derivatives Recognized in OCI	(0.2)	(0.2)	(0.7)	(0.6)
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	(4.9)
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense		Interest expense	Interest expense
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ (0.2)		$ (0.7)	$ (0.6)

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2013

Other Comprehensive Income

Other Comprehensive Income
	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2013
Unrealized gain on cash flow hedges	$	1.1	$	(0.4	)	$	0.7	$	0.7		$	(0.3	)	$	0.4
Reclassification from AOCI to net income (1)		0.1		0.0			0.1		1.0			(0.3	)		0.7
Gain on cash flow hedges		1.2		(0.4	)		0.8		1.7			(0.6	)		1.1
Amortization of unrecognized benefit costs (2)		1.0		(0.4	)		0.6		3.2			(1.2	)		2.0
Recognized benefit costs due to settlement		2.6		(1.0	)		1.6		2.6			(1.0	)		1.6
Total other comprehensive income	$	4.8	$	(1.8	)	$	3.0	$	7.5		$	(2.8	)	$	4.7
2012
Unrealized gain (loss) on cash flow hedges	$	2.5	$	(0.9	)	$	1.6	$	(7.2	)	$	2.7		$	(4.5	)
Reclassification from AOCI to net income (1)		0.2		(0.1	)		0.1		0.5			(0.2	)		0.3
Gain (Loss) on cash flow hedges		2.7		(1.0	)		1.7		(6.7	)		2.5			(4.2	)
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5		2.3			(1.2	)		1.1
Total other comprehensive income (loss)	$	3.5	$	(1.3	)	$	2.2	$	(4.4	)	$	1.3		$	(3.1	)

(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.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive (Loss) Income
(millions)	Sept. 30, 2013			Dec. 31, 2012
Unrecognized pension loss and prior service (benefit) credit (1)	$	(29.3	)	$	(32.9	)
Unrecognized other benefit loss, prior service (benefit) cost and transition obligation (2)		11.1			11.1
Net unrealized losses from cash flow hedges (3)		(8.1	)		(9.2	)
Total accumulated other comprehensive loss	$	(26.3	)	$	(31.0	)

(1) Net of tax benefit of $17.9 million and $20.1 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(2) Net of tax expense of $6.7 million and $6.7 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax benefit of $5.2 million and $5.8 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

Other Comprehensive Income	Three months ended Sept. 30,							Nine months ended Sept. 30,
(millions)	Gross		Tax			Net		Gross			Tax			Net
2013
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		0.4		(0.2	)		0.2		1.1			(0.4	)		0.7
Gain on cash flow hedges		0.4		(0.2	)		0.2		1.1			(0.4	)		0.7
Total other comprehensive income	$	0.4	($	0.2	)	$	0.2	$	1.1		($	0.4	)	$	0.7
2012
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		0.4		(0.2	)		0.2		1.0			(0.4	)		0.6
Gain (Loss) on cash flow hedges		0.4		(0.2	)		0.2		(7.0	)		2.7			(4.3	)
Total other comprehensive income (loss)	$	0.4	($	0.2	)	$	0.2	($	7.0	)	$	2.7		($	4.3	)

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Sept. 30, 2013			Dec. 31, 2012
Net unrealized losses from cash flow hedges (1)	($	8.0	)	($	8.7	)
Total accumulated other comprehensive loss	($	8.0	)	($	8.7	)

(1) Net of tax benefit of $5.1 million and $5.5 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively.

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Income Taxes - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended			3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Tampa Electric Company [Member]	Sep. 30, 2012 TECO Guatemala [Member]	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations			3 years		3 years	4 years
Income tax examination period	1 year		1 year
Interest recognition associated with uncertain tax positions	$ 0.1	$ 0.1
Penalties recognition associated with uncertain tax positions	0	0
Unused foreign tax credits				$ 22.6
Effective tax rate	36.37%	36.09%

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Long-Term Debt

9 Months Ended

Sep. 30, 2013

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,178.1 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,439.4 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are level 2 instruments.

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007B

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

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

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

On March 26, 2008, TEC purchased in lieu of redemption $20 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C.

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Sept. 30, 2013 to provide an opportunity to evaluate refinancing alternatives.

Tampa Electric Company [Member]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At Sept. 30, 2013, total long-term debt had a carrying amount of $1,880.9 million and an estimated fair market value of $2,031.4 million. At Dec. 31, 2012, total long-term debt had a carrying amount of $1,932.6 million and an estimated fair market value of $2,270.3 million. 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.

Purchase in Lieu of Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007B

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

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

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

On March 26, 2008, TEC purchased in lieu of redemption $20 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007C.

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Sept. 30, 2013 to provide an opportunity to evaluate refinancing alternatives.

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Regulatory

9 Months Ended

Sep. 30, 2013

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.

Base Rates-Tampa Electric

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

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

On Sept. 6, 2013, TEC and all of the intervenors in its Tampa Electric division base rate proceeding filed with the FPSC a joint motion for the FPSC to approve a stipulation and settlement agreement, which would resolve all matters in Tampa Electric’s pending base rate proceeding.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved Tampa Electric’s base rate proceeding.

Storm Damage Cost Recovery

Tampa Electric is 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. Tampa Electric’s storm reserve was $55.4 million and $50.4 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively. Effective Nov. 1, 2013, Tampa Electric will cease accruing for this storm damage reserve as a settlement provision of the base rate proceeding mentioned above. 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 the level as of Oct. 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 Sept. 30, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.2	$	67.2
Other:
Cost-recovery clauses		14.4		42.9
Postretirement benefit asset		263.8		276.1
Deferred bond refinancing costs (2)		8.3		9.2
Environmental remediation		47.8		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5
Total other regulatory assets		344.2		385.7
Total regulatory assets		411.4		452.9
Less: Current portion		40.9		70.3
Long-term regulatory assets	$	370.5	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	13.7	$	14.6
Other:
Cost-recovery clauses		49.4		73.9
Transmission and delivery storm reserve		55.4		50.4
Deferred gain on property sales (3)		2.3		3.4
Other		1.3		1.0
Accumulated reserve - cost of removal		591.9		593.7
Total other regulatory liabilities		700.3		722.4
Total regulatory liabilities		714.0		737.0
Less: Current portion		81.3		105.6
Long-term regulatory liabilities	$	632.7	$	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)	Sept. 30, 2013		Dec. 31, 2012
Clause recoverable (1)	$	18.6	$	47.0
Components of rate base (2)		266.7		279.1
Regulatory tax assets (3)		67.2		67.2
Capital structure and other (3)		58.9		59.6
Total	$	411.4	$	452.9

(1) To be recovered through recovery mechanisms 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.

Base Rates-Tampa Electric

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

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

On Sept. 6, 2013, TEC and all of the intervenors in its Tampa Electric division base rate proceeding filed with the FPSC a joint motion for the FPSC to approve a stipulation and settlement agreement, which would resolve all matters in Tampa Electric’s pending base rate proceeding.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved Tampa Electric’s base rate proceeding.

Storm Damage Cost Recovery

Tampa Electric is 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. Tampa Electric’s storm reserve was $55.4 million and $50.4 million as of Sept. 30, 2013 and Dec. 31, 2012, respectively. Effective Nov. 1, 2013, Tampa Electric will cease accruing for this storm damage reserve as a settlement provision of the base rate proceeding mentioned above. 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 the level as of Oct. 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 Sept. 30, 2013 and Dec. 31, 2012 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Sept. 30, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.2	$	67.2
Other:
Cost-recovery clauses		14.4		42.9
Postretirement benefit asset		263.8		276.1
Deferred bond refinancing costs (2)		8.3		9.2
Environmental remediation		47.8		46.9
Competitive rate adjustment		4.2		4.1
Other		5.7		6.5
Total other regulatory assets		344.2		385.7
Total regulatory assets		411.4		452.9
Less: Current portion		40.9		70.3
Long-term regulatory assets	$	370.5	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	13.7	$	14.6
Other:
Cost-recovery clauses		49.4		73.9
Transmission and delivery storm reserve		55.4		50.4
Deferred gain on property sales (3)		2.3		3.4
Other		1.3		1.0
Accumulated reserve - cost of removal		591.9		593.7
Total other regulatory liabilities		700.3		722.4
Total regulatory liabilities		714.0		737.0
Less: Current portion		81.3		105.6
Long-term regulatory liabilities	$	632.7	$	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)	Sept. 30, 2013		Dec. 31, 2012
Clause recoverable (1)	$	18.6	$	47.0
Components of rate base (2)		266.7		279.1
Regulatory tax assets (3)		67.2		67.2
Capital structure and other (3)		58.9		59.6
Total	$	411.4	$	452.9

(1) To be recovered through recovery mechanisms 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.

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Consolidated Condensed Statements of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities
Net income	$ 155.7	$ 167.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	251.3	253.2
Deferred income taxes	89.1	115.2
Investment tax credits	(0.3)	(0.3)
Allowance for other funds used during construction	(4.3)	(1.6)
Non-cash stock compensation	10.2	8.5
(Loss) gain on sales of business/assets, pretax	(0.3)	14.5
Deferred recovery clauses	(3.8)	(3.7)
Asset impairment, pre-tax	0	17.4
Receivables, less allowance for uncollectibles	(64.4)	(47.3)
Inventories	3.1	7.9
Prepayments and other current assets	(4.2)	(3.1)
Taxes accrued	44.0	58.7
Interest accrued	22.2	23.6
Accounts payable	10.6	22.0
Other	(2.8)	(25.0)
Cash flows from operating activities	506.1	607.6
Cash flows from investing activities
Capital expenditures	(370.9)	(355.2)
Allowance for other funds used during construction	4.3	1.6
Net proceeds from sales of business/assets	0.4	7.4
Cash flows used in investing activities	(366.2)	(346.2)
Cash flows from financing activities
Dividends	(143.4)	(142.8)
Proceeds from the sale of common stock	7.4	3.2
Proceeds from long-term debt issuance	0	538.3
Repayment of long-term debt/Purchase in lieu of redemption	(51.6)	(469.2)
Dividends to noncontrolling interest	0	(0.3)
Cash flows used in financing activities	(187.6)	(70.8)
Net (decrease) increase in cash and cash equivalents	(47.7)	190.6
Cash and cash equivalents at beginning of the period	200.5	44.0
Cash and cash equivalents at beginning of the period	200.5
Cash and cash equivalents at end of the period	152.8	234.6
Cash and cash equivalents at end of the period	152.8
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	178.2	183.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	221.6	214.9
Deferred income taxes	57.7	92.6
Investment tax credits	(0.3)	(0.2)
Allowance for other funds used during construction	(4.3)	(1.6)
(Loss) gain on sales of business/assets, pretax	0	(0.2)
Deferred recovery clauses	(3.8)	(3.7)
Receivables, less allowance for uncollectibles	(61.5)	(64.0)
Inventories	(2.6)	5.8
Prepayments	(5.1)	(4.3)
Taxes accrued	89.6	78.2
Interest accrued	20.0	19.4
Accounts payable	6.2	22.9
Other	1.4	4.5
Cash flows from operating activities	497.1	548.2
Cash flows from investing activities
Capital expenditures	(353.1)	(318.3)
Allowance for other funds used during construction	4.3	1.6
Net proceeds from sale of assets	0	0.3
Cash flows used in investing activities	(348.8)	(316.4)
Cash flows from financing activities
Dividends	(147.6)	(149.5)
Proceeds from the sale of common stock	20.0	53.0
Proceeds from long-term debt issuance	0	538.3
Repayment of long-term debt/Purchase in lieu of redemption	(51.6)	(460.9)
Cash flows used in financing activities	(179.2)	(19.1)
Net (decrease) increase in cash and cash equivalents	(30.9)	212.7
Cash and cash equivalents at beginning of the period	45.2	13.9
Cash and cash equivalents at end of the period	$ 14.3	$ 226.6

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Earnings Per Share - Schedule of Earnings Per Share (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Basic earnings per share
Net income from continuing operations	$ 62.9	$ 90.2	$ 155.7	$ 200.4
Amount allocated to nonvested participating shareholders	(0.2)	(0.3)	(0.5)	(0.7)
Income before discontinued operations available to common shareholders - Basic	62.7	89.9	155.2	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	(0.1)	(46.2)	0	(32.8)
Amount allocated to nonvested participating shareholders	0	0.1	0	0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Basic	(0.1)	(46.1)	0	(32.7)
Net income attributable to TECO Energy	62.8	44.0	155.7	167.6
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.5)	(0.6)
Net income attributable to TECO Energy available to common shareholders - Basic	62.6	43.8	155.2	167.0
Average common shares outstanding - Basic	215.2	214.5	214.9	214.2
Earnings per share from continuing operations available to common shareholders - Basic	$ 0.29	$ 0.42	$ 0.72	$ 0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$ 0.00	$ (0.22)	$ 0.00	$ (0.15)
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$ 0.29	$ 0.20	$ 0.72	$ 0.78
Diluted earnings per share
Net income from continuing operations	62.9	90.2	155.7	200.4
Amount allocated to nonvested participating shareholders	(0.2)	(0.3)	(0.5)	(0.7)
Income before discontinued operations available to common shareholders - Diluted	62.7	89.9	155.2	199.7
(Loss) Income from discontinued operations attributable to TECO Energy, net	(0.1)	(46.2)	0	(32.8)
Amount allocated to nonvested participating shareholders	0	0.1	0	0.1
(Loss) Income from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	(0.1)	(46.1)	0	(32.7)
Net income attributable to TECO Energy	62.8	44.0	155.7	167.6
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.5)	(0.6)
Net income attributable to TECO Energy available to common shareholders - Diluted	$ 62.6	$ 43.8	$ 155.2	$ 167.0
Unadjusted average common shares outstanding - Diluted	215.2	214.5	214.9	214.2
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net	0.4	0.9	0.5	1.1
Average common shares outstanding - Diluted	215.6	215.4	215.4	215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$ 0.29	$ 0.42	$ 0.72	$ 0.93
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$ 0.00	$ (0.22)	$ 0.00	$ (0.15)
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$ 0.29	$ 0.20	$ 0.72	$ 0.78
Anti-dilutive shares	0	0	0	0.6

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Short-Term Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended		9 Months Ended					9 Months Ended			9 Months Ended			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]	Sep. 30, 2013 Revolving Credit Facility [Member]	Jun. 24, 2013 Revolving Credit Facility [Member]	Sep. 30, 2013 Revolving Credit Facility [Member] Maximum [Member]	Sep. 30, 2013 TECO ENERGY, INC. [Member]	Sep. 30, 2013 Tampa Electric Company [Member]	Dec. 31, 2012 Tampa Electric Company [Member]	Sep. 30, 2013 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Feb. 15, 2013 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2012 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Sep. 30, 2013 Tampa Electric Company [Member] Minimum [Member]	Sep. 30, 2013 Tampa Electric Company [Member] Maximum [Member]
Line of Credit Facility [Line Items]
Commitment fees, percentage			0.125%	0.25%					0.525%		0.525%			0.125%	0.25%
Outstanding borrowings	$ 0	$ 0							$ 0	$ 0	$ 0		$ 0
Credit facility	$ 675.0	$ 675.0				$ 200.0			$ 475.0	$ 475.0	$ 150.0	$ 150.0	$ 150.0
Debt instrument maturity date									Feb. 14, 2014
Basis spread on federal funds rate									0.50%		0.50%
Amended maturity date of credit facility	Oct. 25, 2016							Oct. 25, 2016	Oct. 25, 2016
Normal capitalization ratio					0.65		0.70
Mortgage bonds issued by certain regulated significant subsidiaries maximum principal amount					66.67%

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

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) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		TECO Coal			TECO Guatemala (2)			Other & Eliminations			TECO Energy
2013
Revenues - external	$	556.2	$	83.1	$	123.7		$	0.0		$	2.9		$	765.9
Sales to affiliates		0.2		0.3		0.0			0.0			(0.5	)		0.0
Total revenues		556.4		83.4		123.7			0.0			2.4			765.9
Depreciation and amortization		62.2		13.4		9.3			0.0			0.5			85.4
Total interest charges (1)		22.8		3.4		1.6			0.0			13.7			41.5
Internally allocated interest (1)		0.0		0.0		1.5			0.0			(1.5	)		0.0
Provision (benefit) for income taxes		42.7		3.4		(1.2	)		0.0			(7.3	)		37.6
Net income from continuing operations		68.7		5.4		(1.4	)		0.0			(9.8	)		62.9
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0			(0.1	)		(0.1	)
Net income attributable to TECO Energy	$	68.7	$	5.4	($	1.4	)	$	0.0		($	9.9	)	$	62.8
2012
Revenues - external	$	574.9	$	95.2	$	186.0		$	0.0		$	2.5		$	858.6
Sales to affiliates		0.3		0.0		0.0			0.0			(0.3	)		0.0
Total revenues		575.2		95.2		186.0			0.0			2.2			858.6
Depreciation and amortization		60.2		12.7		10.2			0.0			0.3			83.4
Total interest charges (1)		26.7		3.7		1.9			0.0			12.3			44.6
Internally allocated interest (1)		0.0		0.0		1.7			0.0			(1.7	)		0.0
Provision (benefit) for income taxes		45.7		4.4		6.0			0.0			(4.4	)		51.7
Net income from continuing operations		73.5		7.0		17.4			0.0			(7.7	)		90.2
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			(42.6	)		(3.6	)		(46.2	)
Net income attributable to TECO Energy	$	73.5	$	7.0	$	17.4		($	42.6	)	($	11.3	)	$	44.0
(millions) Nine months ended Sept. 30,
2013
Revenues - external	$	1,476.6	$	306.3	$	370.0		$	0.0		$	10.0		$	2,162.9
Sales to affiliates		0.7		0.8		0.0			0.0			(1.5	)		0.0
Total revenues		1,477.3		307.1		370.0			0.0			8.5			2,162.9
Depreciation and amortization		182.0		39.6		28.5			0.0			1.2			251.3
Total interest charges (1)		69.5		10.1		5.0			0.0			42.0			126.6
Internally allocated interest (1)		0.0		0.0		4.8			0.0			(4.8	)		0.0
Provision (benefit) for income taxes		94.0		17.1		(2.2	)		0.0			(19.9	)		89.0
Net income from continuing operations		151.1		27.1		2.3			0.0			(24.8	)		155.7
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0			0.0			0.0
Net income attributable to TECO Energy	$	151.1	$	27.1	$	2.3		$	0.0		($	24.8	)	$	155.7
2012
Revenues - external	$	1,527.8	$	298.9	$	474.1		$	0.0		$	7.4		$	2,308.2
Sales to affiliates		0.8		1.3		0.0			0.0			(2.1	)		0.0
Total revenues		1,528.6		300.2		474.1			0.0			5.3			2,308.2
Depreciation and amortization		177.2		37.7		31.0			0.0			1.0			246.9
Total interest charges (1)		86.2		12.6		5.5			0.0			36.5			140.8
Internally allocated interest (1)		0.0		0.0		5.2			0.0			(5.2	)		0.0
Provision (benefit) for income taxes		96.5		17.0		13.2			0.0			(13.5	)		113.2
Net income from continuing operations		156.9		27.0		39.4			0.0			(22.9	)		200.4
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			(28.6	)		(4.2	)		(32.8	)
Net income attributable to TECO Energy	$	156.9	$	27.0	$	39.4		($	28.6	)	($	27.1	)	$	167.6

Segment Information (1)
(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala (2)		Other & Eliminations			TECO Energy
At Sept. 30, 2013
Total assets	$	6,149.8	$	1,014.3	$	339.3	$	0.0	($	109.3	)	$	7,394.1
At Dec. 31, 2012
Total assets	$	6,042.3	$	1,009.9	$	356.6	$	164.9	($	238.8	)	$	7,334.9

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2012 through September 2013 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala, Inc. and certain charges at Parent that directly relate to TECO Guatemala, Inc. Revenues for TECO Guatemala, Inc. that were reclassified to discontinued operations were $31.5 million and $100.4 million for the three and nine months ended Sept. 30, 2012, respectively. There were no revenues reclassified for the three or nine months ended Sept. 30, 2013. See Note 15 for additional information.

Tampa Electric Company [Member]

Schedule of Segment Information

(millions) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2013
Revenues - external	$	556.3	$	83.1	$	0.0		$	639.4
Sales to affiliates		0.1		0.3		(0.4	)		0.0
Total revenues		556.4		83.4		(0.4	)		639.4
Depreciation and amortization		62.2		13.4		0.0			75.6
Total interest charges		22.8		3.4		0.0			26.2
Provision for income taxes		42.7		3.4		0.0			46.1
Net income	$	68.7	$	5.4	$	0.0		$	74.1
2012
Revenues - external	$	575.1	$	95.2	$	0.0		$	670.3
Sales to affiliates		0.1		0.0		(0.1	)		0.0
Total revenues		575.2		95.2		(0.1	)		670.3
Depreciation and amortization		60.2		12.7		0.0			72.9
Total interest charges		26.7		3.7		0.0			30.4
Provision for income taxes		45.7		4.4		0.0			50.1
Net income	$	73.5	$	7.0	$	0.0		$	80.5
Nine months ended Sept. 30,
2013
Revenues - external	$	1,477.0	$	306.3	$	0.0		$	1,783.3
Sales to affiliates		0.3		0.8		(1.1	)		0.0
Total revenues		1,477.3		307.1		(1.1	)		1,783.3
Depreciation and amortization		182.0		39.6		0.0			221.6
Total interest charges		69.5		10.1		0.0			79.6
Provision for income taxes		94.0		17.1		0.0			111.1
Net income	$	151.1	$	27.1	$	0.0		$	178.2
Total assets at Sept. 30, 2013	$	5,885.5	$	979.1	($	16.7	)	$	6,847.9
2012
Revenues - external	$	1,528.3	$	298.9	$	0.0		$	1,827.2
Sales to affiliates		0.3		1.3		(1.6	)		0.0
Total revenues		1,528.6		300.2		(1.6	)		1,827.2
Depreciation and amortization		177.2		37.7		0.0			214.9
Total interest charges		86.2		12.6		0.0			98.8
Provision for income taxes		96.5		17.0		0.0			113.5
Net income	$	156.9	$	27.0	$	0.0		$	183.9
Total assets at Dec. 31, 2012	$	5,760.4	$	970.9	$	13.3		$	6,744.6

XML

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	$ 0.2	$ 0.2
Total Swap Liabilities	6.7	15.2
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.2	0.2
Total Swap Liabilities	6.7	15.2
Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	6.3	14.3
Fair Value, Measurements, Recurring [Member] | Diesel Fuel Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0
Total Swap Liabilities	0.4	0.9
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] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [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] | Fair Value, Measurements, Recurring [Member] | Diesel Fuel Derivatives [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	0.2	0.2
Total Swap Liabilities	6.7	15.2
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	6.3	14.3
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Diesel Fuel Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0
Total Swap Liabilities	0.4	0.9
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] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [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] | Fair Value, Measurements, Recurring [Member] | Diesel Fuel Derivatives [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	0.1	0.2
Total Swap Liabilities	6.3	14.3
Tampa Electric Company [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	6.3	14.3
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	6.3	14.3
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] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [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	0.1	0.2
Total Swap Liabilities	6.3	14.3
Tampa Electric Company [Member] | Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	6.3	14.3
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] | Fair Value, Measurements, Recurring [Member] | Natural Gas Derivatives [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 - Gross Amounts of Derivatives and Their Related Offset Amounts (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	$ 1.2	$ 1.0
Derivative liabilities, Gross Amounts of Recognized (Liabilities	(7.7)	(16.0)
Derivative assets, Gross Amounts offset on the Balance Sheet	(1.0)	(0.8)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	1.0	0.8
Derivative assets, Net Amounts of Assets	0.2	0.2
Derivative assets, Net Amounts of Liabilities	(6.7)	(15.2)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	1.1	1.0
Derivative liabilities, Gross Amounts of Recognized (Liabilities	(7.3)	(15.1)
Derivative assets, Gross Amounts offset on the Balance Sheet	(1.0)	(0.8)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	1.0	0.8
Derivative assets, Net Amounts of Assets	0.1	0.2
Derivative assets, Net Amounts of Liabilities	$ (6.3)	$ (14.3)

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

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. Two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim. The Court recently denied plaintiffs’ motion for reconsideration of the ruling. PGS’s suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident remains pending, as does the Posen Construction counter-claim against PGS alleging negligence. In addition, the suit filed by the Posen Construction employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees are 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 recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected sometime in 2014.

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Sept. 30, 2013, TEC has estimated its ultimate financial liability to be $37.2 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.

Environmental Protection Agency Section 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station in Polk County, Florida with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter. TEC responded with the requested information on April 26, 2013 and has not received any response from the EPA on this matter.

Environmental Protection Agency Administrative Order

In December 2010, Clintwood Elkhorn Mining Company, a subsidiary of TECO Coal, received an Administrative Order from the EPA relating to the discharge of wastewater associated with inactive mining operations in Pike County, Kentucky. A consent agreement and final order with the EPA with respect to this matter became effective on July 23, 2013, the costs associated with which were not material to the financial results or financial position of TECO Energy.

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 Sept. 30, 2013 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2013		2014-2017		After (1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
TECO Coal
Fuel purchase related (2)	$	0.0	$	1.4	$	4.0	$	5.4	$	2.3
Other subsidiaries
Guaranty under sale agreement (3)		0.0		4.9		0.0		4.9		4.9
Fuel purchase/energy management (2)		0.0		10.0		94.3		104.3		0.4
Total	$	0.0	$	16.3	$	98.3	$	114.6	$	7.6

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After (1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
Tampa Electric (2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Sept. 30, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement of the TECO Guatemala equity interests.

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 Sept. 30, 2013, 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

9. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. Two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim. The Court recently denied plaintiffs’ motion for reconsideration of the ruling. PGS’s suit against Posen Construction in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident remains pending, as does the Posen Construction counter-claim against PGS alleging negligence. In addition, the suit filed by the Posen Construction employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction and the engineering company on the construction project, seeking damages for his injuries, also remains pending.

In addition, three former or inactive TEC employees are 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 recently the trial judge allowed the plaintiffs to seek punitive damages in connection with their case. A trial is expected sometime in 2014.

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 Sept. 30, 2013, TEC has estimated its ultimate financial liability to be $37.2 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.

Environmental Protection Agency Section 114 Letter

On Feb. 11, 2013, TEC received an information request from the EPA under Section 114(a) of the CAA seeking documents and other information concerning the compliance status of its sulfuric acid plant at its Polk Power Station in Polk County, Florida with the “New Source Review” requirements of the CAA. The request received by TEC appears to be part of a broader EPA national enforcement initiative focusing on sulfuric acid plants. TEC cannot predict at this time what the scope of this matter will ultimately be or the range of outcomes, and therefore it is not able to estimate the possible loss or range of loss, if any, with respect to this matter. TEC responded with the requested information on April 26, 2013 and has not received any response from the EPA on this matter.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Sept. 30, 2013 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2013		2014-2017		After(1) 2017		Total		Liabilities Recognized at Sept. 30, 2013
Tampa Electric (2)	$	0.8	$	0.0	$	0.7	$	1.5	$	0.3

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at Sept. 30, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Sept. 30, 2013, TEC was in compliance with all applicable financial covenants.

XML

Short-Term Debt

9 Months Ended

Sep. 30, 2013

Short-Term Debt

6. Short-Term Debt

At Sept. 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Sept. 30, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	1.5	$	675.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

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

At Sept. 30, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at Sept. 30, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

Amendment of TECO Energy/TECO Finance Credit Facility

On June 24, 2013, TECO Energy and TECO Finance entered into an Amendment No. 1 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011 (TECO Credit Facility). Pursuant to the TECO Credit Facility, TECO Finance may borrow up to $200 million from time to time on a revolving basis. The TECO Credit Facility matures on Oct. 25, 2016.

The Amendment was entered into to accommodate the acquisition of NMGI, as described in Note 16 herein, by (i) temporarily changing the total debt-to-total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closes, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changing the definition of Permitted Liens as defined in the TECO Credit Facility to permit the acquisition of a significant subsidiary that carries secured debt and making other changes matching the corresponding covenant in the Bridge Facility, as described in Note 16 herein. More specifically, the Amendment adds to the definition of Permitted Liens, (i) liens existing on any property or asset prior to the acquisition thereof by any significant subsidiary or existing on any property or assets of any person that becomes a significant subsidiary after the date of the Amendment prior to the time such person becomes a significant subsidiary, (ii) liens on assets subject to existing liens to secure additional obligations and (iii) mortgage bonds issued by certain regulated significant subsidiaries including NMGC in a principal amount not exceeding 66 2/3% of the value of such significant subsidiary’s plant, property and equipment. The Amendment also contains other minor changes to the TECO Credit Facility.

Tampa Electric Company [Member]

Short-Term Debt

6. Short-Term Debt

At Sept. 30, 2013 and Dec. 31, 2012, the following credit facilities and related borrowings existed:

Credit Facilities
	Sept. 30, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	1.5	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		0.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	0.0	$	1.5	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

At Sept. 30, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. There were no outstanding borrowings at Sept. 30, 2013 or Dec. 31, 2012.

Tampa Electric Company Accounts Receivable Facility

On Feb. 15, 2013, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 11 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 14, 2014, (ii) provides that TRC will pay program and liquidity fees, which will total 52.5 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin and (iv) makes other technical changes.

XML

Variable Interest Entities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 15.7	$ 25.8	$ 50.8	$ 85.2
Agreement's expiration	Dec. 31, 2012		Dec. 31, 2012
Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	15.7	25.8	50.8	85.2
Agreement's expiration	Dec. 31, 2012		Dec. 31, 2012
Power Purchase Agreements [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power		13.1		38.3
Power Purchase Agreements [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power		13.1		38.3
Power Purchase Agreements [Member] | Variable Interest Entities [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	6.5	19.0	16.4	62.3
Power Purchase Agreements [Member] | Variable Interest Entities [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 6.5	$ 19.0	$ 16.4	$ 62.3
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			370
Maximum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range			370

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2013

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 Sept. 30, 2013 and Dec. 31, 2012. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Sept. 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
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
Liabilities
Natural gas swaps	$	0.0	$	6.3	$	0.0	$	6.3
Diesel fuel swaps		0.0		0.4		0.0		0.4
Total	$	0.0	$	6.7	$	0.0	$	6.7

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

Natural gas and diesel fuel swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (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 Sept. 30, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Tampa Electric Company [Member]

Fair Value Measurements

12. 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 Sept. 30, 2013 and Dec. 31, 2012. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below, the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Sept. 30, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	0.1	$	0.0	$	0.1
Total	$	0.0	$	0.1	$	0.0	$	0.1
Liabilities
Natural gas swaps	$	0.0	$	6.3	$	0.0	$	6.3
Total	$	0.0	$	6.3	$	0.0	$	6.3

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

Natural gas swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 11).

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 Sept. 30, 2013, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

XML

Segment Information

9 Months Ended

Sep. 30, 2013

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) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		TECO Coal			TECO Guatemala (2)			Other & Eliminations			TECO Energy
2013
Revenues - external	$	556.2	$	83.1	$	123.7		$	0.0		$	2.9		$	765.9
Sales to affiliates		0.2		0.3		0.0			0.0			(0.5	)		0.0
Total revenues		556.4		83.4		123.7			0.0			2.4			765.9
Depreciation and amortization		62.2		13.4		9.3			0.0			0.5			85.4
Total interest charges (1)		22.8		3.4		1.6			0.0			13.7			41.5
Internally allocated interest (1)		0.0		0.0		1.5			0.0			(1.5	)		0.0
Provision (benefit) for income taxes		42.7		3.4		(1.2	)		0.0			(7.3	)		37.6
Net income from continuing operations		68.7		5.4		(1.4	)		0.0			(9.8	)		62.9
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0			(0.1	)		(0.1	)
Net income attributable to TECO Energy	$	68.7	$	5.4	($	1.4	)	$	0.0		($	9.9	)	$	62.8
2012
Revenues - external	$	574.9	$	95.2	$	186.0		$	0.0		$	2.5		$	858.6
Sales to affiliates		0.3		0.0		0.0			0.0			(0.3	)		0.0
Total revenues		575.2		95.2		186.0			0.0			2.2			858.6
Depreciation and amortization		60.2		12.7		10.2			0.0			0.3			83.4
Total interest charges (1)		26.7		3.7		1.9			0.0			12.3			44.6
Internally allocated interest (1)		0.0		0.0		1.7			0.0			(1.7	)		0.0
Provision (benefit) for income taxes		45.7		4.4		6.0			0.0			(4.4	)		51.7
Net income from continuing operations		73.5		7.0		17.4			0.0			(7.7	)		90.2
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			(42.6	)		(3.6	)		(46.2	)
Net income attributable to TECO Energy	$	73.5	$	7.0	$	17.4		($	42.6	)	($	11.3	)	$	44.0
(millions) Nine months ended Sept. 30,
2013
Revenues - external	$	1,476.6	$	306.3	$	370.0		$	0.0		$	10.0		$	2,162.9
Sales to affiliates		0.7		0.8		0.0			0.0			(1.5	)		0.0
Total revenues		1,477.3		307.1		370.0			0.0			8.5			2,162.9
Depreciation and amortization		182.0		39.6		28.5			0.0			1.2			251.3
Total interest charges (1)		69.5		10.1		5.0			0.0			42.0			126.6
Internally allocated interest (1)		0.0		0.0		4.8			0.0			(4.8	)		0.0
Provision (benefit) for income taxes		94.0		17.1		(2.2	)		0.0			(19.9	)		89.0
Net income from continuing operations		151.1		27.1		2.3			0.0			(24.8	)		155.7
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			0.0			0.0			0.0
Net income attributable to TECO Energy	$	151.1	$	27.1	$	2.3		$	0.0		($	24.8	)	$	155.7
2012
Revenues - external	$	1,527.8	$	298.9	$	474.1		$	0.0		$	7.4		$	2,308.2
Sales to affiliates		0.8		1.3		0.0			0.0			(2.1	)		0.0
Total revenues		1,528.6		300.2		474.1			0.0			5.3			2,308.2
Depreciation and amortization		177.2		37.7		31.0			0.0			1.0			246.9
Total interest charges (1)		86.2		12.6		5.5			0.0			36.5			140.8
Internally allocated interest (1)		0.0		0.0		5.2			0.0			(5.2	)		0.0
Provision (benefit) for income taxes		96.5		17.0		13.2			0.0			(13.5	)		113.2
Net income from continuing operations		156.9		27.0		39.4			0.0			(22.9	)		200.4
Loss from discontinued operations attributable to TECO Energy		0.0		0.0		0.0			(28.6	)		(4.2	)		(32.8	)
Net income attributable to TECO Energy	$	156.9	$	27.0	$	39.4		($	28.6	)	($	27.1	)	$	167.6

Segment Information (1)
(millions)	Tampa Electric		Peoples Gas		TECO Coal		TECO Guatemala (2)		Other & Eliminations			TECO Energy
At Sept. 30, 2013
Total assets	$	6,149.8	$	1,014.3	$	339.3	$	0.0	($	109.3	)	$	7,394.1
At Dec. 31, 2012
Total assets	$	6,042.3	$	1,009.9	$	356.6	$	164.9	($	238.8	)	$	7,334.9

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2012 through September 2013 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala, Inc. and certain charges at Parent that directly relate to TECO Guatemala, Inc. Revenues for TECO Guatemala, Inc. that were reclassified to discontinued operations were $31.5 million and $100.4 million for the three and nine months ended Sept. 30, 2012, respectively. There were no revenues reclassified for the three or nine months ended Sept. 30, 2013. See Note 15 for additional information.

Tampa Electric Company [Member]

Segment Information

10. Segment Information

(millions) Three months ended Sept. 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2013
Revenues - external	$	556.3	$	83.1	$	0.0		$	639.4
Sales to affiliates		0.1		0.3		(0.4	)		0.0
Total revenues		556.4		83.4		(0.4	)		639.4
Depreciation and amortization		62.2		13.4		0.0			75.6
Total interest charges		22.8		3.4		0.0			26.2
Provision for income taxes		42.7		3.4		0.0			46.1
Net income	$	68.7	$	5.4	$	0.0		$	74.1
2012
Revenues - external	$	575.1	$	95.2	$	0.0		$	670.3
Sales to affiliates		0.1		0.0		(0.1	)		0.0
Total revenues		575.2		95.2		(0.1	)		670.3
Depreciation and amortization		60.2		12.7		0.0			72.9
Total interest charges		26.7		3.7		0.0			30.4
Provision for income taxes		45.7		4.4		0.0			50.1
Net income	$	73.5	$	7.0	$	0.0		$	80.5
Nine months ended Sept. 30,
2013
Revenues - external	$	1,477.0	$	306.3	$	0.0		$	1,783.3
Sales to affiliates		0.3		0.8		(1.1	)		0.0
Total revenues		1,477.3		307.1		(1.1	)		1,783.3
Depreciation and amortization		182.0		39.6		0.0			221.6
Total interest charges		69.5		10.1		0.0			79.6
Provision for income taxes		94.0		17.1		0.0			111.1
Net income	$	151.1	$	27.1	$	0.0		$	178.2
Total assets at Sept. 30, 2013	$	5,885.5	$	979.1	($	16.7	)	$	6,847.9
2012
Revenues - external	$	1,528.3	$	298.9	$	0.0		$	1,827.2
Sales to affiliates		0.3		1.3		(1.6	)		0.0
Total revenues		1,528.6		300.2		(1.6	)		1,827.2
Depreciation and amortization		177.2		37.7		0.0			214.9
Total interest charges		86.2		12.6		0.0			98.8
Provision for income taxes		96.5		17.0		0.0			113.5
Net income	$	156.9	$	27.0	$	0.0		$	183.9
Total assets at Dec. 31, 2012	$	5,760.4	$	970.9	$	13.3		$	6,744.6

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 25, 2013
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
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		217,301,601
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC CO
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

Accounting for Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2013

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 cash flow 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 has designated all derivatives as cash flow hedges.

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 Sept. 30, 2013, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at Sept. 30, 2013 and Dec. 31, 2012:

Total Derivatives(1)
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.2	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.2	$	0.2
Current liabilities	$	5.2	$	14.6
Long-term liabilities		1.5		0.6
Total liabilities	$	6.7	$	15.2

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

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Sept. 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Sept. 30, 2013
Description
Derivative assets	$	1.2		$	(1.0	)	$	0.2
Derivative liabilities	$	(7.7	)	$	1.0		$	(6.7	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

The following table presents the derivative hedges of diesel fuel contracts at Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.0
Current liabilities	$	0.3	$	0.5
Long-term liabilities		0.1		0.4
Total liabilities	$	0.4	$	0.9

The following table presents the derivative hedges of natural gas contracts at Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.1	$	0.2
Current liabilities	$	4.9	$	14.1
Long-term liabilities		1.4		0.2
Total liabilities	$	6.3	$	14.3

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at Sept. 30, 2013 is a net loss of $8.1 million after tax and accumulated amortization. This compares to a net loss of $9.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at Sept. 30, 2013 and Dec. 31, 2012:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.3
Long-term	Derivative assets		0.0	Derivative liabilities		0.1
Natural gas derivatives:
Current	Derivative assets		0.1	Derivative liabilities		4.9
Long-term	Derivative assets		0.0	Derivative liabilities		1.4
Total derivatives designated as hedging instruments		$	0.2		$	6.7

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

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sept. 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.1	Regulatory assets	$	4.9
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.4
Total		$	0.1		$	6.3

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

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

Based on the fair value of the instruments at Sept. 30, 2013, net pretax losses of $4.8 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 and nine months ended Sept. 30:

For the three months ended Sept. 30:	Amount of			Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.7	Mining related costs		0.1
Total	$	0.7		($	0.1	)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		1.6	Mining related costs		0.1
Total	$	1.6		($	0.1	)

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

For the nine months ended Sept. 30:	Amount of				Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)				Effective Portion (1)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.7	)
Commodity contracts:
Diesel fuel derivatives		0.4		Mining related costs		0.0
Total	$	0.4			($	0.7	)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.6	)
Commodity contracts:
Diesel fuel derivatives		0.4		Mining related costs		0.3
Total	($	4.5	)		($	0.3	)

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

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the nine months ended Sept. 30, 2013 and 2012, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the nine months ended Sept. 30:

(millions)	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2013
Interest rate swaps	$	0.0		$	0.0		($	0.7	)
Diesel fuel derivatives		(0.3	)		0.4			0.0
Total	($	0.3	)	$	0.4		($	0.7	)
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.6	)
Diesel fuel derivatives		(0.2	)		0.4			0.3
Total	($	0.2	)	($	4.5	)	($	0.3	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2015 for financial natural gas and Dec. 31, 2014 for financial diesel fuel contracts. The following table presents by commodity type the company’s derivative volumes that, as of Sept. 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2013		0.0		1.8		0.0		9.8
2014		0.0		2.0		0.0		35.0
2015		0.0		0.0		0.0		5.9
Total		0.0		3.8		0.0		50.7

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 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 Sept. 30, 2013, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio are rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

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

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

The table below presents the fair value of the overall contractual contingent liability positions for the company’s derivative activity at Sept. 30, 2013:

Contingent Features
(millions) At Sept. 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	6.6	)	($	6.6	)	$	0.0

Tampa Electric Company [Member]

Accounting for Derivative Instruments and Hedging Activities

11. 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 cash flow 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 has designated all derivatives as cash flow hedges.

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 Sept. 30, 2013, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at Sept. 30, 2013 and Dec. 31, 2012 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Sept. 30, 2013		Dec. 31, 2012
Current assets	$	0.1	$	0.0
Long-term assets		0.0		0.2
Total assets	$	0.1	$	0.2
Current liabilities (1)	$	4.9	$	14.1
Long-term liabilities		1.4		0.2
Total liabilities	$	6.3	$	14.3

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

The ending balance in AOCI related to previously settled interest rate swaps at Sept. 30, 2013 is a net loss of $8.0 million after tax and accumulated amortization. This compares to a net loss of $8.7 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Sept. 30, 2013 and Dec. 31, 2012. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Sept. 30, 2013
Description
Derivative assets	$	1.1		$	(1.0	)	$	0.1
Derivative liabilities	$	(7.3	)	$	1.0		$	(6.3	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheet as of Sept. 30, 2013 and Dec. 31, 2012:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Sept. 30, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	0.1	Regulatory assets	$	4.9
Long-term	Regulatory liabilities		0.0	Regulatory assets		1.4
Total		$	0.1		$	6.3

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

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

Based on the fair value of the instruments at Sept. 30, 2013, net pretax losses of $4.8 million are expected to be reclassified from regulatory assets to the Consolidated Condensed Statements of Income within the next 12 months.

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

For the three months ended Sept. 30:	Amount of			Amount of
(millions)	Gain/(Loss) on Derivatives Recognized in OCI		Location of Gain/(Loss) Reclassified From AOCI Into Income	Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)			Effective Portion (1)
2013
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)
2012
Interest rate contracts	$	0.0	Interest expense	($	0.2	)
Total	$	0.0		($	0.2	)

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

For the nine months ended Sept. 30:	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)
2013
Interest rate contracts	$	0.0		Interest expense	($	0.7	)
Total	$	0.0			($	0.7	)
2012
Interest rate contracts	($	4.9	)	Interest expense	($	0.6	)
Total	($	4.9	)		($	0.6	)

(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 nine months ended Sept. 30:

(millions)	Fair Value Asset/ (Liability)		Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2013
Interest rate swaps	$	0.0	$	0.0		($	0.7	)
Total	$	0.0	$	0.0		($	0.7	)
2012
Interest rate swaps	$	0.0	($	4.9	)	($	0.6	)
Total	$	0.0	($	4.9	)	($	0.6	)

(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 and nine months ended Sept. 30, 2013 and 2012, 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, 2015 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of Sept. 30, 2013, are expected to settle during the 2013, 2014 and 2015 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2013		0.0		9.8
2014		0.0		35.0
2015		0.0		5.9
Total		0.0		50.7

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 Sept. 30, 2013, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio are rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

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

The table below presents the fair value of the overall contractual contingent liability positions for TEC’s derivative activity at Sept. 30, 2013:

Contingent Features
(millions) Sept. 30, 2013	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	6.3	)	($	6.3	)	$	0.0

XML

Accounting for Derivative Instruments and Hedging Activities - Energy Related Derivatives (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Current	$ 81.3	$ 105.6
Long-term	632.7	631.4
Regulatory liabilities	714.0	737.0
Current regulatory assets	40.9	70.3
Long-term regulatory assets	370.5	382.6
Regulatory assets	411.4	452.9
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current	81.3	105.6
Long-term	632.7	631.4
Regulatory liabilities	714.0	737.0
Current regulatory assets	40.9	70.3
Long-term regulatory assets	370.5	382.6
Regulatory assets	411.4	452.9
Energy Related Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current	0.1	0
Long-term	0	0.2
Regulatory liabilities	0.1	0.2
Current regulatory assets	4.9	14.1
Long-term regulatory assets	1.4	0.2
Regulatory assets	6.3	14.3
Energy Related Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current	0.1	0
Long-term	0	0.2
Regulatory liabilities	0.1	0.2
Current regulatory assets	4.9	14.1
Long-term regulatory assets	1.4	0.2
Regulatory assets	$ 6.3	$ 14.3

XML

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Hedging Instruments (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Jan. 10, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Current assets	$ 0.2		$ 0
Long-term derivative assets	0		0.2
Total assets	0.2		0.2
Current liabilities	5.2		14.6
Long-term derivative liabilities	1.5		0.6
Total liabilities	6.7		15.2
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1		0
Long-term derivative assets	0		0
Total assets	0.1		0
Current liabilities	0.3		0.5
Long-term derivative liabilities	0.1		0.4
Total liabilities	0.4		0.9
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1		0
Long-term derivative assets	0		0.2
Total assets	0.1		0.2
Current liabilities	4.9		14.1
Long-term derivative liabilities	1.4		0.2
Total liabilities	6.3		14.3
Derivatives Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Total assets	0.2		0.2
Total liabilities		6.7	15.2
Derivatives Designated as Hedging Instruments [Member] | Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1		0
Long-term derivative assets	0		0
Current liabilities		0.3	0.5
Long-term derivative liabilities		0.1	0.4
Derivatives Designated as Hedging Instruments [Member] | Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1		0
Long-term derivative assets	0		0.2
Current liabilities		4.9	14.1
Long-term derivative liabilities		$ 1.4	$ 0.2