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 June 30, 2014

OR

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

For the transition period from                      to                     

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

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

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

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

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

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

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

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

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

The number of shares of TECO Energy, Inc.’s common stock outstanding as of July 28, 2014 was 233,407,893 . As of July 28, 2014, there were 10 shares of Tampa Electric Company’s common stock issued and outstanding, all of which were held, beneficially and of record, by TECO Energy, Inc.

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

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

Page 2 of 69

Index to Exhibits appears on page 70

DEFINITIONS

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

Term	Meaning
ABS	asset-backed security
ADR	American depository receipt
AFUDC	allowance for funds used during construction
AFUDC - debt	debt component of allowance for funds used during construction
AFUDC - equity	equity component of allowance for funds used during construction
AMT	alternative minimum tax
AOCI	accumulated other comprehensive income
APBO	accumulated postretirement benefit obligation
ARO	asset retirement obligation
BACT	Best Available Control Technology
BTU	British Thermal Unit
CAA	Federal Clean Air Act
CAIR	Clean Air Interstate Rule
capacity clause	capacity cost-recovery clause, as established by the FPSC
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980
CCRs	coal combustion residuals
CES	Continental Energy Systems
CGESJ	Central Generadora Eléctrica San José, Limitada, owner of the San José Power Station in Guatemala
CMMA	Cardno Marshall Miller & Associates
CMBS	commercial mortgage-backed securities
CMO	collateralized mortgage obligation
CNG	compressed natural gas
CPI	consumer price index
CSAPR	Cross State Air Pollution Rule
CO2	carbon dioxide
CT	combustion turbine
DECA II	Distribución Eléctrica Centro Americana, II, S.A.
DOE	U.S. Department of Energy
DR-CAFTA	Dominican Republic Central America – United States Free Trade Agreement
ECRC	environmental cost recovery clause
EEGSA	Empresa Eléctrica de Guatemala, S.A., the largest private distribution company in Central America
EEI	Edison Electric Institute
EGWP	Employee Group Waiver Plan
EPA	U.S. Environmental Protection Agency
EPS	earnings per share
ERISA	Employee Retirement Income Security Act
EROA	expected return on plan assets
ERP	enterprise resource planning
FASB	Financial Accounting Standards Board
FDEP	Florida Department of Environmental Protection
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company
FPSC	Florida Public Service Commission
fuel clause	fuel and purchased power cost-recovery clause, as established by the FPSC
GAAP	generally accepted accounting principles
GHG	greenhouse gas(es)
HCIDA	Hillsborough County Industrial Development Authority
HPP	Hardee Power Partners

2

ICSID	International Centre for the Settlement of Investment Disputes
IFRS	International Financial Reporting Standards
IGCC	integrated gasification combined-cycle
IOU	investor owned utility
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISO	independent system operator
ITCs	investment tax credits
KW	Kilowatt(s)
KWH	kilowatt-hour(s)
LDS	local distribution companies
LIBOR	London Interbank Offered Rate
MAP-21	Moving Ahead for Progress in the 21st Century Act
MBS	mortgage-backed securities
MD&A	Management’s Discussion and Analysis
Met	metallurgical
MMA	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
MMBTU	one million British Thermal Units
MRV	market-related value
MSHA	Mine Safety and Health Administration
MW	megawatt(s)
MWH	megawatt-hour(s)
NAESB	North American Energy Standards Board
NAV	net asset value
NERC	North American Electric Reliability Corporation
NMGC	New Mexico Gas Company, Inc., the principal subsidiary of NMGI
NMGI	New Mexico Gas Intermediate, Inc.
NMPRC	New Mexico Public Regulation Commission
NOL	net operating loss
Note	Note      to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OATT	open access transmission tariff
OCI	other comprehensive income
OTC	over-the-counter
OTTI	other than temporary impairment
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PCIDA	Polk County Industrial Development Authority
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PM	particulate matter
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
REIT	real estate investment trust
REMIC	real estate mortgage investment conduit
RFP	request for proposal

3

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

4

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 June 30, 2014 and Dec. 31, 2013, and the results of their operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three month and six month periods ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. References should be made to the explanatory notes affecting the consolidated financial statements contained in TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 and to the notes on pages 12 through 30 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, June 30, 2014 and Dec. 31, 2013		6-7
Consolidated Condensed Statements of Income for the three month and six month periods ended June 30, 2014		8-9
Consolidated Condensed Statements of Comprehensive Income for the three month and six month periods ended June 30, 2014		10
Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2014 and 2013		11
Notes to Consolidated Condensed Financial Statements		12-30

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.

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets (millions)	Jun 30, 2014			Dec 31, 2013
Current assets
Cash and cash equivalents	$	167.0		$	185.2
Receivables, less allowance for uncollectibles of $3.8 and $4.7 at June 30, 2014 and Dec. 31, 2013, respectively		323.8			287.2
Inventories, at average cost
Fuel		137.4			118.7
Materials and supplies		83.4			85.9
Derivative assets		8.2			9.7
Regulatory assets		33.7			34.3
Deferred income taxes		87.7			100.3
Prepayments and other current assets		47.5			34.9
Income tax receivables		0.8			1.5
Total current assets		889.5			857.7
Property, plant and equipment
Utility plant in service
Electric		6,941.7			6,934.0
Gas		1,324.4			1,308.3
Construction work in progress		494.9			386.7
Other property		441.5			448.3
Property, plant and equipment, at original costs		9,202.5			9,077.3
Accumulated depreciation		(2,878.4	)		(2,907.2	)
Total property, plant and equipment, net		6,324.1			6,170.1
Other assets
Regulatory assets		283.9			293.1
Derivative assets		0.5			0.3
Deferred charges and other assets		122.8			126.8
Total other assets		407.2			420.2
Total assets	$	7,620.8		$	7,448.0

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

6

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capital (millions)	Jun 30, 2014			Dec 31, 2013
Current liabilities
Long-term debt due within one year	$	274.5		$	83.3
Notes payable		0.0			84.0
Accounts payable		232.3			261.7
Customer deposits		167.5			164.5
Regulatory liabilities		65.7			85.8
Derivative liabilities		0.2			0.1
Interest accrued		34.4			31.9
Taxes accrued		68.2			34.6
Other		18.4			19.5
Total current liabilities		861.2			765.4
Other liabilities
Deferred income taxes		497.4			444.0
Investment tax credits		9.2			9.4
Regulatory liabilities		621.4			631.4
Derivative liabilities		0.1			0.2
Deferred credits and other liabilities		422.0			426.1
Long-term debt, less amount due within one year		2,863.1			2,837.8
Total other liabilities		4,413.2			4,348.9
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 217.8 million and 217.3 million shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively)		217.8			217.3
Additional paid in capital		1,587.8			1,581.3
Retained earnings		560.9			548.3
Accumulated other comprehensive loss		(20.1	)		(13.2	)
Total capital		2,346.4			2,333.7
Total liabilities and capital	$	7,620.8		$	7,448.0

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

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Jun 30,
(millions, except per share amounts)		2014			2013
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $27.8 in 2014 and $26.7 in 2013)		$	603.6		$	604.0
Unregulated			122.7			131.9
Total revenues			726.3			735.9
Expenses
Regulated operations and maintenance
Fuel			169.7			174.5
Purchased power			19.9			20.5
Cost of natural gas sold			29.1			40.7
Other			126.8			129.6
Operation and maintenance other expense
Mining related costs			103.5			110.2
Other			4.8			3.4
Depreciation and amortization			84.2			83.9
Taxes, other than income			55.1			53.6
Total expenses			593.1			616.4
Income from continuing operations			133.2			119.5
Other income
Allowance for other funds used during construction			2.0			1.4
Other income			(0.2	)		1.6
Total other income			1.8			3.0
Interest charges
Interest expense			42.9			43.5
Allowance for borrowed funds used during construction			(0.7	)		(0.8	)
Total interest charges			42.2			42.7
Income from continuing operations before provision for income taxes			92.8			79.8
Provision for income taxes			34.4			28.2
Net income from continuing operations			58.4			51.6
Discontinued operations
Loss from discontinued operations			0.0			(0.2	)
Provision for income taxes			0.0			0.0
Loss from discontinued operations, net			0.0			(0.2	)
Net income		$	58.4		$	51.4
Average common shares outstanding	– Basic		215.4			215.0
	– Diluted		215.9			215.5
Earnings per share from continuing operations	– Basic	$	0.27		$	0.24
	– Diluted	$	0.27		$	0.24
Earnings per share from discontinued operations	– Basic	$	0.00		$	0.00
	– Diluted	$	0.00		$	0.00
Earnings per share	– Basic	$	0.27		$	0.24
	– Diluted	$	0.27		$	0.24
Dividends paid per common share outstanding		$	0.22		$	0.22

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

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Six months ended Jun 30,
(millions, except per share amounts)		2014			2013
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $55.0 in 2014 and $52.1 in 2013)		$	1,179.3		$	1,143.1
Unregulated			231.1			253.9
Total revenues			1,410.4			1,397.0
Expenses
Regulated operations and maintenance
Fuel			319.3			314.5
Purchased power			38.1			35.1
Cost of natural gas sold			76.2			90.2
Other			247.4			250.4
Operation and maintenance other expense
Mining related costs			194.7			205.7
Other			7.9			4.7
Depreciation and amortization			169.1			165.9
Taxes, other than income			111.4			106.9
Total expenses			1,164.1			1,173.4
Income from continuing operations			246.3			223.6
Other income
Allowance for other funds used during construction			4.4			2.5
Other income			(0.9	)		3.2
Total other income			3.5			5.7
Interest charges
Interest expense			85.4			86.5
Allowance for borrowed funds used during construction			(2.1	)		(1.4	)
Total interest charges			83.3			85.1
Income from continuing operations before provision for income taxes			166.5			144.2
Provision for income taxes			61.1			51.4
Net income from continuing operations			105.4			92.8
Discontinued operations
Income from discontinued operations			5.0			0.2
Provision for income taxes			1.9			0.1
Income from discontinued operations, net			3.1			0.1
Net income		$	108.5		$	92.9
Average common shares outstanding	– Basic		215.3			214.8
	– Diluted		215.8			215.3
Earnings per share from continuing operations	– Basic	$	0.49		$	0.43
	– Diluted	$	0.49		$	0.43
Earnings per share from discontinued operations	– Basic	$	0.01		$	0.00
	– Diluted	$	0.01		$	0.00
Earnings per share	– Basic	$	0.50		$	0.43
	– Diluted	$	0.50		$	0.43
Dividends paid per common share outstanding		$	0.44		$	0.44

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

9

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Jun 30,					Six months ended Jun 30,
(millions)	2014		2013			2014			2013
Net income	$	58.4	$	51.4		$	108.5		$	92.9
Other comprehensive income, net of tax
Net unrealized gains (losses) on cash flow hedges		0.1		(0.1	)		0.3			0.3
Amortization of unrecognized benefit costs		0.5		0.7			1.0			1.4
Increase in unrecognized postemployment costs		0.0		0.0			(8.2	)		0.0
Other comprehensive income (loss), net of tax		0.6		0.6			(6.9	)		1.7
Comprehensive income	$	59.0	$	52.0		$	101.6		$	94.6

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

10

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended Jun 30,
(millions)	2014			2013
Cash flows from operating activities
Net income	$	108.5		$	92.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		169.1			165.9
Deferred income taxes		62.0			52.1
Investment tax credits		(0.2	)		(0.2	)
Allowance for other funds used during construction		(4.4	)		(2.5	)
Non-cash stock compensation		7.1			6.9
Gain on sales of business/assets, pretax		(0.1	)		(0.2	)
Deferred recovery clauses		(14.4	)		(5.9	)
Receivables, less allowance for uncollectibles		(36.6	)		(38.5	)
Inventories		(16.2	)		(19.7	)
Prepayments and other current assets		(2.1	)		(4.3	)
Taxes accrued		34.3			28.1
Interest accrued		2.5			2.0
Accounts payable		(36.0	)		13.0
Other		(12.5	)		(1.8	)
Cash flows from operating activities		261.0			287.8
Cash flows from investing activities
Capital expenditures		(320.3	)		(249.6	)
Allowance for other funds used during construction		4.4			2.5
Net proceeds from sales of business/assets		0.3			0.3
Cash flows used in investing activities		(315.6	)		(246.8	)
Cash flows from financing activities
Dividends		(95.9	)		(95.6	)
Proceeds from the sale of common stock		3.0			7.4
Proceeds from long-term debt issuance		296.6			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(83.3	)		0.0
Net decrease in short-term debt		(84.0	)		0.0
Cash flows from (used) in financing activities		36.4			(88.2	)
Net decrease in cash and cash equivalents		(18.2	)		(47.2	)
Cash and cash equivalents at beginning of the period		185.2			200.5
Cash and cash equivalents at end of the period	$	167.0		$	153.3
Supplemental disclosure of non-cash activities
Capital expenditures accrued-excluded above	$	8.6		$	(3.1	)

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

11

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

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 June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three months and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

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.

12

2. New Accounting Pronouncements

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for the company beginning in 2015.

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for the company beginning in fiscal 2017 and allows for either full retrospective adoption or modified retrospective adoption. The company is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

3. Regulatory

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

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both June 30, 2014 and Dec. 31, 2013.

Regulatory Assets and Liabilities

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

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

13

Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun 30, 2014		Dec 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	68.1	$	67.4
Other:
Cost-recovery clauses		1.8		6.1
Postretirement benefit asset		177.6		182.7
Deferred bond refinancing costs (2)		7.6		8.0
Environmental remediation		52.0		51.4
Competitive rate adjustment		2.8		4.1
Other		7.7		7.7
Total other regulatory assets		249.5		260.0
Total regulatory assets		317.6		327.4
Less: Current portion		33.7		34.3
Long-term regulatory assets	$	283.9	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.6	$	9.8
Other:
Cost-recovery clauses		34.8		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.4		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		588.4		594.0
Total other regulatory liabilities		681.5		707.4
Total regulatory liabilities		687.1		717.2
Less: Current portion		65.7		85.8
Long-term regulatory liabilities	$	621.4	$	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	Jun 30,		Dec 31,
(millions)	2014		2013
Clause recoverable (1)	$	4.6	$	10.2
Components of rate base (2)		180.7		185.6
Regulatory tax assets (3)		68.1		67.4
Capital structure and other (3)		64.2		64.2
Total	$	317.6	$	327.4

(1) To be recovered through cost-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.

14

4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for years 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2010 and forward.

The effective tax rate increased to 36.71% for the six months ended June 30, 2014 from 35.64% for the same period in 2013.

5. Employee Postretirement Benefits

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Jun 30,	2014			2013			2014			2013
Components of net periodic benefit expense
Service cost	$	4.2		$	4.3		$	0.6		$	0.5
Interest cost on projected benefit obligations		8.2			7.2			2.6			2.4
Expected return on assets		(10.4	)		(9.5	)		0.0			0.0
Amortization of:
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		(0.1	)
Actuarial loss		3.5			5.3			0.1			0.2
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	7.2		$	3.2		$	3.0
Six months ended Jun 30,
Components of net periodic benefit expense
Service cost	$	8.3		$	9.1		$	1.2		$	1.2
Interest cost on projected benefit obligations		16.4			14.4			5.2			4.7
Expected return on assets		(20.7	)		(19.2	)		0.0			0.0
Amortization of:
Prior service (benefit) cost		(0.2	)		(0.2	)		(0.1	)		(0.2	)
Actuarial loss		6.7			10.3			0.1			0.5
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income	$	10.5		$	14.4		$	6.4		$	6.2

For the 2014 plan year, TECO Energy is using an assumed long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $26.5 million to its pension plan for the six months ended June 30, 2014.

For the three and six months ended June 30, 2014, TECO Energy and its subsidiaries reclassed $0.7 million and $1.3 million pretax, respectively, of unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and six months ended June 30, 2014, TEC reclassed $2.7 million and $5.2 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

15

6. Short-Term Debt

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Jun 30, 2014						Dec 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		78.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	0.7	$	675.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

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

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

At June 30, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at June 30, 2014.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

16

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2014, total long-term debt had a carrying amount of $3,137.6 million and an estimated fair market value of $3,469.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the Notes). The Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

17

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and six months ended June 30, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Jun 30,									Six months ended Jun 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2014
Unrealized gain on cash flow hedges	$	0.1		$	0.0		$	0.1		$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.1			(0.1	)		0.0			0.5			(0.2	)		0.3
Gain on cash flow hedges		0.2			(0.1	)		0.1			0.5			(0.2	)		0.3
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5			1.6			(0.6	)		1.0
Increase in unrecognized postemployment costs(3)		0.0			0.0			0.0			(12.9	)		4.7			(8.2	)
Total other comprehensive income (loss)	$	1.0		($	0.4	)	$	0.6		($	10.8	)	$	3.9		($	6.9	)
2013
Unrealized loss on cash flow hedges	($	0.7	)	$	0.3		($	0.4	)	($	0.4	)	$	0.2		($	0.2	)
Reclassification from AOCI to net income (1)		0.5			(0.2	)		0.3			0.8			(0.3	)		0.5
(Loss) Gain on cash flow hedges		(0.2	)		0.1			(0.1	)		0.4			(0.1	)		0.3
Amortization of unrecognized benefit costs (2)		1.1			(0.4	)		0.7			2.2			(0.8	)		1.4
Total other comprehensive income	$	0.9		($	0.3	)	$	0.6		$	2.6		($	0.9	)	$	1.7

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

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

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

Accumulated Other Comprehensive Loss
(millions)	Jun 30, 2014			Dec 31, 2013
Unrecognized pension loss and prior service credit (1)	($	19.7	)	($	20.5	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		7.1			15.1
Net unrealized losses from cash flow hedges (3)		(7.5	)		(7.8	)
Total accumulated other comprehensive loss	($	20.1	)	($	13.2	)

(1) Net of tax benefit of $12.1 million and $12.6 million as of June 30, 2014 and Dec. 31, 2013, respectively.

(2) Net of tax expense of $4.4 million and $9.1 million as of June 30, 2014 and Dec. 31, 2013, respectively.

(3) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

18

9. Earnings Per Share

	For the three months ended Jun 30,						For the six months ended Jun 30,
(millions, except per share amounts)	2014			2013			2014			2013
Basic earnings per share
Net income from continuing operations	$	58.4		$	51.6		$	105.4		$	92.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Income before discontinued operations available to common shareholders - Basic	$	58.2		$	51.4		$	105.0		$	92.5
Income (Loss) from discontinued operations, net	$	0.0		($	0.2	)	$	3.1		$	0.1
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (Loss) from discontinued operations available to common shareholders - Basic	$	0.0		($	0.2	)	$	3.1		$	0.1
Net income	$	58.4		$	51.4		$	108.5		$	92.9
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Net income available to common shareholders - Basic	$	58.2		$	51.2		$	108.1		$	92.6
Average common shares outstanding - Basic		215.4			215.0			215.3			214.8
Earnings per share from continuing operations available to common shareholders - Basic	$	0.27		$	0.24		$	0.49		$	0.43
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.00		$	0.00		$	0.01		$	0.00
Earnings per share available to common shareholders - Basic	$	0.27		$	0.24		$	0.50		$	0.43
Diluted earnings per share
Net income from continuing operations	$	58.4		$	51.6		$	105.4		$	92.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Income before discontinued operations available to common shareholders - Diluted	$	58.2		$	51.4		$	105.0		$	92.5
Income (Loss) from discontinued operations, net	$	0.0		($	0.2	)	$	3.1		$	0.1
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (Loss) from discontinued operations available to common shareholders - Diluted	$	0.0		($	0.2	)	$	3.1		$	0.1
Net income	$	58.4		$	51.4		$	108.5		$	92.9
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Net income available to common shareholders - Diluted	$	58.2		$	51.2		$	108.1		$	92.6
Unadjusted average common shares outstanding - Diluted		215.4			215.0			215.3			214.8
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.5			0.5			0.5
Average common shares outstanding - Diluted		215.9			215.5			215.8			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.27		$	0.24		$	0.49		$	0.43
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.00		$	0.00		$	0.01		$	0.00
Earnings per share available to common shareholders - Diluted	$	0.27		$	0.24		$	0.50		$	0.43
Anti-dilutive shares		0.0			0.0			0.0			0.0

19

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. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

The company believes the claim in the pending action described above in this item is without merit and intends to defend the matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to this matter.

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

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

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

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

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

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 June 30, 2014 TEC has estimated its ultimate financial liability to be $35.9 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.

20

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 June 30, 2014 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
TECO Coal
Fuel purchase related (2)	$	0.0	$	0.7	$	4.0	$	4.7	$	0.6
Other subsidiaries
Fuel purchase/energy management (2)		0.0		0.0		92.9		92.9		0.1
Total	$	0.0	$	0.7	$	96.9	$	97.6	$	0.7
Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
Tampa Electric Company(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at June 30, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At June 30, 2014, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

11. Segment Information

TECO Energy is an electric and gas utility holding company with 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.

21

Segment Information (1)
(millions) Three months ended Jun 30,	Tampa Electric		Peoples Gas		TECO Coal			Other & Eliminations			TECO Energy
2014
Revenues - external	$	512.5	$	90.7	$	120.6		$	2.5		$	726.3
Sales to affiliates		0.2		0.4		0.0			(0.6	)		0.0
Total revenues		512.7		91.1		120.6			1.9			726.3
Depreciation and amortization		61.7		13.4		8.7			0.4			84.2
Total interest charges(1)		23.3		3.4		1.5			14.0			42.2
Internally allocated interest (1)		0.0		0.0		1.5			(1.5	)		0.0
Provision (benefit) for income taxes		37.1		4.8		(0.7	)		(6.8	)		34.4
Net income (loss) from continuing operations		62.2		7.5		0.8			(12.1	)		58.4
Income from discontinued operations, net		0.0		0.0		0.0			0.0			0.0
Net income (loss)	$	62.2	$	7.5	$	0.8		($	12.1	)	$	58.4
2013
Revenues - external	$	502.6	$	101.3	$	128.4		$	3.6		$	735.9
Sales to affiliates		0.3		0.5		0.0			(0.8	)		0.0
Total revenues		502.9		101.8		128.4			2.8			735.9
Depreciation and amortization		60.8		13.2		9.5			0.4			83.9
Total interest charges(1)		23.3		3.3		1.7			14.4			42.7
Internally allocated interest (1)		0.0		0.0		1.7			(1.7	)		0.0
Provision (benefit) for income taxes		31.5		5.0		(0.9	)		(7.4	)		28.2
Net income (loss) from continuing operations		50.6		7.9		0.7			(7.6	)		51.6
Income from discontinued operations, net		0.0		0.0		0.0			(0.2	)		(0.2	)
Net income (loss)	$	50.6	$	7.9	$	0.7		($	7.8	)	$	51.4
(millions) Six months ended Jun 30,	Tampa Electric		Peoples Gas		TECO Coal			Other & Eliminations			TECO Energy
2014
Revenues - external	$	965.4	$	213.1	$	226.7		$	5.2		$	1,410.4
Sales to affiliates		0.5		0.6		0.0			(1.1	)		0.0
Total revenues		965.9		213.7		226.7			4.1			1,410.4
Depreciation and amortization		123.8		26.7		17.7			0.9			169.1
Total interest charges(1)		45.3		6.8		3.0			28.2			83.3
Internally allocated interest (1)		0.0		0.0		3.0			(3.0	)		0.0
Provision (benefit) for income taxes		63.7		14.0		(2.9	)		(13.7	)		61.1
Net income (loss) from continuing operations		107.4		22.1		(0.8	)		(23.3	)		105.4
Income from discontinued operations, net		0.0		0.0		0.0			3.1			3.1
Net income (loss)	$	107.4	$	22.1	$	(0.8	)	$	(20.2	)	$	108.5
2013
Revenues - external	$	920.4	$	223.2	$	246.3		$	7.1		$	1,397.0
Sales to affiliates		0.5		0.5		0.0			(1.0	)		0.0
Total revenues		920.9		223.7		246.3			6.1			1,397.0
Depreciation and amortization		119.8		26.2		19.2			0.7			165.9
Total interest charges(1)		46.7		6.7		3.4			28.3			85.1
Internally allocated interest (1)		0.0		0.0		3.3			(3.3	)		0.0
Provision (benefit) for income taxes		51.3		13.7		(1.0	)		(12.6	)		51.4
Net income (loss) from continuing operations		82.4		21.7		3.7			(15.0	)		92.8
Income from discontinued operations, net		0.0		0.0		0.0			0.1			0.1
Net income (loss)	$	82.4	$	21.7	$	3.7		$	(14.9	)	$	92.9
At Jun 30, 2014
Total assets	$	6,311.9	$	1,034.1	$	333.3		($	58.5	)	$	7,620.8
At Dec 31, 2013
Total assets	$	6,126.9	$	1,021.2	$	316.3		($	16.4	)	$	7,448.0

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2013 through June 2014 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

22

12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

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

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 30, 2014, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at June 30, 2014 and Dec. 31, 2013:

Total Derivatives(1)
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.2	$	9.7
Long-term assets		0.5		0.3
Total assets	$	8.7	$	10.0
Current liabilities	$	0.2	$	0.1
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.3

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

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties.

23

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
Jun 30, 2014
Description
Derivative assets	$	9.9		$	(1.2	)	$	8.7
Derivative liabilities	$	(1.5	)	$	1.2		$	(0.3	)
Dec 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)

The following table presents the derivative hedges of diesel fuel contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	0.1	$	0.2
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.2
Current liabilities	$	0.0	$	0.1
Long-term liabilities		0.0		0.0
Total liabilities	$	0.0	$	0.1

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.1	$	9.5
Long-term assets		0.5		0.3
Total assets	$	8.6	$	9.8
Current liabilities	$	0.2	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.2

The ending balance in AOCI related to the cash flow hedges and interest rate swaps at June 30, 2014 is a net loss of $7.5 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

24

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2014 and Dec. 31, 2013:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.0	Derivative liabilities		0.0
Natural gas derivatives:
Current	Derivative assets		8.1	Derivative liabilities		0.2
Long-term	Derivative assets		0.5	Derivative liabilities		0.1
Total derivatives designated as hedging instruments		$	8.7		$	0.3

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

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	8.1	Regulatory assets	$	0.2
Long-term	Regulatory liabilities		0.5	Regulatory assets		0.1
Total		$	8.6		$	0.3
(millions) Dec 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

25

Based on the fair value of the instruments at June 30, 2014, net pretax gains of $7.9 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 six months ended June 30:

For the three months ended Jun 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)					Effective Portion (1)
2014
Interest rate contracts	$	0.0			Interest expense	$	0.0
Commodity contracts:
Diesel fuel derivatives		0.1			Mining related costs		0.0
Total	$	0.1				$	0.0
2013
Interest rate contracts	$	0.0			Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.4	)		Mining related costs		(0.1	)
Total	($	0.4	)			($	0.3	)
For the six months ended Jun 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)					Effective Portion	(1)
2014
Interest rate contracts	$	0.0			Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.0			Mining related costs		(0.1	)
Total	$	0.0				($	0.3	)
2013
Interest rate contracts	$	0.0			Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)		Mining related costs		(0.1	)
Total	($	0.2	)			($	0.5	)

(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 six months ended June 30, 2014 and 2013, all hedges were effective.

26

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the six months ended June 30:

(millions)	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2014
Interest rate swaps	$	0.0		$	0.0		($	0.2	)
Diesel fuel derivatives		0.1			0.0			(0.1	)
Total	$	0.1		$	0.0		($	0.3	)
2013
Interest rate swaps	$	0.0		$	0.0		($	0.4	)
Diesel fuel derivatives		(1.1	)		(0.2	)		(0.1	)
Total	($	1.1	)	($	0.2	)	($	0.5	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		1.0		0.0		19.4
2015		0.0		0.0		0.0		25.0
2016		0.0		0.0		0.0		2.8
Total		0.0		1.0		0.0		47.2

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

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of June 30, 2014, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. As of June 30, 2014, substantially all positions with counterparties were net assets.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments. Substantially all of the company’s open positions with counterparties as of June 30, 2014 were asset positions.

27

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 June 30, 2014 and Dec. 31, 2013. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Jun 30, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	8.6	$	0.0	$	8.6
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	8.7	$	0.0	$	8.7
Liabilities
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Diesel fuel swaps		0.0		0.0		0.0		0.0
Total	$	0.0	$	0.3	$	0.0	$	0.3
	At fair value as of Dec 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Diesel fuel swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	10.0	$	0.0	$	10.0
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.3	$	0.0	$	0.3

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

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

28

14. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $7.0 million and $12.8 million of capacity pursuant to PPAs for the three and six months ended June 30, 2014, respectively and $5.0 million and $9.9 million for the three and six months ended June 30, 2013, respectively.

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

15. Discontinued Operations

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

The following table provides selected components of discontinued operations:

Components of income from discontinued operations	Three months ended					Six months ended
	Jun 30,					Jun 30,
(millions)	2014		2013			2014		2013
Revenues	$	0.0	$	0.0		$	0.0	$	0.0
(Loss) Income from operations		0.0		(0.2	)		5.0		0.2
(Loss) Income from discontinued operations		0.0		(0.2	)		5.0		0.2
Less: Provision for income taxes		0.0		0.0			1.9		0.1
(Loss) Income from discontinued operations, net		0.0		(0.2	)		3.1		0.1

16. Asset Impairments

The company accounts for long-lived asset impairments in accordance with the accounting guidance for long-lived assets, which requires that long-lived assets held and used be tested for recoverability whenever events or changes in circumstances indicate that its carrying value may not be recoverable, and assets held for sale be recorded at the lower of its carrying amount or fair value less cost to sell. An asset is considered not recoverable if its carrying value exceeds the sum of its undiscounted expected cash flows. If it is determined that the carrying value is not recoverable and its carrying value exceeds its fair value, an impairment charge is made and the value of the asset is reduced to its fair value.

In 2014, the benchmark price for coal significantly fell from what was used in the long-lived asset impairment testing that was done for TECO Coal in 2013. Additionally, the company is currently in active discussions with potential buyers of TECO Coal; however, no agreement or understanding with respect to any sale has been reached, nor has the company’s board of directors made a determination regarding whether the company would sell TECO Coal based on current indications of value. These indications suggest that a sale price above book value may be unlikely at this time. Although there can be no assurances that a sale of TECO Coal will be completed and TECO Coal is not considered an asset held for sale, the company felt that these factors, coupled together, caused a triggering event requiring impairment testing of TECO Coal in the second quarter of 2014.

The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. A 20-year forecast was developed based on proven and probable reserves, prices using current average coal benchmark prices as a pricing base, and costs using current average costs. A market recovery was assumed for prices and increased costs that moved in line with the prices were factored into the forecast. The book value of TECO Coal’s long-lived assets (including capitalized mine development costs) was determined to be recoverable; therefore, no impairment charge was deemed necessary. Additionally, due to the uncertainty in the soft coal market, the company performed sensitivity analyses on revenues and noted that if revenues declined 15 percent from forecast, all assets would still be recoverable.

29

17. Pending Acquisition of New Mexico Gas Company

Pending Acquisition of New Mexico Gas Company

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

On May 14, 2014, the Joint Applicants announced they had reached a settlement agreement in the case with certain interveners, which was not opposed by NMPRC staff or any other interveners in the proceeding. On June 30, 2014, the hearing examiner issued a certification of the stipulation recommending approval of the stipulation.

A meeting of the NMPRC to consider the hearing examiner’s certification has not been scheduled. It is anticipated that the NMPRC will issue a final order approving the acquisition and certification of stipulation in time for the transaction to close in the third quarter of 2014.

In July 2014, TECO Energy completed a public offering of common stock, the proceeds from which are intended to be used to pay a portion of the acquisition price (see Note 18). With TECO Energy’s consent, NMGC and NMGI each entered into a Note Purchase Agreement on July 30, 2014, contemplating the issuance of $70 million and $200 million of notes, respectively, conditioned upon, and to be issued at, closing of the acquisition. The proceeds from the NMGC notes are to be used to repay existing debt at closing and the proceeds from the NMGI notes are to be primarily used to repay existing debt and to fund the transaction, costs and expenses.

18. Subsequent Events

Public Offering of 15.5 million in Common Shares

On July 1, 2014, the company entered into an underwriting agreement with Morgan Stanley & Co. LLC, as representative of the several underwriters named therein, pursuant to which the company agreed to offer and sell 15.5 million shares of its common stock in an underwritten public offering at a public offering price of $18.10 per share. The company received approximately $271 million in net proceeds from the offering after underwriting fees and offering expenses. The shares were delivered to the underwriters on July 8, 2014.

Pursuant to the terms of the underwriting agreement, the company granted the underwriters a 30-day option to purchase up to an additional 2.3 million shares. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

The company plans to use the net proceeds from this offering to fund, in part, the company’s previously announced acquisition of New Mexico Gas Company and for general corporate purposes.

NMGC and NMGI Note Purchase Agreement

NMGC and NMGI each entered into a Note Purchase Agreement on July 30, 2014, contemplating the issuance of $70 million and $200 million of notes, respectively, conditioned upon, and to be issued at, closing of the acquisition. (See Note 17)

30

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 June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three month and six month periods ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014. References should be made to the explanatory notes affecting the consolidated financial statements contained in TEC’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 and to the notes on pages 37 through 48 of this report.

INDEX TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

	Page No.
Consolidated Condensed Balance Sheets, June 30, 2014 and Dec. 31, 2013		32-33
Consolidated Condensed Statements of Income and Comprehensive Income for the three month and six month periods ended June 30, 2014 and 2013		34-35
Consolidated Condensed Statements of Cash Flows for the six month periods ended June 30, 2014 and 2013		36
Notes to Consolidated Condensed Financial Statements		37-48

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.

31

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Jun 30,			Dec 31,
(millions)	2014			2013
Property, plant and equipment
Utility plant in service
Electric	$	6,941.7		$	6,934.0
Gas		1,265.6			1,249.5
Construction work in progress		493.4			385.3
Utility plant in service, at original costs		8,700.7			8,568.8
Accumulated depreciation		(2,530.9	)		(2,562.6	)
		6,169.8			6,006.2
Other property		8.4			8.3
Total property, plant and equipment, net		6,178.2			6,014.5
Current assets
Cash and cash equivalents		55.2			9.8
Receivables, less allowance for uncollectibles of $2.3 and $2.0 at Jun 30, 2014 and Dec. 31, 2013, respectively		256.7			227.6
Inventories, at average cost
Fuel		98.7			93.7
Materials and supplies		74.4			76.8
Regulatory assets		33.7			34.3
Derivative assets		8.1			9.5
Taxes receivable		0.0			54.9
Deferred income taxes		20.4			29.4
Prepayments and other current assets		21.2			12.5
Total current assets		568.4			548.5
Deferred debits
Unamortized debt expense		17.1			14.8
Regulatory assets		283.9			293.1
Derivative assets		0.5			0.3
Other		3.8			4.6
Total deferred debits		305.3			312.8
Total assets	$	7,051.9		$	6,875.8

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

32

TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets – continued

Unaudited

Liabilities and Capitalization	Jun 30,			Dec 31,
(millions)	2014			2013
Capitalization
Common stock	$	2,047.4		$	2,030.4
Accumulated other comprehensive loss		(7.6	)		(7.8	)
Retained earnings		325.6			308.1
Total capital		2,365.4			2,330.7
Long-term debt		2,013.9			1,797.5
Total capitalization		4,379.3			4,128.2
Current liabilities
Long-term debt due within one year		83.3			83.3
Notes payable		0.0			84.0
Accounts payable		198.2			226.0
Customer deposits		167.5			164.5
Regulatory liabilities		65.7			85.8
Derivative liabilities		0.2			0.0
Interest accrued		18.6			16.4
Taxes accrued		57.8			12.2
Other		12.1			12.0
Total current liabilities		603.4			684.2
Deferred credits
Deferred income taxes		1,145.1			1,114.3
Investment tax credits		9.2			9.4
Derivative liabilities		0.1			0.2
Regulatory liabilities		621.4			631.4
Other		293.4			308.1
Total deferred credits		2,069.2			2,063.4
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	7,051.9		$	6,875.8

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

33

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Jun 30,
(millions)	2014			2013
Revenues
Electric (includes franchise fees and gross receipts taxes of $22.7 in 2014 and $21.5 in 2013)	$	512.7		$	502.8
Gas (includes franchise fees and gross receipts taxes of $5.1 in 2014 and $5.2 in 2013)		90.6			101.3
Total revenues		603.3			604.1
Expenses
Regulated operations and maintenance
Fuel		169.7			174.5
Purchased power		19.9			20.5
Cost of natural gas sold		29.0			40.9
Other		126.8			129.5
Depreciation and amortization		75.1			74.0
Taxes, other than income		47.6			45.8
Total expenses		468.1			485.2
Income from operations		135.2			118.9
Other income
Allowance for other funds used during construction		2.0			1.4
Other income, net		1.1			1.3
Total other income		3.1			2.7
Interest charges
Interest on long-term debt		26.4			26.4
Other interest		1.0			1.0
Allowance for borrowed funds used during construction		(0.7	)		(0.8	)
Total interest charges		26.7			26.6
Income before provision for income taxes		111.6			95.0
Provision for income taxes		41.9			36.5
Net income		69.7			58.5
Other comprehensive income, net of tax
Amortization of settled interest rate swaps		0.0			0.2
Total other comprehensive income, net of tax		0.0			0.2
Comprehensive income	$	69.7		$	58.7

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

	Six months ended Jun 30,
(millions)	2014			2013
Revenues
Electric (includes franchise fees and gross receipts taxes of $43.0 in 2014 and $40.5 in 2013)	$	965.7		$	920.7
Gas (includes franchise fees and gross receipts taxes of $12.0 in 2014 and $11.6 in 2013)		213.1			223.2
Total revenues		1,178.8			1,143.9
Expenses
Regulated operations and maintenance
Fuel		319.3			314.5
Purchased power		38.1			35.1
Cost of natural gas sold		76.2			90.4
Other		247.1			250.1
Depreciation and amortization		150.5			146.0
Taxes, other than income		95.0			90.3
Total expenses		926.2			926.4
Income from operations		252.6			217.5
Other income
Allowance for other funds used during construction		4.4			2.5
Other income, net		2.3			2.5
Total other income		6.7			5.0
Interest charges
Interest on long-term debt		52.1			52.9
Other interest		2.1			1.9
Allowance for borrowed funds used during construction		(2.1	)		(1.4	)
Total interest charges		52.1			53.4
Income before provision for income taxes		207.2			169.1
Provision for income taxes		77.7			65.0
Net income		129.5			104.1
Other comprehensive income, net of tax
Amortization of settled interest rate swaps		0.2			0.4
Total other comprehensive income, net of tax		0.2			0.4
Comprehensive income	$	129.7		$	104.5

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

35

TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Six months ended Jun 30,
(millions)	2014			2013
Cash flows from operating activities
Net income	$	129.5		$	104.1
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		150.5			146.0
Deferred income taxes		35.0			42.6
Investment tax credits		(0.2	)		(0.2	)
Allowance for funds used during construction		(4.4	)		(2.5	)
Deferred recovery clauses		(14.4	)		(5.9	)
Receivables, less allowance for uncollectibles		(29.1	)		(43.0	)
Inventories		(2.6	)		(18.9	)
Prepayments		(2.8	)		(5.6	)
Taxes accrued		100.5			63.5
Interest accrued		2.2			1.6
Accounts payable		(34.3	)		13.9
Other		(10.6	)		(0.2	)
Cash flows from operating activities		319.3			295.4
Cash flows from investing activities
Capital expenditures		(312.7	)		(239.9	)
Allowance for funds used during construction		4.4			2.5
Net proceeds from sale of assets		0.1			0.0
Cash flows used in investing activities		(308.2	)		(237.4	)
Cash flows from financing activities
Common stock		17.0			20.0
Proceeds from long-term debt issuance		296.6			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(83.3	)		0.0
Net decrease in short-term debt		(84.0	)		0.0
Dividends		(112.0	)		(94.1	)
Cash flows provided by (used in) financing activities		34.3			(74.1	)
Net increase (decrease) in cash and cash equivalents		45.4			(16.1	)
Cash and cash equivalents at beginning of period		9.8			45.2
Cash and cash equivalents at end of period	$	55.2		$	29.1
Supplemental disclosure of non-cash activities
Capital expenditures not yet paid	$	8.6		$	(3.1	)

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

36

TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

Cash Flows Related to Derivatives and Hedging Activities

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

2. New Accounting Pronouncements

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations. A disposal of a

37

component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for TEC beginning in 2015.

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for TEC beginning in fiscal 2017 and allows for either full retrospective adoption or modified retrospective adoption. TEC is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

3. Regulatory

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

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both June 30, 2014 and Dec. 31, 2013.

Regulatory Assets and Liabilities

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

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

38

Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun 30, 2014		Dec 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	68.1	$	67.4
Other:
Cost-recovery clauses		1.8		6.1
Postretirement benefit asset		177.6		182.7
Deferred bond refinancing costs (2)		7.6		8.0
Environmental remediation		52.0		51.4
Competitive rate adjustment		2.8		4.1
Other		7.7		7.7
Total other regulatory assets		249.5		260.0
Total regulatory assets		317.6		327.4
Less: Current portion		33.7		34.3
Long-term regulatory assets	$	283.9	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.6	$	9.8
Other:
Cost-recovery clauses		34.8		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.4		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		588.4		594.0
Total other regulatory liabilities		681.5		707.4
Total regulatory liabilities		687.1		717.2
Less: Current portion		65.7		85.8
Long-term regulatory liabilities	$	621.4	$	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	Jun 30,		Dec 31,
(millions)	2014		2013
Clause recoverable (1)		$4.6		$10.2
Components of rate base (2)		180.7		185.6
Regulatory tax assets (3)		68.1		67.4
Capital structure and other (3)		64.2		64.2
Total	$	317.6	$	327.4

(1) To be recovered through cost-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.

39

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 six months ended June 30, 2014 and 2013 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2010 and forward.

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 June 30, 2014 and 2013, respectively, was $3.9 million and $5.6 million for pension benefits, and $2.6 million and $2.4 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2014 and 2013, respectively, was $7.7 million and $10.9 million for pension benefits, and $5.2 million and $5.0 million for other postretirement benefits.

For the 2014 plan year, TECO Energy assumed a long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. Additionally, TECO Energy made contributions of $26.5 million to its pension plan in the six months ended June 30, 2014. TEC’s portion of the contributions was $21.5 million.

Included in the benefit expenses discussed above, for the three and six months ended June 30, 2014, TEC reclassed $2.7 million and $5.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

40

6. Short-Term Debt

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Jun 30, 2014						Dec. 31, 2013
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		78.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

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

At June 30, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at June 30, 2014.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2014, TEC’s total long-term debt had a carrying amount of $2,097.2 million and an estimated fair market value of $2,329.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,042.0 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the Notes). The Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

41

8. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

TEC believes the claim in the pending action described above in this item is without merit and intends to defend the matter vigorously. TEC is unable at this time to estimate the possible loss or range of loss with respect to this matter.

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 June 30, 2014 TEC has estimated its ultimate financial liability to be $35.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2014 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
Tampa Electric Company (2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at June 30, 2014. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2014, TEC was in compliance with all applicable financial covenants.

42

9. Segment Information

(millions) Three months ended Jun 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2014
Revenues - external	$	512.6	$	90.7	$	0.0		$	603.3
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Total revenues		512.7		91.1		(0.5	)		603.3
Depreciation and amortization		61.7		13.4		0.0			75.1
Total interest charges		23.3		3.4		0.0			26.7
Provision for income taxes		37.1		4.8		0.0			41.9
Net income	$	62.2	$	7.5	$	0.0		$	69.7
2013
Revenues - external	$	502.8	$	101.3	$	0.0		$	604.1
Sales to affiliates		0.1		0.5		(0.6	)		0.0
Total revenues		502.9		101.8		(0.6	)		604.1
Depreciation and amortization		60.8		13.2		0.0			74.0
Total interest charges		23.3		3.3		0.0			26.6
Provision for income taxes		31.5		5.0		0.0			36.5
Net income	$	50.6	$	7.9	$	0.0		$	58.5
Six months ended Jun 30,
2014
Revenues - external	$	965.7	$	213.1	$	0.0		$	1,178.8
Sales to affiliates		0.2		0.6		(0.8	)		0.0
Total revenues		965.9		213.7		(0.8	)		1,178.8
Depreciation and amortization		123.8		26.7		0.0			150.5
Total interest charges		45.3		6.8		0.0			52.1
Provision for income taxes		63.7		14.0		0.0			77.7
Net income	$	107.4	$	22.1	$	0.0		$	129.5
Total assets at Jun 30, 2014	$	6,061.9	$	1,002.4	($	12.4	)	$	7,051.9
2013
Revenues - external	$	920.7	$	223.2	$	0.0		$	1,143.9
Sales to affiliates		0.2		0.5		(0.7	)		0.0
Total revenues		920.9		223.7		(0.7	)		1,143.9
Depreciation and amortization		119.8		26.2		0.0			146.0
Total interest charges		46.7		6.7		0.0			53.4
Provision for income taxes		51.3		13.7		0.0			65.0
Net income	$	82.4	$	21.7	$	0.0		$	104.1
Total assets at Dec 31, 2013	$	5,895.4	$	989.3	($	8.9	)	$	6,875.8

43

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 30, 2014, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.1	$	9.5
Long-term assets		0.5		0.3
Total assets	$	8.6	$	9.8
Current liabilities (1)	$	0.2	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.2

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

The ending balance in AOCI related to previously settled interest rate swaps at June 30, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

44

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
(millions)	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Jun 30, 2014
Description
Derivative assets	$	9.8		$	(1.2	)	$	8.6
Derivative liabilities	$	(1.5	)	$	1.2		$	(0.3	)
Dec 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	8.1	Regulatory assets	$	0.2
Long-term	Regulatory liabilities		0.5	Regulatory assets		0.1
Total		$	8.6		$	0.3
(millions) Dec 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Based on the fair value of the instruments at June 30, 2014, net pretax gains of $7.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

45

The following table presents the effect of hedging instruments on OCI and income for the three months and six months ended June 30:

(millions)	Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)	Three months ended Jun 30:			Six months ended Jun 30:
2014
Interest rate contracts:	Interest expense	$	0.0		$	0.2
Total		$	0.0		$	0.2
2013
Interest rate contracts:	Interest expense	($	0.2	)	($	0.4	)
Total		($	0.2	)	($	0.4	)

(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 six months ended June 30, 2014 and 2013, all hedges were effective.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2014		0.0		19.4
2015		0.0		25.0
2016		0.0		2.8
Total		0.0		47.2

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 June 30, 2014, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions are generally not adjusted as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. As of June 30, 2014, substantially all positions with counterparties were net assets.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments. Substantially all of TEC’s open positions with counterparties as of June 30, 2014 were asset positions.

46

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and Dec. 31, 2013. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below, the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Jun 30, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	8.6	$	0.0	$	8.6
Total	$	0.0	$	8.6	$	0.0	$	8.6
Liabilities
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Total	$	0.0	$	0.3	$	0.0	$	0.3
	At fair value as of Dec 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Total	$	0.0	$	9.8	$	0.0	$	9.8
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2

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

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

47

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended June 30,							Six months ended June 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2014
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.0		0.0			0.0		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.0		0.0			0.0		0.4		(0.2	)		0.2
Total other comprehensive income	$	0.0	$	0.0		$	0.0	$	0.4	($	0.2	)	$	0.2
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		0.7		(0.3	)		0.4
Gain on cash flow hedges		0.4		(0.2	)		0.2		0.7		(0.3	)		0.4
Total other comprehensive income	$	0.4	($	0.2	)	$	0.2	$	0.7	($	0.3	)	$	0.4

Accumulated Other Comprehensive Loss
(millions)	Jun 30, 2014			Dec 31, 2013
Net unrealized losses from cash flow hedges (1)	($	7.6	)	($	7.8	)
Total accumulated other comprehensive loss	($	7.6	)	($	7.8	)

(1) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

13. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $7.0 million and $12.8 million of capacity pursuant to PPAs for the three and six months ended June 30, 2014, respectively, and $5.0 million and $9.9 million for the three and six months ended June 30, 2013, respectively.

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

48

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

This Management’s Discussion & Analysis of Financial Conditions contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. The forecasted results are based on the company’s current expectations and assumptions, and the company does not undertake to update that information or any other information contained in this Management’s Discussion & Analysis, except as may be required by law. Factors that could impact actual results include: regulatory actions by federal, state or local authorities, including the required approval by the New Mexico Public Regulation Commission for the acquisition of NMGC; the risk that the transaction to acquire NMGC may be delayed, may be consummated on less favorable terms than originally expected, or not be consummated at all; unexpected capital needs or unanticipated reductions in cash flow that affect liquidity; the ability to access the capital and credit markets when required; the ability to sell TECO Coal at an acceptable price; general economic conditions affecting energy sales at the utility companies; economic conditions, both national and international, affecting the Florida economy and demand for TECO Coal’s production; costs for alternate fuels used for power generation affecting demand for TECO Coal’s thermal coal production; operating costs and environmental or safety regulations affecting production levels and margins at TECO Coal; weak demand and market pricing conditions affecting the value of TECO Coal’s facilities and coal reserves; weather variations and customer energy usage patterns affecting sales and operating costs at the utilities and the effect of weather conditions on energy consumption; the effect of extreme weather conditions or hurricanes; general operating conditions; input commodity prices affecting cost at all of the operating companies; natural gas demand at the utilities; and the ability of TECO Energy’s subsidiaries to operate equipment without undue accidents, breakdowns or failures. Additional information is contained under Item IA “Risk Factors” in this Quarterly Report on Form 10-Q for the period ended June 30, 2014.

Earnings Summary - Unaudited
	Three months ended June 30,					Six months ended June 30,
(millions, except per share amounts)	2014		2013			2014		2013
Consolidated revenues	$	726.3	$	735.9		$	1,410.4	$	1,397.0
Continuing operations	$	58.4	$	51.6		$	105.4	$	92.8
Discontinued operations		—		(0.2	)		3.1		0.1
Net income	$	58.4	$	51.4		$	108.5	$	92.9
Average common shares outstanding
Basic		215.4		215.0			215.3		214.8
Diluted		215.9		215.5			215.8		215.3
Earnings per share - Basic
Continuing operations	$	0.27	$	0.24		$	0.49	$	0.43
Discontinued operations		—		—			0.01		—
Earnings per share - Basic	$	0.27	$	0.24		$	0.50	$	0.43
Earnings per share - Diluted
Continuing operations	$	0.27	$	0.24		$	0.49	$	0.43
Discontinued operations		—		—			0.01		—
Earnings per share - Diluted	$	0.27	$	0.24		$	0.50	$	0.43

TECO Energy Strategy

TECO Energy’s strategy is to transition into a growth plus sustainable yield company focused on its existing core businesses—electric and gas utilities—and to execute on accretive acquisitions of regulated utilities to grow its base. TECO Energy seeks to optimize its businesses by application of best practices in both gas and electric operations.

Our strategy, which is based on a long and successful history of owning and operating regulated electric and gas utilities, consistently delivering value to our shareholders over the long term, is to:

Invest in and grow our utilities, both in Florida and, upon consummation of the NMGC acquisition, in New Mexico with intentions to acquire additional utilities in areas of the country with favorable regulatory environments and above-average growth prospects;

Focus our gas utilities on CNG vehicle conversions and customer user-conversions from other forms of energy to natural gas;

Invest in proven and emerging technologies, such as smart grid applications, that benefit customers and shareholders;

Collaborate with customers to develop alternative solutions to meet their energy needs; and Utilize our expertise in intrastate pipelines and lateral development to support the growth of natural gas in Florida and in New Mexico.

49

An important part of our strategy is that we expect our utilities to earn returns that are at or above the middle of their respective allowed ROE while maintaining their authorized capital structures and financial integrity. Tampa Electric’s 2013 Florida rate case settlement, which included $70 million of base rate increases through 2015, plus an additional $110 million base rate increase in January 2017, or when the Polk Power Station units two through five conversion project enters service, provides regulatory certainty through 2017.

Florida, with its favorable growth characteristics, combined with its supportive regulatory environment, is one of the most attractive states to operate regulated utilities. We see similar growth characteristics in New Mexico, an attractive sunbelt state with a growing population. We expect opportunities to invest capital to support the growth and reliability opportunities at PGS and NMGC, the largest LDCs Florida and New Mexico, respectively. Additionally, we have opportunities to invest significant capital in Tampa Electric over the next several years for the Polk Power Station units two through five conversion, which we believe will allow us to continue providing safe, affordable and reliable service to customers and support our growth.

TECO Coal Update

As we have previously indicated, we do not consider TECO Coal to be a core holding. Consistent with this view, we have had discussions from time to time with interested parties regarding a possible sale of TECO Coal, and have been working with an investment banking firm to help us determine whether there would be interest in a sale transaction that we would find acceptable. We are in active discussions with potential buyers, but no agreement or understanding with respect to any sale has been reached. Furthermore, our board of directors has not made a determination regarding whether we would sell TECO Coal based on current indications of value. These indications suggest that a sale price above book value may be unlikely in the current market conditions. In the context of furthering our overall strategy, that is a factor which we would consider, among others, in deciding whether to sell TECO Coal. Accordingly, there can be no assurances that a sale of TECO Coal will be completed, and if a sale is completed, the price received is expected to reflect current market conditions.

Update on Regulatory Status of NMGC Acquisition

In May 2013, TECO Energy announced that it had signed an agreement to acquire NMGI, the parent company of New Mexico Gas Company from CES. This acquisition is subject to approval by the NMPRC. In July 2013, we filed a joint application with NMGC and CES with the NMPRC for approval of the acquisition. On May 14, 2014, we reached a settlement agreement with the New Mexico Industrial Energy Consumers, which represents large customers of NMGC, and the New Mexico Attorney General’s office, which represents New Mexico residential and small business customers, with regards to the NMGC acquisition. Under the terms of the settlement, among other elements, NMGC will freeze customer rates until the end of 2017 and limit job reductions in the first three years after the NMGC acquisition. The NMPRC staff did not oppose the settlement, and on June 30, 2014, the NMPRC hearing examiner issued a certification of stipulation recommending that the NMPRC approve the transaction and related matters. The NMPRC still must decide whether the settlement is in the public interest and whether to approve the NMGC acquisition, which decision we expect in the third quarter of 2014. Under this schedule, however, closing of the NMGC acquisition will not occur within one year of our Hart-Scott-Rodino Premerger Notification and Report Form with the U.S. Department of Justice (HSR Form). Accordingly, on June 20, 2014, we filed a new HSR Form and the closing of the transaction will be subject to renewed clearance from anti-trust regulators and expiration of the new waiting period under the filing. As previously announced, we already reached a settlement agreement with the U.S. Department of Energy regarding the NMGC acquisition.

In July, we completed the permanent financing required to fund the closing of the NMGC acquisition.

Operating Results

Three Months Ended June 30, 2014

TECO Energy, Inc. reported second-quarter 2014 net income of $58.4 million, or $0.27 per share, compared with $51.4 million, or $0.24 per share, in the second quarter of 2013. Net income from continuing operations was also $58.4 million in the 2014 second quarter, compared with $51.6 million, or $0.24 per share, for the same period in 2013.

Six Months Ended June 30, 2014

Year-to-date net income was $108.5 million, or $0.50 per share, compared with net income of $92.9 million, or $0.43 per share in the 2013 period. Net income from continuing operations was $105.4 million or $0.49 per share, compared with $92.8 million or $0.43 per share in the 2013 period.

The 2014 benefit of $3.1 million reported in discontinued operations was related to the favorable resolution of an indemnification provision associated with the 2012 sale of TECO Guatemala.

50

Operating Company Results

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

Tampa Electric Company – Electric Division

Tampa Electric’s net income for the second quarter of 2014 was $62.2 million, compared with $50.6 million for the same period in 2013. Results for the quarter reflected the benefits of the rate case settlement effective Nov. 1, 2013, a 1.7% higher average number of customers, higher energy sales primarily due to customer growth, and $0.8 million lower earnings on assets recovered through the Environmental Cost Recovery Clause (ECRC) due to a lower current weighted average cost of capital, which includes the lower return on equity (ROE) in the 2013 rate case settlement. Results reflected lower operations and maintenance expenses, partially offset by higher depreciation expense. Second-quarter net income in 2014 included $2.1 million of Allowance for Funds Used During Construction (AFUDC) equity, which represents allowed equity cost capitalized to construction costs, compared with $1.4 million in the 2013 quarter.

Total degree days in Tampa Electric’s service area in the second quarter of 2014 were 4% below normal, and 6% below the 2013 period. Although the total degree day comparisons indicate milder than normal weather, the pattern of periods of warm and dry weather, especially later in the quarter, contributed to higher energy sales. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, increased 0.8% in the second quarter of 2014 compared with the same period in 2013. In the 2014 period, pretax base revenues were almost $17 million higher than in 2013, including approximately $15 million of higher revenue as a result of the 2013 rate case settlement. (The quarterly energy sales shown on the statistical summary that follows reflect the energy sales based on the timing of billing cycles, which can vary period to period.) Sales to residential customers increased primarily from customer growth. Sales to commercial and non-phosphate industrial customers increased due to the improving economy. Sales to lower-margin industrial-phosphate customers decreased as self-generation by those customers increased.

Operations and maintenance expense, excluding all Florida Public Service Commission (FPSC)-approved cost-recovery clauses, was $1.6 million lower than in the 2013 quarter, reflecting $1.7 million of higher cost to operate and maintain the generating system and higher employee-related costs more than offset by a $1.2 million benefit from the elimination of the storm damage accrual as a result of the 2013 rate case settlement, almost $1.0 million lower pension expense and lower self-insurance reserves. Depreciation and amortization expense increased $0.5 million in 2014, primarily as a result of normal additions to facilities to reliably serve customers, partially offset by approximately $1.0 million of lower amortization on software due to the change in expected useful life for software in the 2013 rate case settlement.

Year-to-date net income was $107.4 million, compared with $82.4 million in the 2013 period, driven primarily by the benefits from the 2013 rate case settlement, 1.7% higher average number of customers, higher energy sales from customer growth, more favorable weather and a stronger economy and lower operations and maintenance expenses, partially offset by higher depreciation expense, and $1.6 million lower earnings on assets recovered through the ECRC. Year-to-date net income in 2014 included $4.4 million of AFUDC equity, compared with $2.5 million in the 2013 period.

Year-to-date total degree days in Tampa Electric’s service area were 3% below normal, and 2% below the prior year-to-date period. Pretax base revenue was almost $39 million higher than in 2013, including approximately $28 million of higher revenue as a result of the 2013 rate case settlement. In the 2014 year-to-date period, total net energy for load was 1.5% higher than the same period in 2013. Higher energy sales were driven by the same factors as the quarterly sales, and winter weather that was colder than in 2013.

Operations and maintenance expenses, excluding all FPSC-approved cost-recovery clauses, decreased $1.8 million in the 2014 year-to-date period reflecting the same factors as in the second quarter. Compared to the 2013 year-to-date period, depreciation and amortization expense increased $2.5 million, reflecting additions to facilities to serve customers, partially offset by approximately $2.0 million of lower amortization on software due to the change in expected useful life for software in the 2013 rate case settlement.

51

A summary of Tampa Electric’s regulated operating statistics for the three and six months ended June 30, 2014 and 2013 follows:

(millions, except average customers)	Operating Revenues							Kilowatt-hour sales
Three months ended June 30,	2014		2013		% Change			2014		2013		% Change
By Customer Type
Residential	$	243.5	$	226.2		7.6			2,089.2		2,061.9		1.3
Commercial		150.2		143.5		4.7			1,529.2		1,501.0		1.9
Industrial – Phosphate		16.5		18.9		(12.7	)		203.5		235.1		(13.4	)
Industrial – Other		26.6		25.5		4.3			297.4		287.5		3.4
Other sales of electricity		45.6		44.4		2.7			459.1		460.3		(0.3	)
Deferred and other revenues (1)		15.2		26.0		(41.5	)
Total energy sales	$	497.6	$	484.5		2.7			4,578.4		4,545.8		0.7
Sales for resale		1.2		3.5		(65.7	)		26.3		88.5		(70.3	)
Other operating revenue		14.0		14.9		(6.0	)
Total revenues	$	512.8	$	502.9		2.0			4,604.7		4,634.3		(0.6	)
Average customers (thousands)		705.3		693.8		1.7
Retail net energy for load (kilowatt hours)									5,068.8		5,029.0		0.8
Six months ended June 30,
By Customer Type
Residential	$	457.0	$	415.8		9.9			3,912.1		3,787.1		3.3
Commercial		285.0		274.2		3.9			2,880.1		2,854.3		0.9
Industrial – Phosphate		33.3		36.7		(9.3	)		411.8		457.1		(9.9	)
Industrial – Other		50.9		48.8		4.3			565.3		550.4		2.7
Other sales of electricity		88.1		85.7		2.8			880.9		880.8		0.0
Deferred and other revenues (1)		13.2		23.2		(43.1	)
Total energy sales		927.5		884.4		4.9			8,650.2		8,529.7		1.4
Sales for resale		8.2		4.9		67.3			132.7		129.3		2.6
Other operating revenue		30.2		31.6		(4.4	)
Total revenues	$	965.9	$	920.9		4.9			8,782.9		8,659.0		1.4
Average customers (thousands)		703.8		692.0		1.7
Retail output to line (kilowatt hours)									9,254.0		9,116.9		1.5

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

Tampa Electric Company – Natural Gas Division

PGS reported net income of $7.5 million for the second quarter, compared with $7.9 million in 2013. Average customer growth was 1.8% in the quarter, and therm sales to residential customers decreased as a result of mild spring weather. Second-quarter results in 2014 reflected slightly higher general non-fuel operations and maintenance expense driven by higher employee-related costs. Depreciation and amortization increased slightly due to normal additions to facilities to serve customers, partially offset by a change in software amortization similar to Tampa Electric’s discussed above. Sales to power-generation customers and off-system sales decreased due to two power generators not operating and new participants in the off-system sales market.

PGS reported net income of $22.1 million for the year-to-date period, compared with $21.7 million in the same period in 2013. Results reflect a 1.7% higher average number of customers, and higher therm sales to residential and commercial customers 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 second quarter. Non-fuel operations and maintenance expense increased $0.6 million compared to the 2013 period, driven by the same factors as in the second quarter partially offset by a first quarter of 2014 recovery of $1.6 million of costs incurred in connection with a 2010 outage incident.

52

A summary of PGS’s regulated operating statistics for the three and six months ended June 30, 2014 and 2013 follows:

(millions, except average customers)	Operating Revenues							Therms
Three months ended June 30,	2014		2013		% Change			2014		2013		% Change
By Customer Type
Residential	$	30.7	$	29.6		3.7			15.3		16.3		(6.1	)
Commercial		33.4		33.0		1.2			110.9		107.3		3.4
Industrial		3.3		3.0		10.0			64.8		68.5		(5.4	)
Off system sales		9.4		20.4		(53.9	)		18.5		46.6		(60.3	)
Power generation		1.6		2.5		(36.0	)		148.7		180.4		(17.6	)
Other revenues		10.6		10.7		(0.9	)
Total	$	89.0	$	99.2		(10.3	)		358.2		419.1		(14.5	)
By Sales Type
System supply	$	50.0	$	60.4		(17.2	)		40.6		70.5		(42.4	)
Transportation		28.4		28.2		0.7			317.6		348.6		(8.9	)
Other revenues		10.6		10.7		(0.9	)
Total	$	89.0	$	99.3		(10.4	)		358.2		419.1		(14.5	)
Average customers (thousands)		353.9		347.8		1.8
Six months ended June 30,
By Customer Type
Residential	$	80.4	$	71.9		11.8			48.6		45.8		6.1
Commercial		74.3		72.2		2.9			241.9		232.1		4.2
Industrial		6.9		6.6		4.5			136.8		139.7		(2.1	)
Off system sales		17.8		38.7		(54.0	)		33.9		97.1		(65.1	)
Power generation		3.6		5.6		(35.7	)		304.3		385.4		(21.0	)
Other revenues		26.5		23.2		14.2
Total	$	209.5	$	218.2		(4.0	)		765.5		900.1		(15.0	)
By Sales Type
System supply	$	121.7	$	134.4		(9.4	)		98.1		160.4		(38.8	)
Transportation		61.3		60.6		1.2			667.4		739.7		(9.8	)
Other revenues		26.5		23.2		14.2
Total	$	209.5	$	218.2		(4.0	)		765.5		900.1		(15.0	)
Average customers (thousands)		352.9		347.1		1.7

TECO Coal

TECO Coal reported second quarter net income of $0.8 million on sales of 1.5 million tons, compared with net income of $0.7 million on similar sales volumes in the same period in 2013. In 2014, second-quarter results reflect an average net per ton selling price, excluding transportation allowances, of $80, more than $5 lower than in 2013. In the second quarter of 2014, the all-in total per-ton cost of sales was $80, compared with almost $86 in the 2013 period. Second quarter costs include an approximately $0.30 per ton negative impact of incremental transportation costs due to a tunnel fire on the railroad serving the Premier Elkhorn mining complex. These costs are expected to be recovered from the railroad in a future quarter. TECO Coal recorded a $0.7 million income tax benefit in the second quarter of 2014 that included a $0.8 million tax depletion benefit, compared with a $1.0 million tax benefit that included a $0.8 million tax depletion benefit, in the 2013 period.

TECO Coal recorded a 2014 year-to-date loss of $0.8 million on sales of 2.8 million tons, compared with net income of $3.7 million on similar sales volumes in the 2013 period. The 2014 year-to-date average net per-ton selling price was almost $80, compared with $87 in 2013. The all-in total per-ton cost of sales was $81, compared with almost $87 in 2013. TECO Coal recorded a $2.9 million income tax benefit in 2014, which included a $1.5 million tax depletion benefit, compared with a $1.0 million income tax benefit in the 2013 period.

Parent & other

The cost from continuing operations for Parent & other in the second quarter of 2014 was $12.1 million, compared with a cost of $7.6 million in the same period in 2013. Costs in 2014 included $2.7 million of costs associated with the pending acquisition of NMGC, compared with $1.8 million of NMGC related costs in 2013. Results in 2014 reflect lower results at the smaller unregulated companies reported in Parent & other and less favorable tax adjustments compared to 2013.

The 2014 year-to-date cost from continuing operations was $23.3 million, compared with $15.0 million in the 2013 period. The 2014 year-to-date cost included $4.8 million of NMGC acquisition-related costs, compared with $1.8 million of NMGC acquisition-related costs in 2013. Other cost drivers in the 2014 year-to-date period were the same as in the second quarter.

53

2014 Guidance from Continuing Operations

TECO Energy expects the Florida regulated utility operations, net of Parent & other, to deliver earnings in a range between $1.00 and $1.05 in 2014, and expects consolidated 2014 earnings from continuing operations, excluding any non-GAAP charges or gains, in a range between $0.95 and $1.05. We now expect that the above 2014 guidance will be unchanged by the effects of the acquisition related financing activities and NMGC’s expected seasonally positive financial results for the remainder of 2014, assuming that the NMGC acquisition closes later in the third quarter.

TECO Energy expects earnings in 2014 to be driven by the factors discussed below.

Tampa Electric expects to earn in the middle of its authorized allowed ROE range of 9.25% to 11.25%, driven by approximately $50 million of higher base revenues in 2014 as a result of its September 2013 rate case settlement agreement. Based on year-to-date experience, it now expects slightly higher average customer growth of 1.6% and total retail energy sales growth about 0.5% lower than customer growth due to lower average customer usage. Operations and maintenance expenses are expected to be lower than 2013 actual amounts due to lower employee-related costs, lower storm-damage expense accruals and lower pension expense driven by higher discount rate assumptions, partially offset by increased expenses to operate the system and reliably serve customers. Depreciation expense is expected to be higher due to normal additions to facilities to serve customers.

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

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

TECO Coal expects 2014 sales of about 6.0 million tons, reflecting almost 70% specialty coal. Almost 90% of the expected second half sales tons are committed and priced, with the remainder subject to quarterly met coal price adjustments based on Asian benchmark prices. At prices currently being paid for its products, about $80 per ton, TECO Coal expects to be about earnings breakeven for the year, and cash-flow positive. However, the most recent quarterly Asian benchmark price is at levels below the level at which TECO Coal’s current prices were set. The all-in cost of sales is expected to be in a range between $79 and $83 per ton. The cash cost of sales, which excludes depreciation and allocated interest, is expected to be about $7 per ton below the all-in cost. In 2014, TECO Coal expects to continue to record tax depletion tax benefits.

Income Taxes

The provisions for income taxes from continuing operations for the six-month periods ended June 30, 2014 and 2013 were $61.1 million and $51.4 million, respectively. The provision for income taxes for the six months ended June 30, 2014 was impacted by TECO Energy’s higher taxable income and decreased depletion benefit at TECO Coal.

Environmental

EPA Proposal Regarding Carbon Emissions and Coal Plants

As previously described in our Annual Report on Form 10-K for the year ended December 31, 2013, in June 2013, President Obama announced his “Climate Action Plan,” a broad package of mostly administrative initiatives aimed at reducing GHG emissions by approximately 17% below 2005 levels by 2020. As part of the Climate Action Plan, the president directed the EPA to issue a draft rule for existing power plants by June 1, 2014, to finalize the rule by June 1, 2015, and to require states to submit implementation plans by June 30, 2016. In response to this directive, on June 2, 2014, the EPA released a comprehensive proposed rule, which it calls the “Clean Power Plan,” aiming to cut GHG emissions from existing power plants by an average across all states of 30% from their 2005 levels by 2030, with an interim goal for the period from 2020 through 2029. Under the proposed rule, each state would have to reduce carbon dioxide emissions on a state-wide basis by an amount specified by the EPA; the target amount was determined by the EPA’s view of each state’s options, including: making power plant efficiency upgrades; shifting from coal-fired to natural gas-fired generation; investing in zero- and low-emitting power sources, such as renewable and nuclear energy; and implementing customer energy efficiency programs. States will have a great deal of flexibility in designing programs to meet their emission reduction targets, including the four approaches noted above or any other measures they choose to adopt, for example, carbon tax and cap-and-trade. The EPA is scheduled to finalize the rule by June 1, 2015, and states will have until June 30, 2016, to submit plans to implement the finalized rule (subject to extension and EPA approval of the states’ plans). The outcome of this rule-making process and its impact on our businesses cannot be determined at this time; however, it could result in increased operating costs, decreased operations at Tampa Electric’s coal-fired plants, and decreased profitability at our coal mining and production subsidiary. See “Risk Factors—General Business and Operational Risks—Federal or state regulation of GHG emissions, depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales.”

54

Liquidity and Capital Resources

The table below sets forth the June 30, 2014 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/TECO Finance and TEC credit facilities.

At Jun 30, 2014 (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		0.7		0.7		0.0		0.0
Available credit facilities		674.3		474.3		0.0		200.0
Cash and short-term investments		167.0		55.2		5.4		106.4
Total liquidity	$	841.3	$	529.5	$	5.4	$	306.4

See Notes 17 and 18 for additional liquidity disclosures relating to the transactions for financing the acquisition of NMNG.

Covenants in Financing Agreements

In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At June 30, 2014, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at June 30, 2014. 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 Jun 30, 2014
TEC
Credit facility(2)	Debt/capital		Cannot exceed 65%	46.9%
Accounts receivable credit facility(2)	Debt/capital		Cannot exceed 65%	46.9%
6.25% senior notes	Debt/capital Limit on liens(3)		Cannot exceed 60% Cannot exceed $700	46.9% $0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	Debt/capital		Cannot exceed 65%	57.0%
TECO Finance 6.75% notes	Restrictions on secured debt(4)		(5)	(5)

(1) As defined in each applicable instrument.

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

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

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

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

Credit Ratings of Senior Unsecured Debt at June 30, 2014
	Standard & Poor’s	Moody’s	Fitch
TEC	BBB+	A2	A-
TECO Energy/TECO Finance	BBB	Baa1	BBB

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

On May 30, 2013, Fitch placed the rating of TECO Energy, TECO Finance and TEC on ratings watch negative following the announcement of our agreement to purchase NMGC. On Oct. 9, 2013, Fitch removed TEC from ratings watch negative and affirmed its ratings. S&P, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus, all three credit rating agencies assign TECO Energy, TECO Finance and TEC’s senior unsecured debt investment-grade credit ratings.

A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC’s

55

derivative instruments contain provisions that require TEC’s debt to maintain investment grade credit ratings (see Note 12 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.

Financing of Pending NMGC Acquisition

As previously disclosed, the purchase price for the acquisition of all the capital stock of NMGI, the parent company of NMGC (NMGC Acquisition), is $950 million including the assumption of $200 million of existing NMGC debt. To provide bridge financing for the NMGC Acquisition, TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement (Bridge Facility) on June 24, 2013, among TECO Energy as guarantor, TECO Finance as borrower, Morgan Stanley Senior Funding, Inc. (Morgan Stanley) as administrative agent, sole lead arranger and sole book runner, and Morgan Stanley together with nine other banks as lenders in the Bridge Facility. TECO Energy unconditionally guaranteed TECO Finance’s obligations under the Bridge Facility. The availability of funds under the Bridge Facility is subject to various conditions, including (i) the absence of a material adverse effect having occurred with respect to NMGC, (ii) the consummation of the NMGC Acquisition and (iii) other customary closing conditions.

TECO Energy expects to permanently finance the NMGC Acquisition with a combination of the proceeds from its recently completed equity offering, the issuance, concurrently with the closing of the NMGC Acquisition, of debt at NMGC and NMGI, cash on hand and short-term borrowings.

In July 2014, TECO Energy sold 15.5 million shares of its common stock in a follow-on public offering raising net proceeds of approximately $271 million. In addition, TECO Energy granted the underwriters an option for a period of 30 days ending July 31, 2014, to purchase an additional 2.3 million shares of common stock. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

TECO Energy plans to use the net proceeds from this offering to fund, in part, the acquisition of NMGC and for general corporate purposes. Following the closing of this offering, the commitment under the Bridge Facility was correspondingly reduced by $270 million.

On July 30, 2014, with TECO Energy’s consent, NMGC and NMGI each entered into a Note Purchase Agreement contemplating the issuance of $70 million and $200 million aggregate principal amount of notes, respectively, conditioned upon, and to be issued at, closing of the NMGC Acquisition. The issuance of the notes by NMGC is further conditioned upon the approval of the NMPRC. The proceeds from the new NMGC debt will be used to repay existing NMGC debt and the proceeds from the new NMGI debt will be used to retire existing NMGI debt, to fund the transaction, costs and expenses, and for general corporate purposes.

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 June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk.

Critical Accounting Policies and Estimates

The company’s critical accounting policies relate to deferred income taxes, employee postretirement benefits, long-lived assets and regulatory accounting. For further discussion of critical accounting policies, see TECO Energy, Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2013.

56

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in Fair Value of Derivatives

The change in fair value of derivatives is largely due to the increase in the average market price component of the company’s outstanding natural gas swaps of approximately 3% from Dec. 31, 2013 to June 30, 2014. For natural gas, the company maintained a similar volume hedged as of June 30, 2014 from Dec. 31, 2013.

The following tables summarize the changes in and the fair value balances of derivative assets (liabilities) for the six month period ended June 30, 2014:

Changes in Fair Value of Derivatives (millions)
Net fair value of derivatives as of Dec 31, 2013	$	9.7
Additions and net changes in unrealized fair value of derivatives		17.4
Changes in valuation techniques and assumptions		0.0
Realized net settlement of derivatives		(18.7	)
Net fair value of derivatives as of Jun 30, 2014	$	8.4
Roll-Forward of Derivative Net Assets (Liabilities) (millions)
Total derivative net liabilities as of Dec 31, 2013	$	9.7
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		17.4
Recorded in earnings		0.0
Realized net settlement of derivatives		(18.7	)
Net option premium payments		0.0
Net purchase (sale) of existing contracts		0.0
Net fair value of derivatives as of Jun 30, 2014	$	8.4

Below is a summary table of sources of fair value, by maturity period, for derivative contracts at June 30, 2014:

Maturity and Source of Derivative Contracts Net Assets (Liabilities) (millions)
Contracts Maturing in	Current		Non-current		Total Fair Value
Source of fair value
Actively quoted prices	$	0.0	$	0.0	$	0.0
Other external sources (1)		8.0		0.4		8.4
Model prices (2)		0.0		0.0		0.0
Total	$	8.0	$	0.4	$	8.4

⁽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.

57

Item 4. CONTROLS AND PROCEDURES

TECO Energy, Inc.

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

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

Tampa Electric Company

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

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

58

PART II. OTHER INFORMATION

Item 1A. RISK FACTORS

The following description of risk factors includes any material changes to, and supersedes the description of, risk factors associated with TECO Energy’s business, including the pending acquisition of NMGC, (the NMGC Acquisition) previously disclosed in Part I, Item 1A of TECO Energy’s 2013 Form 10-K under the heading “Risk Factors.” The business, financial condition and operating results of TECO Energy can be affected by a number of factors, whether currently known or unknown, including but not limited to those described below, any one or more of which could, directly or indirectly, cause TECO Energy’s actual results of operations and financial condition to vary materially from past, or from anticipated future, results of operations and financial condition. Any of these factors, in whole or in part, could materially and adversely affect TECO Energy’s business, financial condition, results of operations and common stock price.

The following discussion of risk factors contains forward-looking statements. These risk factors may be important to understanding any statement in this Form 10-Q or elsewhere. The following information should be read in conjunction with the condensed consolidated financial statements and related notes in Part I, Item 1, “Financial Statements” and Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q.

Risks Associated With the NMGC Acquisition

We will be subject to business uncertainties while the NMGC Acquisition is pending that could adversely affect our business and operations.

While the NMGC Acquisition is pending, we will be subject to a number of risks that could have an adverse effect on us, including:

our estimate of the costs to complete the NMGC Acquisition and the operating performance after the completion of the transaction may vary significantly from actual results;

both before and after the closing of the NMGC Acquisition, the attention of management is expected to be focused on closing the transaction and the subsequent integration of NMGC. During this period, the focus on current operations or the pursuit of other opportunities that could be beneficial to us may be reduced;

the potential loss of key employees of TECO Energy or NMGC who may be uncertain about their future roles if and when the NMGC Acquisition is completed; and

the trading price of our common stock may be adversely affected by speculation about the timing of the closing of the NMGC Acquisition.

The NMGC Acquisition may not be completed at all or on a timely basis, or regulatory approval may be subject to unfavorable conditions, which could have an adverse effect on us.

On May 14, 2014, we reached a settlement agreement with the New Mexico Industrial Energy Consumers, which represents large customers of NMGC, and the New Mexico Attorney General’s office, which represents New Mexico residential and small business customers, regarding the NMGC Acquisition. Under the terms of the settlement, among other elements of the stipulation, NMGC will freeze customer rates until the end of 2017 and limit job reductions in the first three years after the NMGC Acquisition. The NMPRC staff did not oppose the settlement, and on June 30, 2014, the NMPRC hearing examiner issued a certification of stipulation recommending that the NMPRC approve the transaction and related matters. The NMPRC still must decide whether to approve the NMGC acquisition, which decision we expect in the third quarter of 2014. If we do not receive the NMPRC’s final approval by September 25, 2014, however, the stock purchase agreement may be terminated by either party.

Failure to complete the NMGC acquisition could negatively affect our stock price as well as our future business and financial results.

If the NMGC acquisition is not completed, we will be subject to a number of risks, including: we must pay costs related to the NMGC acquisition, including legal, accounting, financial advisory, and filing costs, whether the transaction is completed or not; we could be subject to litigation related to the failure to complete the NMGC acquisition or other factors, which litigation may adversely affect our business, financial results and stock price; our management will have broad discretion in the application of the net proceeds from the recently completed equity offering and could spend the proceeds in ways that do not meet investor expectations. Furthermore, we would be subject to earnings per share dilution if we do not find other attractive investment opportunities or undertake other means to reduce our overall shares outstanding.

The NMGC Acquisition and associated costs and integration efforts may adversely affect our business, financial condition or results of operations, which may negatively affect the trading price of our common stock.

We expect the NMGC Acquisition to be accretive to earnings beginning twelve months after closing. The NMPRC

59

may not approve the transaction, or may impose terms or conditions on the approval, which could delay the completion of the transaction, impose additional costs, or otherwise affect the anticipated benefits of the transaction. In addition, the anticipated benefits of the transaction are based on estimates of transaction and integration-related costs, which are dependent on financial market conditions and other factors, which may materially change. Negative changes in these factors could have an adverse effect on the anticipated benefits of the transaction or our business, financial condition, results of operations or stock price. Further, following the consummation of the NMGC Acquisition, our ownership of NMGC will be subject to the regulation of the NMPRC and applicable New Mexico state laws governing utilities. Any subsequent sale of NMGC or incidental transfer of ownership through a change of control transaction in TECO Energy would be subject to applicable New Mexico regulatory approval requirements.

In order to finance the NMGC Acquisition, we plan to incur additional indebtedness, which could have an adverse effect on our financial health.

We currently expect to finance the NMGC Acquisition with a combination of the proceeds from the recently completed equity issuance, cash on hand and the issuance, concurrently with the closing of the NMGC Acquisition, of new debt at NMGC and NMGI, proceeds from which will primarily be used to retire certain debt of NMGC and NMGI in connection with the closing of the NMGC Acquisition, to fund the acquisition purchase, costs and expenses, and for general corporate purposes. Incurrence of additional debt may have an adverse effect on our financial condition and may limit our ability to obtain financing in the future. Furthermore, the recently completed issuance of our common stock has resulted in additional shares outstanding and may have an adverse effect on the market price of our common stock.

Additionally, if we fail to realize the expected benefits from the NMGC Acquisition or if the financial performance of NMGC does not meet our current expectations, it may have a negative effect on our financial profile. If we cannot obtain the additional permanent financing we expect, specifically the issuance of new debt at NMGC and NMGI, alternative financing under the Bridge Facility would be on less favorable financial terms. In that event, any debt incurred to replace or refinance the amounts under the Bridge Facility could also be under less favorable terms.

NMGC’s business is subject to many risks, including those attendant to being a regulated gas utility. Some of these risks are similar to those of our existing gas utility, and some are unique to New Mexico; NMGC’s business may be adversely affected by these risks, and additional risks may be identified after closing of the NMGC Acquisition.

NMGC is a highly regulated gas utility which could be adversely affected by a number of factors affecting such a business, such as changes in regulation or legislation or decisions by the NMPRC and the impact of environmental laws and regulations that may increase costs or have other adverse effects on the business; the potential for increased costs in natural gas or volatility in such prices which could reduce sales volumes or have other adverse effects on the business; general economic conditions nationally and in New Mexico affecting the market for natural gas; the inability of the company to renew rights-of-way or franchises for its transmission and distribution facilities on acceptable terms, which could increase costs; and weather-related risks to the business, such as warmer-than-normal weather conditions, or other factors such as global warming or climate change, which may result in reduced natural gas sales and lower profitability. Additional risk factors relating to this business may be identified after the closing of the NMGC Acquisition, if such closing occurs.

In connection with the NMGC Acquisition, we expect to record additional goodwill and long-lived assets that could become impaired and adversely impact our financial condition and results from operations.

We assess long-lived assets and goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of those assets below their carrying values. To the extent the value of goodwill or a long-lived asset becomes impaired, we may be required to record non-cash impairment charges that could have a material impact on results from operations.

Financing Risks

We have substantial indebtedness, which could adversely affect our financial condition and financial flexibility.

We have substantial indebtedness, which has resulted in fixed charges we are obligated to pay. The level of our indebtedness and restrictive covenants contained in our debt obligations could limit our ability to obtain additional financing.

TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements to use their respective credit facilities. Also, TECO Energy, TECO Finance, TEC and other operating companies have certain restrictive covenants in specific agreements and debt instruments. These restrictive covenants could further limit our ability to obtain additional financing.

As of June 30, 2014, we were in compliance with required financial covenants, but we cannot be assured that we will be in compliance with these financial covenants in the future. Our failure to comply with any of these covenants or to meet our payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. We may not have sufficient working capital or liquidity to satisfy our debt obligations in the event of an acceleration of all or a portion of our outstanding obligations.

60

We also incur obligations in connection with the operations of our subsidiaries and affiliates that do not appear on our balance sheet. These obligations take the form of guarantees, letters of credit and contractual commitments, as described under the “Liquidity, and Capital Resources” section of the “Management’s Discussion & Analysis of Financial Condition & Results of Operations” section of this quarterly report.

Financial market conditions could limit our access to capital and increase our costs of borrowing or refinancing, or have other adverse effects on our results.

The financial market conditions that were experienced in 2008 and early 2009 impacted access to both the short- and long-term capital markets and the cost of such capital. TECO Finance has debt maturing in 2015 which it expects to refinance. Future financial market conditions could limit our ability to raise the capital we need and could increase our interest costs, which could reduce earnings.

We enter into derivative transactions, primarily with financial institutions as counterparties. Financial market turmoil could lead to a sudden decline in credit quality among these counterparties, which could make in-the-money positions uncollectable.

We enter into derivative transactions with counterparties, most of which are financial institutions, to hedge our exposure to commodity price changes. Turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which we have an in-the-money position, we could be unable to collect from such counterparty.

Declines in the financial markets or in interest rates used to determine benefit obligations could increase our pension expense or the required cash contributions to maintain required levels of funding for our plan.

Under calculation requirements of the Pension Protection Act, as of the January 1, 2014, measurement date, the funded percentage of our plan was essentially fully funded. TECO Energy estimates its contributions to range from $5 million to $50 million annually over the next five years. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund our plan in the future.

We estimate that pension expense in 2014 will be lower than in 2013, primarily due to the higher interest rates and pension plan asset growth in 2013. Any future declines in the financial markets or decreases in interest rates, however could, cause pension expense to increase in future years.

Our financial condition and results could be adversely affected if our capital expenditures are greater than forecast.

We are forecasting capital expenditures at Tampa Electric to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability, to maintain coal-fired generating unit reliability and efficiency, and to add generating capacity at the Polk Power Station. We are forecasting capital expenditures at PGS to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel and cast iron pipe.

If our capital expenditures exceed the forecasted levels, we may need to draw on credit facilities or access the capital markets on unfavorable terms. We cannot be sure that we will be able to obtain additional financing, in which case our financial position could be adversely affected.

Our financial condition and ability to access capital may be materially adversely affected by multiple ratings downgrades to below investment grade, and we cannot be assured of any rating improvements in the future.

Our senior unsecured debt is rated as investment grade by S&P at BBB, by Moody’s Investor’s Services (Moody’s) at Baa1, and by Fitch Ratings (Fitch) at BBB. The senior unsecured debt of TEC is rated by S&P at BBB+, by Moody’s at A2 and by Fitch at A- . A downgrade to below investment grade by the rating agencies, which would require a two-notch downgrade by S&P and Fitch, and a three notch downgrade by Moody’s, may affect our ability to borrow, may change requirements for future collateral or margin postings, and may increase our financing costs, which may decrease our earnings. We may also experience greater interest expense than we may have otherwise if, in future periods, we replace maturing debt with new debt bearing higher interest rates due to any such downgrades. In addition, downgrades could adversely affect our relationships with customers and counterparties.

At current ratings, TEC is able to purchase electricity and gas without providing collateral. If the ratings of TEC decline to below investment grade, Tampa Electric and PGS could be required to post collateral to support their purchases of electricity and gas.

We are a holding company with no business operations of our own and depend on cash flow from our subsidiaries to meet our obligations.

61

We are a holding company with no business operations of our own or material assets other than the stock of our subsidiaries. Accordingly, all of our operations are conducted by our subsidiaries. As a holding company, we require dividends and other payments from our subsidiaries to meet our cash requirements. If our subsidiaries are unable to pay us dividends or make other cash payments to us, we may be unable to pay dividends or satisfy our obligations.

General Business and Operational Risks

General economic conditions may adversely affect our businesses.

Our businesses are affected by general economic conditions. In particular, growth in Tampa Electric’s service area and in Florida is important to the realization of annual energy sales growth for Tampa Electric and PGS.

Any weakening of economic conditions, including the Florida housing markets and general economy, could adversely affect Tampa Electric’s or PGS’s expected performance and their ability to collect payments from customers.

TECO Coal is also affected by general economic conditions affecting primarily the utility and steel industries, both nationally and internationally. TECO Coal sells metallurgical coal domestically and internationally, and demand for that product has varied due to economic conditions. Continued economic weakness and the resulting lower demand for metallurgical coal in the international markets could reduce TECO Coal’s financial results.

Our electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition.

Tampa Electric and PGS operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on Tampa Electric’s or PGS’s financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.

If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, the earnings could be subject to review by the FPSC which could result in refunds to customers or changes in allowed returns on equity, which could reduce earnings and cash flow.

Changes in the environmental laws and regulations affecting our businesses could increase our costs or curtail our activities.

Our businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on us or require us to curtail some of our businesses’ activities.

Proposed new regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs.

In response to a coal ash pond failure in December 2008 at another utility, the EPA proposed new regulations for the management and disposal of CCRs. These proposed rules include two potential approaches. One approach, known as Subtitle C, would categorize CCRs destined for disposal as hazardous wastes. This proposal could be the most significant for Tampa Electric because management and disposal of hazardous wastes is extremely expensive, and waste landfills are currently prohibited in Florida by state law. In addition, the hazardous designation could require improvements to Tampa Electric’s current ash management practices and interim storage and handling facilities for CCRs inside its power stations, even though permanent onsite disposal would not be allowed. The other proposed rule would set minimum standards for the final disposal of CCRs under regulations similar to those in place for municipal non-hazardous solid waste. This proposal would not be as disruptive as the former, since it would allow for the continued operation of ash impoundments on Tampa Electric’s facilities. However it is unclear whether this approach would place additional management requirements on these existing disposal units or cause them to need structural improvements. The EPA’s current schedule would result in a final proposed rule in 2015, although expected litigation would likely delay the rule’s effective date.

Federal or state regulation of GHG emissions, depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales.

Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions. While GHG emission regulations have been proposed, both at the federal and state level, none has been passed at this time and, therefore, costs to reduce GHGs are unknown. Presently there is no viable technology to remove CO ₂ post-combustion from conventional coal-fired units such as Tampa Electric’s Big Bend units. New rules requiring post-combustion CO ₂ removal could require significant investment in what is essentially experimental technology, costly conversion to natural gas fuel, or a premature shut-down of the units, which would result in non-cash write-offs.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for

62

compliance with new environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but we cannot be assured that the FPSC would grant such recovery.

In a June 25, 2013, memorandum, President Obama directed the EPA to issue new emissions standards for future power plants as well as modified, reconstructed or existing power plants to reduce GHG emissions. The new standards for future power plants were released in the fall of 2013, which essentially mandate that no new coal fired power plants will be constructed in the U.S. On June 2, 2014, the EPA released a comprehensive proposed rule which it calls the “Clean Power Plan,” aiming to cut GHG emissions from existing power plants by 30% from their 2005 levels by 2030, with an interim goal for the period from 2020 through 2029. Under the proposed rule, each state would have to reduce carbon dioxide emissions on a state-wide basis by an amount specified by the EPA; the target amount was determined by the EPA’s view of each state’s options, including: making power plant efficiency upgrades; shifting from coal to natural gas generation; investing in zero- and low-emitting power sources, such as renewable and nuclear energy; and implementing customer energy efficiency programs. Because the 30% reduction target is an average across all states, some states have higher or lower target emission reduction goals under the proposed rule than the average. Based on current emissions, Florida has a higher reduction goal than the average, of 38%. Under the proposed rules, states will have flexibility in designing programs to meet their emission reduction targets, including the four approaches noted above or any other measures they choose to adopt, for example, carbon tax and cap-and-trade. The EPA is scheduled to finalize the rule by June 1, 2015, and states will have until June 30, 2016, to submit plans to implement the finalized rule (subject to extension and EPA approval of the states’ plans). It is unclear whether Florida’s proposed implementation plan will take into consideration emission reductions achieved prior to 2005 or if that baseline year will be changed in the comment process. The 2005 baseline year does not take into consideration the significant reductions in greenhouse gas emissions we achieved prior to 2005 (a reduction of approximately five million tons since 1998). If the 2005 baseline year remains unchanged (which due to our previous reductions in greenhouse gas emissions was our lowest emitting year), it may be more difficult for us to achieve the proposed reductions than other utilities in a cost-effective manner, especially when compared to utilities in other states that have lower emission reduction targets under the proposed rules. It is expected that the rules will be subjected to litigation, which could have a material impact on both the timing and substance of the rules, and, therefore, the outcome of this rule-making process and its impact on our businesses cannot be determined at this time; however, it could result in increased operating costs, decreased operations at Tampa Electric’s coal-fired plants, and decreased profitability at our coal mining and production subsidiary. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, we cannot be assured that any increased costs associated with complying with those regulations will be eligible for such treatment.

In the case of TECO Coal, the use of coal to generate electricity is considered a significant source of GHG emissions. New regulations, depending on final form, could cause the consumption of coal to decrease or the cost of sales to increase, which could negatively impact TECO Coal’s earnings.

Among other rules, the EPA has proposed or finalized a number of new rules, including the CAIR/CSAPR and Hazardous Air Pollutants (“HAPS”) Maximum Achievable Control Technology (“MACT”) for emissions into the air, and a number of new rules focused on water use and discharges from power generation facilities.

Together these air-focused rules impose stringent reductions in several pollutants from electric utility steam generators, primarily coal-fired, but including oil-fired as well. If the CSAPR rule is implemented as planned, the EPA has estimated that the implementation of CSAPR would require significant investment in pollution-control equipment for units not already equipped or could result in the retirement of primarily smaller, older coal-fired power stations that do not currently have state-of-the-art air pollution-control equipment already installed. The retirement of these units or switching to other fuels for compliance with this rule is likely to reduce overall demand for coal, which could reduce sales and financial results at TECO Coal.

The EPA’s water-focused rules could limit the supply of water available to our power generating facilities, require the investment of significant capital for new equipment and increase operating costs.

A mandatory RPS could add to Tampa Electric’s costs and adversely affect its operating results.

In past sessions of the Florida legislature, an RPS was debated but ultimately not enacted, but an RPS standard could be enacted in the future. In addition, there is the potential that legislation could be proposed in the U.S. Congress to introduce an RPS at the federal level. It remains unclear, however, if or when action on such legislation would be completed. Tampa Electric could incur significant costs to comply with an RPS. Tampa Electric’s operating results could be adversely affected if Tampa Electric were not permitted to recover these costs from customers through the ECRC.

Tampa Electric, the state of Florida and the nation as a whole are increasingly dependent on natural gas to generate electricity. There may not be adequate infrastructure to deliver adequate quantities of natural gas to meet the expected future demand, and the expected higher demand for natural gas may lead to increasing costs for the commodity.

63

In Florida and across the United States, utilities are increasingly relying on natural gas for new electric generating plants in response to GHG emissions concerns and attractive natural gas prices. Currently, there is an adequate supply and infrastructure to meet demand for natural gas in Florida and nationally. However, if future supplies are inadequate or if significant new investment is required to install the pipelines necessary to transport the gas, the cost of natural gas could rise. Currently, Tampa Electric and PGS are allowed to pass the cost for the commodity gas and transportation services through to customers without profit. Changes in regulations could reduce earnings if they required Tampa Electric or PGS to bear a portion of the increased cost. In addition, increased costs to customers could result in lower sales.

Our businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations.

All of our businesses are affected by variations in general weather conditions and unusually severe weather. Tampa Electric’s and PGS’s energy sales are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

PGS, which has a typically short but significant winter peak period that is dependent on cold weather, is more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. Mild winter weather in Florida can negatively impact results at Tampa Electric and PGS.

Variations in weather conditions also affect the demand and prices for the commodities sold by TECO Coal. Severe weather conditions could interrupt or slow coal production or rail transportation and increase operating costs.

The state of Florida is exposed to extreme weather, including hurricanes, which can cause damage to our facilities and affect our ability to serve customers.

As a company with electric service and natural gas operations in peninsular Florida, we are exposed to extreme weather events, such as hurricanes. Extreme weather conditions can be destructive, causing outages and property damage that require us to incur additional expenses. Extensive customer outages could reduce revenue collections. If warmer temperatures lead to changes in extreme weather events (increased frequency, duration and severity), these expenses could be greater.

While we have storm preparation and recovery plans in place, and Tampa Electric and PGS have historically been granted regulatory approval to recover or defer the majority of significant storm costs incurred, extreme weather still poses risks to our operations and storm cost-recovery petitions may not always be granted or may not be granted in a timely manner. If costs associated with future severe weather events cannot be recovered in a timely manner, or in an amount sufficient to cover actual costs, our financial condition and operating results could be adversely affected.

Commodity price changes may affect the operating costs and competitive positions of our utility businesses.

All of our businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes could affect the prices these businesses charge, their operating costs and the competitive position of their products and services.

In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales and the margins earned on wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive position of PGS relative to electricity, other forms of energy and other gas suppliers.

Competition among coal producers in Central Appalachia and other producing regions, and low natural gas prices may adversely affect TECO Coal’s ability to sell steam coal. Low-cost natural gas has allowed utility steam coal users to switch from coal to natural gas to produce electricity, which has reduced the current market price and demand for TECO Coal’s steam coal from domestic utilities. Continued or further declines in natural gas prices and increased competition from lower cost producing areas would keep demand and selling prices low, which would reduce TECO Coal’s financial results, or reduce the value of its reserves.

TECO Coal has historically sold about 50% of its production to domestic utilities for use in the generation of power. For over three years, natural gas prices have been dramatically lower than previous averages due to the growth of hydraulic fracturing in the production of natural gas from shale formations. These low natural gas prices have caused utility coal users to switch to lower cost natural gas to generate electricity. Even with the increase in natural gas prices as occurred in the first half

64

of 2014, it remains more cost effective for users of higher cost Central Appalachian coal, which TECO Coal produces, to burn a higher percentage of natural gas for power generation. Lower cost coals from other producing regions of the U.S., such as the Powder River Basin and the Illinois Basin are being utilized by more utilities in lieu of higher cost Central Appalachian coals, further reducing demand.

At the end of 2013, more than 50% of TECO Coal’s profitable steam coal contracts expired and current market prices for Central Appalachian steam coal are not profitable. Without an increase in the cost of natural gas and an increase in the use of coal for power generation, or a general improvement in coal market conditions, TECO Coal’s financial results will be reduced. If these conditions were to persist or decline further, the value of TECO Coal’s reserves could be reduced, which could result in a non-cash impairment charge.

Results at our utility companies may be affected by changes in customer energy-usage patterns, and the cost of complying with potential new environmental regulations.

For the past several years, weather-normalized energy consumption per residential customer declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, trends toward smaller single family houses and increased multi-family housing.

Forecasts by our utility companies are based on normal weather patterns and historical trends in customer energy-usage patterns. The utilities’ ability to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency of lights and appliances, economic conditions or other factors.

Compliance with proposed GHG emissions reductions, a mandatory RPS or other new regulation could raise Tampa Electric’s cost. While current regulation allows Tampa Electric to recover the cost of new environmental regulation through the ECRC, increased costs for electricity may cause customers to change usage patterns, which would impact Tampa Electric’s sales.

Our computer systems and the infrastructure of our utility companies may be subject to cyber (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems, or adversely affect our business and financial results and condition.

There have been an increasing number of cyber-attacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the Internet, through malware, viruses, or attachments to e-mails or through persons inside of the organization or through persons with access to systems inside of the organization.

We have security systems and infrastructure in place that are designed to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, we cannot be assured that a cyber-attack will not cause electric or gas system operational problems, disruptions of service to customers, compromise important data or systems, or subject us to additional regulation, litigation or damage to our reputation.

There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of our utility companies are designed and operated in such a manner to mitigate the impact of this type of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair any damage. These types of events, either impacting our facilities or the industry in general, could also cause us to incur additional security- and insurance-related costs, and could have adverse effects on our business and financial results and condition.

We rely on some transmission and distribution assets that we do not own or control to deliver wholesale electricity, and natural gas. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver electricity and natural gas may be hindered.

We depend on transmission and distribution facilities owned and operated by other utilities and energy companies to deliver the electricity and natural gas we sell to the wholesale and retail markets, as well as the natural gas we purchase for use in our electric generation facilities. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual and service obligations may be hindered.

The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities. Likewise, unexpected interruption in upstream natural gas supply or transmission could affect our ability to generate power or deliver natural gas to local distribution customers.

65

The value of our existing deferred tax benefits are determined by existing tax laws, and could be negatively impacted by changes in these laws.

“Comprehensive tax reform” remains a topic of discussion in the U.S. congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would reduce the value of our existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and reduce future cash flow at the parent company.

The current administration in Washington D.C. has proposed the elimination of the percentage depletion tax deduction for the mining of coal, and other hard minerals and fossil fuels.

If the percentage depletion tax deduction is eliminated for TECO Coal, the effective tax rate for that company would rise from the historical 20% to 25% to the general corporate tax rate of 37%, which would reduce earnings from TECO Coal.

Impairment testing of certain long-lived assets could result in impairment charges.

We evaluate our long-lived assets for impairment annually or more frequently if certain triggering events occur. Should the current carrying values of any of these assets not be recoverable, we would incur non-cash charges to write down the assets to fair market value. For example, annually and upon a triggering event, we are required to conduct a review of TECO Coal’s long-lived assets to determine whether any of the assets have become impaired. In addition, to the extent that we enter into any agreement to sell TECO Coal that has a purchase price below its book value, we would be required to incur an impairment charge, which could be material to our financial statements.

Problems with operations could cause us to incur substantial costs.

Each of our subsidiaries is subject to various operational risks, including accidents, equipment failures and operations below expected levels of performance or efficiency. Our subsidiaries could incur problems such as the breakdown or failure of power generation equipment, transmission lines, pipelines, coal mining or processing equipment or other equipment or processes that would result in performance below assumed levels of output or efficiency. The occurrence of one or more of these problems could cause us to incur substantial costs, including potential claims for damages that may exceed the scope of our insurance coverage, which could have an adverse impact on our financial condition and results from operations.

Failure to obtain the permits necessary to open new surface mines, or challenges to the validity of existing permits, could reduce earnings from TECO Coal.

Our surface coal mining operations are dependent on permits from the USACE to open new surface mines necessary to maintain or increase production. Since 2008, new permits issued by the USACE under Section 404 of the Clean Water Act for new surface coal mining operations have been challenged in court by various environmental groups, resulting in very few usable permits being issued. Failure to obtain the necessary permits to open new surface mines, which are required to maintain and expand production, could reduce production, cause higher mining costs or require purchasing coal at prices above our cost of production to fulfill contract requirements, which would reduce the earnings expected from TECO Coal.

Challenges to existing permits that disrupt mining operations could result in higher costs if operations are forced to move to other mining sites or if coal is purchased from third parties, which would reduce the earnings expected from TECO Coal.

In 2010, the EPA issued new guidelines related to water quality for Central Appalachian coal surface mining operations that would be conditions of new surface mine permits, which would add significant cost to operations or curtail our surface mining activities and preparation plant operations.

In 2010, the EPA issued new guidance on environmental permitting requirements for Central Appalachian mountaintop removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis. In 2011, the EPA made this guidance final. Because the EPA’s standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well. In 2012, the United States District Court for the District of Columbia ruled that the EPA had exceeded its statutory authority in establishing the water quality guidance discussed above in the manner in which it was done. Following the outcome of this court decision, pending appeals by the EPA, few, if any, new usable permits have been issued by the USACE. Over time, if new permits are not issued, TECO Coal could incur higher production costs or reduced production from surface mining operations.

TECO Coal’s sales to international customers are subject to risks that could result in losses or increased costs.

TECO Coal is exposed to financial risk through its sales to international customers primarily in Asia. TECO Coal attempts to mitigate this risk through the use of third parties to broker the sales, dollar-denominated contracts, passage of title upon loading in the U.S. port, customer responsibility for the international freight, letters of credit posted by customers for purchase price of the commodity and the transportation to the U.S. port, and the utilization of local agents where appropriate.

66

TECO Coal cannot be assured that these measures will effectively mitigate all international risks, which could have an adverse effect on TECO Coal’s financial conditions.

In 2014, TECO Coal has a higher percentage of its metallurgical coal sales committed to customers in Asia than in recent years. Prices for metallurgical coal sales to Asia are subject to being reset on a quarterly basis based on supply and demand in the region. Over the past two years the quarterly prices have been lower due to increased supply from Australia and other suppliers and weakening demand for metallurgical coal from China. Lower quarterly prices could reduce TECO Coal’s profitability below levels forecast for 2014.

Increased customer use of distributed generation could adversely affect our regulated electric utility business.

In many areas of the country there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Additionally, the EPA’s proposed “Clean Power Plan” rule, if enacted as proposed, could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule. See “Federal or state regulation of GHG emissions” above, depending on how they are enacted, could increase our costs or the rates charged to our customers, which could curtail sales.

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

Potential competitive changes may adversely affect our regulated electric and gas businesses.

There is competition in wholesale power sales across the country. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

The gas distribution industry has been subject to competitive forces for several years. Gas services provided by PGS are unbundled for all non-residential customers. Because PGS earns margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted PGS’s results. However, future structural changes that we cannot predict could adversely affect PGS.

From time to time, we are a party to legal proceedings that may result in a material adverse effect on our financial condition.

From time to time, we are a party to, or otherwise involved in, lawsuits, claims, proceedings, investigations and other legal matters that have arisen in the ordinary course of conducting our business. While the outcome of these lawsuits, claims, proceedings, investigations and other legal matters which we are a party to, or otherwise involved in, cannot be predicted with certainty, an adverse outcome could result in a material adverse effect on our financial condition.

67

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

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

	Total Number of Shares (or Units) Purchased (1)		Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
Apr. 1, 2014 – Apr. 30, 2014		504	$	17.66		0.0	$	0.0
May 1, 2014 – May 31, 2014		61,612	$	17.90		0.0	$	0.0
June 1, 2014 – June 30, 2014		510	$	17.80		0.0	$	0.0
Total 2nd Quarter 2014		62,626	$	17.90		0.0	$	0.0

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

Item 4. MINE SAFETY INFORMATION

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

Item 6. EXHIBITS

Exhibits - See index on page 70.

68

SIGNATURES

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

	TECO ENERGY, INC.
	(Registrant)
Date: August 1, 2014	By:	/s/  S. W. CALLAHAN
		S. W. CALLAHAN
		Senior Vice President-Finance and Accounting       and Chief Financial Officer (Chief Accounting Officer)       (Principal Financial and Accounting Officer)
	TAMPA ELECTRIC COMPANY
	(Registrant)

Date: August 1, 2014	By:	/s/  S. W. CALLAHAN
		S. W. CALLAHAN
		Vice President-Finance and Accounting       and Chief Financial Officer (Chief Accounting Officer)       (Principal Financial and Accounting Officer)

69

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).	*
4.1	Eleventh Supplemental Indenture dated as of May 12, 2014, between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing the Indenture dated as of July 1, 1998, as amended (including the form of 4.35% notes due 2044) (Exhibit 4.27, Form 8-K dated May 15, 2014).	*
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.

70

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)	6-months ended June 30, 2014		12-months ended June 30, 2014		Year Ended Dec. 31,
					2013		2012		2011		2010			2009
Income from continuing operations, before income taxes	$	166.5	$	329.0	$	306.7	$	383.8	$	393.5	$	321.2		$	268.3
Add:
Interest expense		88.8		175.8		176.1		189.6		202.4		221.5			223.4
Deduct:
Income from equity investments, net		0.0		0.0		0.0		0.0		0.0		(2.8	)		(0.6	)
Earnings before taxes and fixed charges	$	255.3	$	504.8	$	482.8	$	573.4	$	595.9	$	545.5		$	492.3
Interest expense	$	88.8	$	175.8	$	176.1	$	189.6	$	202.4	$	221.5		$	223.4
Total fixed charges	$	88.8	$	175.8	$	176.1	$	189.6	$	202.4	$	221.5		$	223.4
Ratio of earnings to fixed charges		2.88x		2.87x		2.74x		3.02x		2.94x		2.46x			2.20x

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

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

EX-12.2

Exhibit 12.2

TAMPA ELECTRIC COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

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

(millions)	6-months ended June 30, 2014		12-months ended June 30, 2014		Year Ended Dec. 31,
					2013		2012		2011		2010		2009
Income from continuing operations, before income taxes	$	207.2	$	402.6	$	364.4	$	368.9	$	380.7	$	386.6	$	303.7
Interest expense		56.2		112.3		112.7		129.9		141.9		143.9		141.2
Earnings before taxes and fixed charges	$	263.4	$	514.9	$	477.1	$	498.8	$	522.6	$	530.5	$	444.9
Interest expense	$	56.2	$	112.3	$	112.7	$	129.9	$	141.9	$	143.9	$	141.2
Total fixed charges	$	56.2	$	112.3	$	112.7	$	129.9	$	141.9	$	143.9	$	141.2
Ratio of earnings to fixed charges		4.69x		4.59x		4.23x		3.84x		3.68x		3.69x		3.15x

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

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, John B. Ramil, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 1, 2014	/s/ J. B. RAMIL
	J. B. RAMIL
	President, Chief Executive Officer and Director
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 1, 2014	/s/ S.W. CALLAHAN
	S.W. CALLAHAN
	Senior Vice President-Finance and Accounting and Chief     Financial Officer (Chief Accounting Officer)     (Principal Financial and Accounting Officer)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, John B. Ramil, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 1, 2014	/s/ J. B. RAMIL
	J. B. RAMIL
	President, Chief Executive Officer and Director     (Principal Executive Officer)

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 1, 2014	/s/ S. W. CALLAHAN
	S. W. CALLAHAN
	Vice President-Finance and Accounting and Chief Financial     Officer (Chief Accounting Officer)     (Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

TECO ENERGY, INC

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of TECO Energy, Inc. (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended June 30, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	August 1, 2014	/s/ J. B. RAMIL
			J. B. RAMIL
			President, Chief Executive Officer and Director  (Principal Executive Officer)
Date:	August 1, 2014	/s/ S. W. CALLAHAN
			S. W. CALLAHAN
			Senior Vice President-Finance and Accounting and Chief  Financial Officer (Chief Accounting Officer)  (Principal Financial and Accounting Officer)

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

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

EX-32.2

Exhibit 32.2

TAMPA ELECTRIC COMPANY

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

Each of the undersigned officers of Tampa Electric Company (the “Company”) certifies, under the standards set forth in and solely for the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Quarterly Report on Form 10-Q of the Company for the quarter ended June 30, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	August 1, 2014	/s/ J. B. RAMIL
			J. B. RAMIL
			President, Chief Executive Officer and Director  (Principal Executive Officer)
Date:	August 1, 2014	/s/ S. W. CALLAHAN
			S. W. CALLAHAN
			Vice President-Finance and Accounting  and Chief Financial Officer  (Chief Accounting Officer)  (Principal Financial and Accounting Officer)

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

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

EX-95

Exhibit 95

MINE SAFETY DISCLOSURE

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

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

Exhibit 95

For the quarter ended June 30, 2014 (1)(2)
Mine ID #	Section 104 Significant & Substantial Citations		Section 104(b) Orders		Section 104(d) Citations and Orders		Section 110(b)(2) Violations		Section 107(a) Orders		Proposed MSHA Assessments (in thousands)		Fatalities		Pending Legal Actions (3)(4)		Legal Actions Initiated During Period (3)(4)		Legal Actions Resolved During Period (3)(4)
Clintwood Elkhorn
15-16734(5)		0		0		0		0		0	$	0.0		0		3		0		0
15-19396		0		0		0		0		0		0.0		0		0		0		0
44-03010		6		0		0		0		0		1.7		0		1		1		1
40-07199		0		0		0		0		0		0.0		0		4		0		0
YGX(6)		0		0		0		0		0		0.0		0		3		0		0
Totals		6		0		0		0		0	$	1.7		0		11		1		1
Perry County
15-05485		1		0		0		0		0	$	0.0		0		5		0		2
15-18565(7)		3		0		0		0		0		5.6		0		35		22		19
15-18662		3		0		0		0		0		3.1		0		40		1		1
15-19015(7)		7		0		0		0		0		12.0		0		56		13		14
Totals		14		0		0		0		0	$	20.7		0		136		36		36
Premier Elkhorn
15-16470		2		0		0		0		0	$	1.1		0		0		0		0
15-18823		0		0		0		0		0		8.1		0		9		1		0
15-18946		1		0		0		0		0		0.0		0		0		0		0
15-19622		1		0		0		0		0		0.9		0		0		0		0
15-19649		0		0		0		0		0		0.0		0		0		0		0
15-19721		2		0		0		0		0		0.0		0		0		0		0
A906(8)		0		0		0		0		0		0.0		0		0		0		0
Totals		6		0		0		0		0	$	10.1		0		9		1		0
Grand Totals		26		0		0		0		0	$	32.5		0		156		38		37

1. Based on data obtained from MSHA Mine Data Retrieval System as of July 2, 2014 for the 2nd quarter of 2014.

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

3. All of the 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 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. Three vacated citations that were shown “In Contest” in the previous quarterly report are no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

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

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

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

XML

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014 Tampa Electric Company [Member]	Jun. 30, 2013 Tampa Electric Company [Member]	Jun. 30, 2014 Tampa Electric Company [Member]	Jun. 30, 2013 Tampa Electric Company [Member]	Jun. 30, 2014 Unbilled Revenues [Member]	Dec. 31, 2013 Unbilled Revenues [Member]	Jun. 30, 2014 Unbilled Revenues [Member] Tampa Electric Company [Member]	Dec. 31, 2013 Unbilled Revenues [Member] Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues									$ 57.0	$ 46.7	$ 57.0	$ 46.7
Franchise fees and gross receipts taxes	$ 27.8	$ 26.7	$ 55.0	$ 52.1	$ 27.8	$ 26.7	$ 55.0	$ 52.1

XML

Earnings Per Share - Schedule of Earnings Per Share (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Basic earnings per share
Net income from continuing operations	$ 58.4	$ 51.6	$ 105.4	$ 92.8
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.4)	(0.3)
Income before discontinued operations available to common shareholders - Basic	58.2	51.4	105.0	92.5
Income (Loss) from discontinued operations, net	0	(0.2)	3.1	0.1
Amount allocated to nonvested participating shareholders	0	0	0	0
Income (Loss) from discontinued operations available to common shareholders - Basic	0	(0.2)	3.1	0.1
Net income	58.4	51.4	108.5	92.9
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.4)	(0.3)
Net income available to common shareholders - Basic	58.2	51.2	108.1	92.6
Average common shares outstanding - Basic	215.4	215.0	215.3	214.8
Earnings per share from continuing operations available to common shareholders - Basic	$ 0.27	$ 0.24	$ 0.49	$ 0.43
Earnings per share from discontinued operations available to common shareholders - Basic	$ 0.00	$ 0.00	$ 0.01	$ 0.00
Earnings per share - Basic	$ 0.27	$ 0.24	$ 0.50	$ 0.43
Diluted earnings per share
Net income from continuing operations	58.4	51.6	105.4	92.8
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.4)	(0.3)
Income before discontinued operations available to common shareholders - Diluted	58.2	51.4	105.0	92.5
Income (Loss) from discontinued operations, net	0	(0.2)	3.1	0.1
Amount allocated to nonvested participating shareholders	0	0	0	0
Income (Loss) from discontinued operations available to common shareholders - Diluted	0	(0.2)	3.1	0.1
Net income	58.4	51.4	108.5	92.9
Amount allocated to nonvested participating shareholders	(0.2)	(0.2)	(0.4)	(0.3)
Net income available to common shareholders - Diluted	$ 58.2	$ 51.2	$ 108.1	$ 92.6
Unadjusted average common shares outstanding - Diluted	215.4	215.0	215.3	214.8
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net	0.5	0.5	0.5	0.5
Average common shares outstanding - Diluted	215.9	215.5	215.8	215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$ 0.27	$ 0.24	$ 0.49	$ 0.43
Earnings per share from discontinued operations available to common shareholders - Diluted	$ 0.00	$ 0.00	$ 0.01	$ 0.00
Earnings per share - Diluted	$ 0.27	$ 0.24	$ 0.50	$ 0.43
Anti-dilutive shares	0	0	0	0

XML

Short-Term Debt - Credit Facilities (Parenthetical) (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit facility maturity date	Dec. 17, 2018	Dec. 17, 2018

XML

Discontinued Operations - Components of Discontinued Operations (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
(Loss) Income from discontinued operations	$ 0	$ (0.2)	$ 5.0	$ 0.2
Less: Provision for income taxes	0	0	1.9	0.1
(Loss) Income from discontinued operations, net	0	(0.2)	3.1	0.1
TECO Guatemala [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	0	0	0	0
(Loss) Income from operations	0	(0.2)	5.0	0.2
(Loss) Income from discontinued operations	0	(0.2)	5.0	0.2
Less: Provision for income taxes	0	0	1.9	0.1
(Loss) Income from discontinued operations, net	$ 0	$ (0.2)	$ 3.1	$ 0.1

XML

Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended	6 Months Ended
	Dec. 19, 2013	Jun. 30, 2014
Site Contingency [Line Items]
Duration of annulment proceedings		2 years
TECO Guatemala Holdings, LLC v. The Republic of Guatemala [Member]
Site Contingency [Line Items]
litigation settlement expenses	$ 21.1
litigation settlement interest		U.S. prime rate plus 2%
litigation settlement amount	7.5
Settlement agreement payment term		120 days after the date of the Award
PGS [Member]
Site Contingency [Line Items]
Ultimate financial liability to superfund sites and former MGP sites		35.9
PGS [Member] | Tampa Electric Company [Member]
Site Contingency [Line Items]
Ultimate financial liability to superfund sites and former MGP sites		$ 35.9

XML

Employee Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA			7.25%
Contributions to pension plan			$ 26.5
Reclassification of AOCI to net income as part of periodic benefit expense	0.7		1.3
Reclassification of regulatory assets to net income as part of periodic benefit expense	2.7		5.2
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term EROA			7.25%
Contributions to pension plan			21.5
Reclassification of regulatory assets to net income as part of periodic benefit expense	2.7		5.2
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.118%		5.118%
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.118%		5.118%
Contributions to pension plan			26.5
Net pension expense	3.9	5.6	7.7	10.9
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.096%		5.096%
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.096%		5.096%
Net pension expense	$ 2.6	$ 2.4	$ 5.2	$ 5.0

XML

Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

	For the three months ended Jun 30,						For the six months ended Jun 30,
(millions, except per share amounts)	2014			2013			2014			2013
Basic earnings per share
Net income from continuing operations	$	58.4		$	51.6		$	105.4		$	92.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Income before discontinued operations available to common shareholders - Basic	$	58.2		$	51.4		$	105.0		$	92.5
Income (Loss) from discontinued operations, net	$	0.0		($	0.2	)	$	3.1		$	0.1
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (Loss) from discontinued operations available to common shareholders - Basic	$	0.0		($	0.2	)	$	3.1		$	0.1
Net income	$	58.4		$	51.4		$	108.5		$	92.9
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Net income available to common shareholders - Basic	$	58.2		$	51.2		$	108.1		$	92.6
Average common shares outstanding - Basic		215.4			215.0			215.3			214.8
Earnings per share from continuing operations available to common shareholders - Basic	$	0.27		$	0.24		$	0.49		$	0.43
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.00		$	0.00		$	0.01		$	0.00
Earnings per share available to common shareholders - Basic	$	0.27		$	0.24		$	0.50		$	0.43
Diluted earnings per share
Net income from continuing operations	$	58.4		$	51.6		$	105.4		$	92.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Income before discontinued operations available to common shareholders - Diluted	$	58.2		$	51.4		$	105.0		$	92.5
Income (Loss) from discontinued operations, net	$	0.0		($	0.2	)	$	3.1		$	0.1
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (Loss) from discontinued operations available to common shareholders - Diluted	$	0.0		($	0.2	)	$	3.1		$	0.1
Net income	$	58.4		$	51.4		$	108.5		$	92.9
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Net income available to common shareholders - Diluted	$	58.2		$	51.2		$	108.1		$	92.6
Unadjusted average common shares outstanding - Diluted		215.4			215.0			215.3			214.8
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.5			0.5			0.5
Average common shares outstanding - Diluted		215.9			215.5			215.8			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.27		$	0.24		$	0.49		$	0.43
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.00		$	0.00		$	0.01		$	0.00
Earnings per share available to common shareholders - Diluted	$	0.27		$	0.24		$	0.50		$	0.43
Anti-dilutive shares		0.0			0.0			0.0			0.0

XML

Subsequent Events - Additional Information (Detail) (Subsequent Event [Member], USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended		1 Months Ended
	Jul. 01, 2014 Underwriter [Member]	Jul. 01, 2014 Underwriter [Member]	Jul. 30, 2014 NMGC [Member]	Jul. 30, 2014 NMGI [Member]
Subsequent Event [Line Items]
Number of shares issued through underwriting agreement	15,500,000
Shares offered, price per share		$ 18.10
Additional shares to be offered under underwriting agreement		2,300,000
Number of days option granted to underwriters	30 days
Proceeds from issuance to underwriters		$ 21
Underwriters exercised this option for an additional, shares		1,200,000
Net proceeds from offering through the underwriting	271
Proceeds from issuance of public offering			$ 70	$ 200

XML

Segment Information - Schedule of Segment Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 726.3	$ 735.9	$ 1,410.4	$ 1,397.0
Depreciation and amortization	84.2	83.9	169.1	165.9
Total interest charges	42.2	42.7	83.3	85.1
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	34.4	28.2	61.1	51.4
Net income (loss) from continuing operations	58.4	51.6	105.4	92.8
Income from discontinued operations, net	0	(0.2)	3.1	0.1
Net income	58.4	51.4	108.5	92.9
Total assets	7,620.8		7,620.8		7,448.0
Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	1.9	2.8	4.1	6.1
Depreciation and amortization	0.4	0.4	0.9	0.7
Total interest charges	14.0	14.4	28.2	28.3
Internally allocated interest	(1.5)	(1.7)	(3.0)	(3.3)
Provision (benefit) for income taxes	(6.8)	(7.4)	(13.7)	(12.6)
Net income (loss) from continuing operations	(12.1)	(7.6)	(23.3)	(15.0)
Income from discontinued operations, net	0	(0.2)	3.1	0.1
Net income	(12.1)	(7.8)	(20.2)	(14.9)
Total assets	(58.5)		(58.5)		(16.4)
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	726.3	735.9	1,410.4	1,397.0
Revenues - External [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	2.5	3.6	5.2	7.1
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0	0	0
Sales to Affiliates [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	(0.6)	(0.8)	(1.1)	(1.0)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	512.7	502.9	965.9	920.9
Depreciation and amortization	61.7	60.8	123.8	119.8
Total interest charges	23.3	23.3	45.3	46.7
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	37.1	31.5	63.7	51.3
Net income (loss) from continuing operations	62.2	50.6	107.4	82.4
Income from discontinued operations, net	0	0	0	0
Net income	62.2	50.6	107.4	82.4
Total assets	6,311.9		6,311.9		6,126.9
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	512.5	502.6	965.4	920.4
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.2	0.3	0.5	0.5
People Gas [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	91.1	101.8	213.7	223.7
Depreciation and amortization	13.4	13.2	26.7	26.2
Total interest charges	3.4	3.3	6.8	6.7
Internally allocated interest	0	0	0	0
Provision (benefit) for income taxes	4.8	5.0	14.0	13.7
Net income (loss) from continuing operations	7.5	7.9	22.1	21.7
Income from discontinued operations, net	0	0	0	0
Net income	7.5	7.9	22.1	21.7
Total assets	1,034.1		1,034.1		1,021.2
People Gas [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	90.7	101.3	213.1	223.2
People Gas [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.4	0.5	0.6	0.5
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	120.6	128.4	226.7	246.3
Depreciation and amortization	8.7	9.5	17.7	19.2
Total interest charges	1.5	1.7	3.0	3.4
Internally allocated interest	1.5	1.7	3.0	3.3
Provision (benefit) for income taxes	(0.7)	(0.9)	(2.9)	(1.0)
Net income (loss) from continuing operations	0.8	0.7	(0.8)	3.7
Income from discontinued operations, net	0	0	0	0
Net income	0.8	0.7	(0.8)	3.7
Total assets	333.3		333.3		316.3
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	120.6	128.4	226.7	246.3
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0	0	0
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues	603.3	604.1	1,178.8	1,143.9
Depreciation and amortization	75.1	74.0	150.5	146.0
Total interest charges	26.7	26.6	52.1	53.4
Provision (benefit) for income taxes	41.9	36.5	77.7	65.0
Net income	69.7	58.5	129.5	104.1
Total assets	7,051.9	6,875.8	7,051.9	6,875.8	6,875.8
Tampa Electric Company [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(0.5)	(0.6)	(0.8)	(0.7)
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	(12.4)	(8.9)	(12.4)	(8.9)
Tampa Electric Company [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues	603.3	604.1	1,178.8	1,143.9
Tampa Electric Company [Member] | Revenues - External [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	0	0	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0	0	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	(0.5)	(0.6)	(0.8)	(0.7)
Tampa Electric Company [Member] | Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	512.7	502.9	965.9	920.9
Depreciation and amortization	61.7	60.8	123.8	119.8
Total interest charges	23.3	23.3	45.3	46.7
Provision (benefit) for income taxes	37.1	31.5	63.7	51.3
Net income	62.2	50.6	107.4	82.4
Total assets	6,061.9	5,895.4	6,061.9	5,895.4
Tampa Electric Company [Member] | Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	512.6	502.8	965.7	920.7
Tampa Electric Company [Member] | Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	0.1	0.1	0.2	0.2
Tampa Electric Company [Member] | People Gas [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	91.1	101.8	213.7	223.7
Depreciation and amortization	13.4	13.2	26.7	26.2
Total interest charges	3.4	3.3	6.8	6.7
Provision (benefit) for income taxes	4.8	5.0	14.0	13.7
Net income	7.5	7.9	22.1	21.7
Total assets	1,002.4	989.3	1,002.4	989.3
Tampa Electric Company [Member] | People Gas [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	90.7	101.3	213.1	223.2
Tampa Electric Company [Member] | People Gas [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates	$ 0.4	$ 0.5	$ 0.6	$ 0.5

XML

Asset Impairments - Additional Information (Detail) (TECO Coal [Member], USD $)	6 Months Ended
	Jun. 30, 2014
TECO Coal [Member]
Asset Impairment Charges [Line Items]
Impairment charge	$ 0
Forecast period	20 years
Impaired assets recoverability threshold percentage	15.00%

XML

Asset Impairments

6 Months Ended

Jun. 30, 2014

Goodwill And Intangible Assets Disclosure [Abstract]

Asset Impairments

16. Asset Impairments

The company accounts for long-lived asset impairments in accordance with the accounting guidance for long-lived assets, which requires that long-lived assets held and used be tested for recoverability whenever events or changes in circumstances indicate that its carrying value may not be recoverable, and assets held for sale be recorded at the lower of its carrying amount or fair value less cost to sell. An asset is considered not recoverable if its carrying value exceeds the sum of its undiscounted expected cash flows. If it is determined that the carrying value is not recoverable and its carrying value exceeds its fair value, an impairment charge is made and the value of the asset is reduced to its fair value.

In 2014, the benchmark price for coal significantly fell from what was used in the long-lived asset impairment testing that was done for TECO Coal in 2013. Additionally, the company is currently in active discussions with potential buyers of TECO Coal; however, no agreement or understanding with respect to any sale has been reached, nor has the company’s board of directors made a determination regarding whether the company would sell TECO Coal based on current indications of value. These indications suggest that a sale price above book value may be unlikely at this time. Although there can be no assurances that a sale of TECO Coal will be completed and TECO Coal is not considered an asset held for sale, the company felt that these factors, coupled together, caused a triggering event requiring impairment testing of TECO Coal in the second quarter of 2014.

The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. A 20-year forecast was developed based on proven and probable reserves, prices using current average coal benchmark prices as a pricing base, and costs using current average costs. A market recovery was assumed for prices and increased costs that moved in line with the prices were factored into the forecast. The book value of TECO Coal’s long-lived assets (including capitalized mine development costs) was determined to be recoverable; therefore, no impairment charge was deemed necessary. Additionally, due to the uncertainty in the soft coal market, the company performed sensitivity analyses on revenues and noted that if revenues declined 15 percent from forecast, all assets would still be recoverable.

XML

Long-Term Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified			6 Months Ended		0 Months Ended	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member]	May 15, 2014 Tampa Electric Company [Member] 4.35% Notes [Member]	Jun. 30, 2014 Tampa Electric Company [Member] 4.35% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount	$ 3,137.6	$ 2,921.1	$ 2,097.2	$ 1,880.8
Estimated fair value	3,469.6	3,184.1	2,329.6	2,042.0
Aggregate principal amount issued					300
Interest at the initial term rate per annum					4.35%
Debt instrument principal amount market price percentage					99.933%
Proceeds from notes net of issuance					$ 296.6
Redeemable principal amount percentage					100.00%
Libor interest rate						15
Issuance of notes, maturity year					Jan. 01, 2044
Debt instrument, maturity year					2044
Debt instrument, stated interest rate					4.35%
Debt instrument, redemption price percentage					100.00%
Discount rate, basis points to be added			0.50%		0.15%
Debt instrument, start date of redemption					Nov. 15, 2043
Debt instrument, offering date					May 15, 2014

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Parenthetical) (Detail)	6 Months Ended
	Jun. 30, 2014
Schedule Of Regulatory Assets And Liabilities [Line Items]
Amortization period	5-year
Tampa Electric Company [Member]
Schedule Of Regulatory Assets And Liabilities [Line Items]
Amortization period	5-year

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2014

Schedule of Recurring Fair Value Measurements

For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Jun 30, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	8.6	$	0.0	$	8.6
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	8.7	$	0.0	$	8.7
Liabilities
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Diesel fuel swaps		0.0		0.0		0.0		0.0
Total	$	0.0	$	0.3	$	0.0	$	0.3
	At fair value as of Dec 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Diesel fuel swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	10.0	$	0.0	$	10.0
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.3	$	0.0	$	0.3

Tampa Electric Company [Member]

Schedule of Recurring Fair Value Measurements

For all assets and liabilities presented below, the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Jun 30, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	8.6	$	0.0	$	8.6
Total	$	0.0	$	8.6	$	0.0	$	8.6
Liabilities
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Total	$	0.0	$	0.3	$	0.0	$	0.3
	At fair value as of Dec 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Total	$	0.0	$	9.8	$	0.0	$	9.8
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2

XML

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	$ (7.5)	$ (7.8)
Total accumulated other comprehensive loss	(20.1)	(13.2)
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	(7.6)	(7.8)
Total accumulated other comprehensive loss	(7.6)	(7.8)
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension loss and prior service credit	(19.7)	(20.5)
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit loss, prior service cost and transition obligation	$ 7.1	$ 15.1

XML

Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	$ 8.7	$ 10.0
Total Swap Liabilities	0.3	0.3
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.7	10.0
Total Swap Liabilities	0.3	0.3
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	0	0.1
Tampa Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Tampa Electric Company [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Tampa Electric Company [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] | Tampa Electric Company [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	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	8.7	10.0
Total Swap Liabilities	0.3	0.3
Level 2 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Level 2 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.1	0.2
Total Swap Liabilities	0	0.1
Level 2 [Member] | Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Level 2 [Member] | Tampa Electric Company [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Tampa Electric Company [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] | Tampa Electric Company [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	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	Jun. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	$ 9.9	$ 10.5
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	(1.5)	(0.8)
Derivative assets, Gross Amounts offset on the Balance Sheet	(1.2)	(0.5)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	1.2	0.5
Derivative assets, Net Amounts of Assets	8.7	10.0
Derivative assets, Net Amounts of Liabilities	(0.3)	(0.3)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	9.8	10.3
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	(1.5)	(0.7)
Derivative assets, Gross Amounts offset on the Balance Sheet	(1.2)	(0.5)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	1.2	0.5
Derivative assets, Net Amounts of Assets	8.6	9.8
Derivative assets, Net Amounts of Liabilities	$ (0.3)	$ (0.2)

XML

Short-Term Debt - Credit Facilities (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Feb. 14, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Credit Facilities	$ 675.0		$ 675.0
Borrowings Outstanding	0		84.0
Letters of Credit Outstanding	0.7		0.7
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit Facilities	475.0		475.0
Borrowings Outstanding	0		84.0
Letters of Credit Outstanding	0.7		0.7
Tampa Electric Company [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	325.0		325.0
Borrowings Outstanding	0		6.0
Letters of Credit Outstanding	0.7		0.7
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	150.0	150.0	150.0
Borrowings Outstanding	0		78.0
Letters of Credit Outstanding	0		0
TECO Energy [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	200.0		200.0
Borrowings Outstanding	0		0
Letters of Credit Outstanding	$ 0		$ 0

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Franchise fees and gross receipts taxes	$ 27.8	$ 26.7	$ 55.0	$ 52.1
Tampa Electric Company [Member]
Franchise fees and gross receipts taxes	27.8	26.7	55.0	52.1
Tampa Electric Company [Member] | Electric [Member]
Franchise fees and gross receipts taxes	22.7	21.5	43.0	40.5
Tampa Electric Company [Member] | Gas [Member]
Franchise fees and gross receipts taxes	$ 5.1	$ 5.2	$ 12.0	$ 11.6

XML

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Hedging Instruments (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current liabilities	$ 0.2	$ 0.1
Long-term derivative liabilities	0.1	0.2
Total derivatives designated as hedging instruments	0.3	0.3
Current assets	8.2	9.7
Long-term derivative assets	0.5	0.3
Total assets	8.7	10.0
Current liabilities	(33.7)	(34.3)
Long-term derivative liabilities	283.9	293.1
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0	0.1
Long-term derivative liabilities	0	0
Total derivatives designated as hedging instruments	0	0.1
Current assets	0.1	0.2
Long-term derivative assets	0	0
Total assets	0.1	0.2
Derivatives Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Total derivatives designated as hedging instruments	0.3	0.3
Total assets	8.7	10.0
Derivatives Designated as Hedging Instruments [Member] | Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0	0.1
Long-term derivative liabilities	0	0
Current assets	0.1	0.2
Long-term derivative assets	0	0
Derivatives Designated as Hedging Instruments [Member] | Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0.2
Long-term derivative liabilities	0.1
Current assets	8.1	9.5
Long-term derivative assets	0.5	0.3
Current liabilities		0
Long-term derivative liabilities		$ 0.2

XML

Regulatory - Regulatory Assets and Related Recovery Periods (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory assets	$ 317.6	$ 327.4
Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	317.6	327.4
Clause Recoverable [Member]
Regulatory Assets [Line Items]
Regulatory assets	4.6	10.2
Clause Recoverable [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	4.6	10.2
Regulatory Tax Asset [Member]
Regulatory Assets [Line Items]
Regulatory assets	68.1	67.4
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	68.1	67.4
Capital Structure and Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	64.2	64.2
Capital Structure and Other [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	64.2	64.2
Components of Rate Base [Member]
Regulatory Assets [Line Items]
Regulatory assets	180.7	185.6
Components of Rate Base [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 180.7	$ 185.6

XML

Regulatory (Tables)

6 Months Ended

Jun. 30, 2014

Schedule of Regulatory Assets and Regulatory Liabilities

Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun 30, 2014		Dec 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	68.1	$	67.4
Other:
Cost-recovery clauses		1.8		6.1
Postretirement benefit asset		177.6		182.7
Deferred bond refinancing costs (2)		7.6		8.0
Environmental remediation		52.0		51.4
Competitive rate adjustment		2.8		4.1
Other		7.7		7.7
Total other regulatory assets		249.5		260.0
Total regulatory assets		317.6		327.4
Less: Current portion		33.7		34.3
Long-term regulatory assets	$	283.9	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.6	$	9.8
Other:
Cost-recovery clauses		34.8		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.4		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		588.4		594.0
Total other regulatory liabilities		681.5		707.4
Total regulatory liabilities		687.1		717.2
Less: Current portion		65.7		85.8
Long-term regulatory liabilities	$	621.4	$	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	Jun 30,		Dec 31,
(millions)	2014		2013
Clause recoverable (1)	$	4.6	$	10.2
Components of rate base (2)		180.7		185.6
Regulatory tax assets (3)		68.1		67.4
Capital structure and other (3)		64.2		64.2
Total	$	317.6	$	327.4

(1) To be recovered through cost-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 June 30, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun 30, 2014		Dec 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	68.1	$	67.4
Other:
Cost-recovery clauses		1.8		6.1
Postretirement benefit asset		177.6		182.7
Deferred bond refinancing costs (2)		7.6		8.0
Environmental remediation		52.0		51.4
Competitive rate adjustment		2.8		4.1
Other		7.7		7.7
Total other regulatory assets		249.5		260.0
Total regulatory assets		317.6		327.4
Less: Current portion		33.7		34.3
Long-term regulatory assets	$	283.9	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.6	$	9.8
Other:
Cost-recovery clauses		34.8		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.4		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		588.4		594.0
Total other regulatory liabilities		681.5		707.4
Total regulatory liabilities		687.1		717.2
Less: Current portion		65.7		85.8
Long-term regulatory liabilities	$	621.4	$	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	Jun 30,		Dec 31,
(millions)	2014		2013
Clause recoverable (1)		$4.6		$10.2
Components of rate base (2)		180.7		185.6
Regulatory tax assets (3)		68.1		67.4
Capital structure and other (3)		64.2		64.2
Total	$	317.6	$	327.4

(1) To be recovered through cost-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.

XML

Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2014

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

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 June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three months and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

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.

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 June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

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.

XML

Commitments and Contingencies - Letters of Credit and Guarantees (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014
Guarantor Obligations [Line Items]
2014	$ 0
2015-2018	0.7
After 2018	96.9
Total	97.6
Liabilities Recognized at Jun 30, 2014	0.7
Tampa Electric Company [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Jun 30, 2014	0.1
Tampa Electric Company [Member] | Letters of Credit [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Jun 30, 2014	0.1
TECO Coal [Member] | Fuel Purchase Related [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	0.7
After 2018	4.0
Total	4.7
Liabilities Recognized at Jun 30, 2014	0.6
Other Subsidiaries [Member] | Fuel Purchase / Energy Management [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	0
After 2018	92.9
Total	92.9
Liabilities Recognized at Jun 30, 2014	$ 0.1

XML

Income Taxes - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Income Taxes [Line Items]
Income tax examination period	1 year
Effective tax rate	36.71%	35.64%
Tampa Electric Company [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Income tax examination period	1 year
Minimum [Member]
Income Taxes [Line Items]
Statutes of limitations	3 years
Maximum [Member]
Income Taxes [Line Items]
Statutes of limitations	4 years

XML

Employee Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2014

Compensation And Retirement Disclosure [Abstract]

Schedule of Net Periodic Benefit Cost

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Jun 30,	2014			2013			2014			2013
Components of net periodic benefit expense
Service cost	$	4.2		$	4.3		$	0.6		$	0.5
Interest cost on projected benefit obligations		8.2			7.2			2.6			2.4
Expected return on assets		(10.4	)		(9.5	)		0.0			0.0
Amortization of:
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		(0.1	)
Actuarial loss		3.5			5.3			0.1			0.2
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	7.2		$	3.2		$	3.0
Six months ended Jun 30,
Components of net periodic benefit expense
Service cost	$	8.3		$	9.1		$	1.2		$	1.2
Interest cost on projected benefit obligations		16.4			14.4			5.2			4.7
Expected return on assets		(20.7	)		(19.2	)		0.0			0.0
Amortization of:
Prior service (benefit) cost		(0.2	)		(0.2	)		(0.1	)		(0.2	)
Actuarial loss		6.7			10.3			0.1			0.5
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income	$	10.5		$	14.4		$	6.4		$	6.2

XML

Short-Term Debt (Tables)

6 Months Ended

Jun. 30, 2014

Short-Term Debt Credit Facilities

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Jun 30, 2014						Dec 31, 2013
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		78.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	0.7	$	675.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

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

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

Tampa Electric Company [Member]

Short-Term Debt Credit Facilities

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Jun 30, 2014						Dec. 31, 2013
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		78.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

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

XML

Consolidated Condensed Statements of Income and Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenues
Total revenues	$ 726.3	$ 735.9	$ 1,410.4	$ 1,397.0
Expenses
Fuel	169.7	174.5	319.3	314.5
Purchased power	19.9	20.5	38.1	35.1
Cost of natural gas sold	29.1	40.7	76.2	90.2
Other	126.8	129.6	247.4	250.4
Depreciation and amortization	84.2	83.9	169.1	165.9
Taxes, other than income	55.1	53.6	111.4	106.9
Total expenses	593.1	616.4	1,164.1	1,173.4
Income from operations	133.2	119.5	246.3	223.6
Other income
Allowance for other funds used during construction	2.0	1.4	4.4	2.5
Total other income	1.8	3.0	3.5	5.7
Interest charges
Interest on long-term debt	42.9	43.5	85.4	86.5
Allowance for borrowed funds used during construction	(0.7)	(0.8)	(2.1)	(1.4)
Total interest charges	42.2	42.7	83.3	85.1
Income before provision for income taxes	92.8	79.8	166.5	144.2
Provision for income taxes	34.4	28.2	61.1	51.4
Net income	58.4	51.4	108.5	92.9
Other comprehensive income, net of tax
Total other comprehensive income, net of tax	0.6	0.6	(6.9)	1.7
Comprehensive income	59.0	52.0	101.6	94.6
Tampa Electric Company [Member]
Revenues
Electric (includes franchise fees and gross receipts taxes of $22.7 in 2014 and $21.5 in 2013)	512.7	502.8	965.7	920.7
Gas (includes franchise fees and gross receipts taxes of $12.0 in 2014 and $11.6 in 2013)	90.6	101.3	213.1	223.2
Total revenues	603.3	604.1	1,178.8	1,143.9
Expenses
Fuel	169.7	174.5	319.3	314.5
Purchased power	19.9	20.5	38.1	35.1
Cost of natural gas sold	29.0	40.9	76.2	90.4
Other	126.8	129.5	247.1	250.1
Depreciation and amortization	75.1	74.0	150.5	146.0
Taxes, other than income	47.6	45.8	95.0	90.3
Total expenses	468.1	485.2	926.2	926.4
Income from operations	135.2	118.9	252.6	217.5
Other income
Allowance for other funds used during construction	2.0	1.4	4.4	2.5
Other income, net	1.1	1.3	2.3	2.5
Total other income	3.1	2.7	6.7	5.0
Interest charges
Interest on long-term debt	26.4	26.4	52.1	52.9
Other interest	1.0	1.0	2.1	1.9
Allowance for borrowed funds used during construction	(0.7)	(0.8)	(2.1)	(1.4)
Total interest charges	26.7	26.6	52.1	53.4
Income before provision for income taxes	111.6	95.0	207.2	169.1
Provision for income taxes	41.9	36.5	77.7	65.0
Net income	69.7	58.5	129.5	104.1
Other comprehensive income, net of tax
Amortization of settled interest rate swaps	0	0.2	0.2	0.4
Total other comprehensive income, net of tax	0	0.2	0.2	0.4
Comprehensive income	$ 69.7	$ 58.7	$ 129.7	$ 104.5

XML

Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2014

Other Comprehensive Income

TECO Energy reported the following OCI for the three and six months ended June 30, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Jun 30,									Six months ended Jun 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2014
Unrealized gain on cash flow hedges	$	0.1		$	0.0		$	0.1		$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.1			(0.1	)		0.0			0.5			(0.2	)		0.3
Gain on cash flow hedges		0.2			(0.1	)		0.1			0.5			(0.2	)		0.3
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5			1.6			(0.6	)		1.0
Increase in unrecognized postemployment costs(3)		0.0			0.0			0.0			(12.9	)		4.7			(8.2	)
Total other comprehensive income (loss)	$	1.0		($	0.4	)	$	0.6		($	10.8	)	$	3.9		($	6.9	)
2013
Unrealized loss on cash flow hedges	($	0.7	)	$	0.3		($	0.4	)	($	0.4	)	$	0.2		($	0.2	)
Reclassification from AOCI to net income (1)		0.5			(0.2	)		0.3			0.8			(0.3	)		0.5
(Loss) Gain on cash flow hedges		(0.2	)		0.1			(0.1	)		0.4			(0.1	)		0.3
Amortization of unrecognized benefit costs (2)		1.1			(0.4	)		0.7			2.2			(0.8	)		1.4
Total other comprehensive income	$	0.9		($	0.3	)	$	0.6		$	2.6		($	0.9	)	$	1.7

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

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

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

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Jun 30, 2014			Dec 31, 2013
Unrecognized pension loss and prior service credit (1)	($	19.7	)	($	20.5	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		7.1			15.1
Net unrealized losses from cash flow hedges (3)		(7.5	)		(7.8	)
Total accumulated other comprehensive loss	($	20.1	)	($	13.2	)

(1) Net of tax benefit of $12.1 million and $12.6 million as of June 30, 2014 and Dec. 31, 2013, respectively.

(2) Net of tax expense of $4.4 million and $9.1 million as of June 30, 2014 and Dec. 31, 2013, respectively.

(3) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

Other Comprehensive Income	Three months ended June 30,							Six months ended June 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2014
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.0		0.0			0.0		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.0		0.0			0.0		0.4		(0.2	)		0.2
Total other comprehensive income	$	0.0	$	0.0		$	0.0	$	0.4	($	0.2	)	$	0.2
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		0.7		(0.3	)		0.4
Gain on cash flow hedges		0.4		(0.2	)		0.2		0.7		(0.3	)		0.4
Total other comprehensive income	$	0.4	($	0.2	)	$	0.2	$	0.7	($	0.3	)	$	0.4

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions)	Jun 30, 2014			Dec 31, 2013
Net unrealized losses from cash flow hedges (1)	($	7.6	)	($	7.8	)
Total accumulated other comprehensive loss	($	7.6	)	($	7.8	)

(1) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

XML

Regulatory - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Storm damage reserve	$ 687.1	$ 717.2
Tampa Electric Company [Member]
Annual accrual storm damage reserve	8.0
Storm damage reserve	687.1	717.2
Tampa Electric Company [Member] | Transmission and Delivery Storm Reserve [Member]
Storm damage reserve	$ 56.1	$ 56.1
Storm damage cost recovery period	12 months

XML

Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 4.7	$ 4.9
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	12.1	12.6
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other benefit loss, prior service cost (credit) and transition obligation, tax expense (benefit)	4.4	9.1
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 4.7	$ 4.9

XML

Pending Acquisition of New Mexico Gas Company - Additional Information (Detail) (Subsequent Event [Member], USD $) In Millions, unless otherwise specified	1 Months Ended
	Jul. 30, 2014
NMGC [Member]
Business Acquisition [Line Items]
Proceeds from issuance of notes	$ 70
NMGI [Member]
Business Acquisition [Line Items]
Proceeds from issuance of notes	$ 200

XML

Consolidated Condensed Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 167.0	$ 185.2
Receivables, less allowance for uncollectibles	323.8	287.2
Inventories, at average cost
Derivative assets	8.2	9.7
Regulatory assets	33.7	34.3
Deferred income taxes	87.7	100.3
Prepayments and other current assets	47.5	34.9
Income tax receivables	0.8	1.5
Total current assets	889.5	857.7
Property, plant and equipment
Construction work in progress	494.9	386.7
Other property	441.5	448.3
Property, plant and equipment, at original costs	9,202.5	9,077.3
Accumulated depreciation	(2,878.4)	(2,907.2)
Total property, plant and equipment, net	6,324.1	6,170.1
Other assets
Regulatory assets	283.9	293.1
Derivative assets	0.5	0.3
Deferred charges and other assets	122.8	126.8
Total other assets	407.2	420.2
Total assets	7,620.8	7,448.0
Current liabilities
Long-term debt due within one year	274.5	83.3
Notes payable	0	84.0
Accounts payable	232.3	261.7
Customer deposits	167.5	164.5
Regulatory liabilities	65.7	85.8
Derivative liabilities	0.2	0.1
Interest accrued	34.4	31.9
Taxes accrued	68.2	34.6
Other	18.4	19.5
Total current liabilities	861.2	765.4
Other liabilities
Deferred income taxes	497.4	444.0
Investment tax credits	9.2	9.4
Regulatory liabilities	621.4	631.4
Derivative liabilities	0.1	0.2
Deferred credits and other liabilities	422.0	426.1
Long-term debt, less amount due within one year	2,863.1	2,837.8
Total other liabilities	4,413.2	4,348.9
Commitments and contingencies (see Note 10)
Capital
Common equity	217.8	217.3
Additional paid in capital	1,587.8	1,581.3
Retained earnings	560.9	548.3
Accumulated other comprehensive loss	(20.1)	(13.2)
Total capital	2,346.4	2,333.7
Total liabilities and capital	7,620.8	7,448.0
Fuel [Member]
Inventories, at average cost
Utility inventories	137.4	118.7
Materials and supplies [Member]
Inventories, at average cost
Utility inventories	83.4	85.9
Electric [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	6,941.7	6,934.0
Gas [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	1,324.4	1,308.3
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	55.2	9.8
Receivables, less allowance for uncollectibles	256.7	227.6
Inventories, at average cost
Derivative assets	8.1	9.5
Regulatory assets	33.7	34.3
Deferred income taxes	20.4	29.4
Prepayments and other current assets	21.2	12.5
Income tax receivables	0	54.9
Total current assets	568.4	548.5
Property, plant and equipment
Construction work in progress	493.4	385.3
Property, plant and equipment, at original costs	8,700.7	8,568.8
Accumulated depreciation	(2,530.9)	(2,562.6)
Public utilities, property, plant and equipment, net	6,169.8	6,006.2
Other property	8.4	8.3
Total property, plant and equipment, net	6,178.2	6,014.5
Other assets
Unamortized debt expense	17.1	14.8
Regulatory assets	283.9	293.1
Derivative assets	0.5	0.3
Deferred charges and other assets	305.3	312.8
Other	3.8	4.6
Total assets	7,051.9	6,875.8
Current liabilities
Long-term debt due within one year	83.3	83.3
Notes payable	0	84.0
Accounts payable	198.2	226.0
Customer deposits	167.5	164.5
Regulatory liabilities	65.7	85.8
Derivative liabilities	0.2	0
Interest accrued	18.6	16.4
Taxes accrued	57.8	12.2
Other	12.1	12.0
Total current liabilities	603.4	684.2
Other liabilities
Deferred income taxes	1,145.1	1,114.3
Investment tax credits	9.2	9.4
Regulatory liabilities	621.4	631.4
Derivative liabilities	0.1	0.2
Other	293.4	308.1
Long-term debt, less amount due within one year	2,013.9	1,797.5
Total other liabilities	2,069.2	2,063.4
Commitments and contingencies (see Note 10)
Capital
Common equity	2,047.4	2,030.4
Retained earnings	325.6	308.1
Accumulated other comprehensive loss	(7.6)	(7.8)
Total capital	2,365.4	2,330.7
Total capitalization	4,379.3	4,128.2
Total liabilities and capital	7,051.9	6,875.8
Tampa Electric Company [Member] | Fuel [Member]
Inventories, at average cost
Utility inventories	98.7	93.7
Tampa Electric Company [Member] | Materials and supplies [Member]
Inventories, at average cost
Utility inventories	74.4	76.8
Tampa Electric Company [Member] | Electric [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	6,941.7	6,934.0
Tampa Electric Company [Member] | Gas [Member]
Property, plant and equipment
Public utilities, property, plant and equipment	$ 1,265.6	$ 1,249.5

XML

Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4.2	$ 4.3	$ 8.3	$ 9.1
Interest cost on projected benefit obligations	8.2	7.2	16.4	14.4
Expected return on assets	(10.4)	(9.5)	(20.7)	(19.2)
Amortization of:
Prior service (benefit) cost	(0.1)	(0.1)	(0.2)	(0.2)
Actuarial loss	3.5	5.3	6.7	10.3
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	5.4	7.2	10.5	14.4
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0.6	0.5	1.2	1.2
Interest cost on projected benefit obligations	2.6	2.4	5.2	4.7
Expected return on assets	0	0	0	0
Amortization of:
Prior service (benefit) cost	(0.1)	(0.1)	(0.1)	(0.2)
Actuarial loss	0.1	0.2	0.1	0.5
Net pension expense recognized in the TECO Energy Consolidated Condensed Statements of Income	$ 3.2	$ 3.0	$ 6.4	$ 6.2

XML

Consolidated Condensed Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net income	$ 58.4	$ 51.4	$ 108.5	$ 92.9
Other comprehensive income, net of tax
Net unrealized gains (losses) on cash flow hedges	0.1	(0.1)	0.3	0.3
Amortization of unrecognized benefit costs	0.5	0.7	1.0	1.4
Increase in unrecognized postemployment costs	0	0	(8.2)	0
Other comprehensive income (loss), net of tax	0.6	0.6	(6.9)	1.7
Comprehensive income	$ 59.0	$ 52.0	$ 101.6	$ 94.6

XML

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current assets	$ 8.2	$ 9.7
Long-term assets	0.5	0.3
Total assets	8.7	10.0
Current liabilities	0.2	0.1
Long-term liabilities	0.1	0.2
Total liabilities	0.3	0.3
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	8.1	9.5
Long-term assets	0.5	0.3
Current liabilities	0.2	0
Long-term liabilities	0.1	0.2
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	8.1	9.5
Long-term assets	0.5	0.3
Total assets	8.6	9.8
Current liabilities	0.2	0
Long-term liabilities	0.1	0.2
Total liabilities	0.3	0.2
Natural Gas Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	8.1	9.5
Long-term assets	0.5	0.3
Total assets	8.6	9.8
Current liabilities	0.2	0
Long-term liabilities	0.1	0.2
Total liabilities	0.3	0.2
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.1	0.2
Long-term assets	0	0
Total assets	0.1	0.2
Current liabilities	0	0.1
Long-term liabilities	0	0
Total liabilities	$ 0	$ 0.1

XML

Segment Information (Tables)

6 Months Ended

Jun. 30, 2014

Schedule of Segment Information

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

Segment Information (1)
(millions) Three months ended Jun 30,	Tampa Electric		Peoples Gas		TECO Coal			Other & Eliminations			TECO Energy
2014
Revenues - external	$	512.5	$	90.7	$	120.6		$	2.5		$	726.3
Sales to affiliates		0.2		0.4		0.0			(0.6	)		0.0
Total revenues		512.7		91.1		120.6			1.9			726.3
Depreciation and amortization		61.7		13.4		8.7			0.4			84.2
Total interest charges(1)		23.3		3.4		1.5			14.0			42.2
Internally allocated interest (1)		0.0		0.0		1.5			(1.5	)		0.0
Provision (benefit) for income taxes		37.1		4.8		(0.7	)		(6.8	)		34.4
Net income (loss) from continuing operations		62.2		7.5		0.8			(12.1	)		58.4
Income from discontinued operations, net		0.0		0.0		0.0			0.0			0.0
Net income (loss)	$	62.2	$	7.5	$	0.8		($	12.1	)	$	58.4
2013
Revenues - external	$	502.6	$	101.3	$	128.4		$	3.6		$	735.9
Sales to affiliates		0.3		0.5		0.0			(0.8	)		0.0
Total revenues		502.9		101.8		128.4			2.8			735.9
Depreciation and amortization		60.8		13.2		9.5			0.4			83.9
Total interest charges(1)		23.3		3.3		1.7			14.4			42.7
Internally allocated interest (1)		0.0		0.0		1.7			(1.7	)		0.0
Provision (benefit) for income taxes		31.5		5.0		(0.9	)		(7.4	)		28.2
Net income (loss) from continuing operations		50.6		7.9		0.7			(7.6	)		51.6
Income from discontinued operations, net		0.0		0.0		0.0			(0.2	)		(0.2	)
Net income (loss)	$	50.6	$	7.9	$	0.7		($	7.8	)	$	51.4
(millions) Six months ended Jun 30,	Tampa Electric		Peoples Gas		TECO Coal			Other & Eliminations			TECO Energy
2014
Revenues - external	$	965.4	$	213.1	$	226.7		$	5.2		$	1,410.4
Sales to affiliates		0.5		0.6		0.0			(1.1	)		0.0
Total revenues		965.9		213.7		226.7			4.1			1,410.4
Depreciation and amortization		123.8		26.7		17.7			0.9			169.1
Total interest charges(1)		45.3		6.8		3.0			28.2			83.3
Internally allocated interest (1)		0.0		0.0		3.0			(3.0	)		0.0
Provision (benefit) for income taxes		63.7		14.0		(2.9	)		(13.7	)		61.1
Net income (loss) from continuing operations		107.4		22.1		(0.8	)		(23.3	)		105.4
Income from discontinued operations, net		0.0		0.0		0.0			3.1			3.1
Net income (loss)	$	107.4	$	22.1	$	(0.8	)	$	(20.2	)	$	108.5
2013
Revenues - external	$	920.4	$	223.2	$	246.3		$	7.1		$	1,397.0
Sales to affiliates		0.5		0.5		0.0			(1.0	)		0.0
Total revenues		920.9		223.7		246.3			6.1			1,397.0
Depreciation and amortization		119.8		26.2		19.2			0.7			165.9
Total interest charges(1)		46.7		6.7		3.4			28.3			85.1
Internally allocated interest (1)		0.0		0.0		3.3			(3.3	)		0.0
Provision (benefit) for income taxes		51.3		13.7		(1.0	)		(12.6	)		51.4
Net income (loss) from continuing operations		82.4		21.7		3.7			(15.0	)		92.8
Income from discontinued operations, net		0.0		0.0		0.0			0.1			0.1
Net income (loss)	$	82.4	$	21.7	$	3.7		$	(14.9	)	$	92.9
At Jun 30, 2014
Total assets	$	6,311.9	$	1,034.1	$	333.3		($	58.5	)	$	7,620.8
At Dec. 31, 2013
Total assets	$	6,126.9	$	1,021.2	$	316.3		($	16.4	)	$	7,448.0

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2013 through June 2014 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

Tampa Electric Company [Member]

Schedule of Segment Information

(millions) Three months ended Jun 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2014
Revenues - external	$	512.6	$	90.7	$	0.0		$	603.3
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Total revenues		512.7		91.1		(0.5	)		603.3
Depreciation and amortization		61.7		13.4		0.0			75.1
Total interest charges		23.3		3.4		0.0			26.7
Provision for income taxes		37.1		4.8		0.0			41.9
Net income	$	62.2	$	7.5	$	0.0		$	69.7
2013
Revenues - external	$	502.8	$	101.3	$	0.0		$	604.1
Sales to affiliates		0.1		0.5		(0.6	)		0.0
Total revenues		502.9		101.8		(0.6	)		604.1
Depreciation and amortization		60.8		13.2		0.0			74.0
Total interest charges		23.3		3.3		0.0			26.6
Provision for income taxes		31.5		5.0		0.0			36.5
Net income	$	50.6	$	7.9	$	0.0		$	58.5
Six months ended Jun 30,
2014
Revenues - external	$	965.7	$	213.1	$	0.0		$	1,178.8
Sales to affiliates		0.2		0.6		(0.8	)		0.0
Total revenues		965.9		213.7		(0.8	)		1,178.8
Depreciation and amortization		123.8		26.7		0.0			150.5
Total interest charges		45.3		6.8		0.0			52.1
Provision for income taxes		63.7		14.0		0.0			77.7
Net income	$	107.4	$	22.1	$	0.0		$	129.5
Total assets at Jun 30, 2014	$	6,061.9	$	1,002.4	($	12.4	)	$	7,051.9
2013
Revenues - external	$	920.7	$	223.2	$	0.0		$	1,143.9
Sales to affiliates		0.2		0.5		(0.7	)		0.0
Total revenues		920.9		223.7		(0.7	)		1,143.9
Depreciation and amortization		119.8		26.2		0.0			146.0
Total interest charges		46.7		6.7		0.0			53.4
Provision for income taxes		51.3		13.7		0.0			65.0
Net income	$	82.4	$	21.7	$	0.0		$	104.1
Total assets at Dec 31, 2013	$	5,895.4	$	989.3	($	8.9	)	$	6,875.8

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Activity for Instruments Classified as Qualifying Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	$ 0.1	$ (1.1)	$ 0.1	$ (1.1)
Amount of Gain/(Loss) Recognized in OCI	0.1	(0.4)	0	(0.2)
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0	(0.3)	(0.3)	(0.5)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0.1	(1.1)	0.1	(1.1)
Amount of Gain/(Loss) Recognized in OCI	0.1	(0.4)	0	(0.2)
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0	(0.1)	(0.1)	(0.1)
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	0
Amount of Gain/(Loss) Reclassified From AOCI Into Income			$ (0.2)	$ (0.4)

XML

Fair Value Measurements

6 Months Ended

Jun. 30, 2014

Fair Value Measurements

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and Dec. 31, 2013. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For natural gas and diesel fuel swaps, the market approach was used in determining fair value.

Recurring Fair Value Measures
	At fair value as of Jun 30, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	8.6	$	0.0	$	8.6
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	8.7	$	0.0	$	8.7
Liabilities
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Diesel fuel swaps		0.0		0.0		0.0		0.0
Total	$	0.0	$	0.3	$	0.0	$	0.3
	At fair value as of Dec 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Diesel fuel swaps		0.0		0.2		0.0		0.2
Total	$	0.0	$	10.0	$	0.0	$	10.0
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Diesel fuel swaps		0.0		0.1		0.0		0.1
Total	$	0.0	$	0.3	$	0.0	$	0.3

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

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

Tampa Electric Company [Member]

Fair Value Measurements

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and Dec. 31, 2013. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For all assets and liabilities presented below, the market approach was used in determining fair value.

Recurring Derivative Fair Value Measures
	At fair value as of Jun 30, 2014
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	8.6	$	0.0	$	8.6
Total	$	0.0	$	8.6	$	0.0	$	8.6
Liabilities
Natural gas swaps	$	0.0	$	0.3	$	0.0	$	0.3
Total	$	0.0	$	0.3	$	0.0	$	0.3
	At fair value as of Dec 31, 2013
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas swaps	$	0.0	$	9.8	$	0.0	$	9.8
Total	$	0.0	$	9.8	$	0.0	$	9.8
Liabilities
Natural gas swaps	$	0.0	$	0.2	$	0.0	$	0.2
Total	$	0.0	$	0.2	$	0.0	$	0.2

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

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At June 30, 2014, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

XML

Accounting for Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2014

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the derivatives that are designated as cash flow hedges at June 30, 2014 and Dec. 31, 2013:

Total Derivatives(1)
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.2	$	9.7
Long-term assets		0.5		0.3
Total assets	$	8.7	$	10.0
Current liabilities	$	0.2	$	0.1
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.3

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

Gross Amounts of Derivatives and Their Related Offset Amounts

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Jun 30, 2014
Description
Derivative assets	$	9.9		$	(1.2	)	$	8.7
Derivative liabilities	$	(1.5	)	$	1.2		$	(0.3	)
Dec 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)

Effect of Hedging Instruments on OCI and Income

The following table presents the effect of hedging instruments on OCI and income for the three and six months ended June 30:

For the three months ended Jun 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)					Effective Portion (1)
2014
Interest rate contracts	$	0.0			Interest expense	$	0.0
Commodity contracts:
Diesel fuel derivatives		0.1			Mining related costs		0.0
Total	$	0.1				$	0.0
2013
Interest rate contracts	$	0.0			Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.4	)		Mining related costs		(0.1	)
Total	($	0.4	)			($	0.3	)
For the six months ended Jun 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)					Effective Portion	(1)
2014
Interest rate contracts	$	0.0			Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.0			Mining related costs		(0.1	)
Total	$	0.0				($	0.3	)
2013
Interest rate contracts	$	0.0			Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)		Mining related costs		(0.1	)
Total	($	0.2	)			($	0.5	)

(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 six months ended June 30, 2014 and 2013, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the six months ended June 30:

(millions)	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2014
Interest rate swaps	$	0.0		$	0.0		($	0.2	)
Diesel fuel derivatives		0.1			0.0			(0.1	)
Total	$	0.1		$	0.0		($	0.3	)
2013
Interest rate swaps	$	0.0		$	0.0		($	0.4	)
Diesel fuel derivatives		(1.1	)		(0.2	)		(0.1	)
Total	($	1.1	)	($	0.2	)	($	0.5	)

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

Derivative Volumes Expected to Settle

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		1.0		0.0		19.4
2015		0.0		0.0		0.0		25.0
2016		0.0		0.0		0.0		2.8
Total		0.0		1.0		0.0		47.2

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 June 30, 2014 and Dec. 31, 2013:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.0	Derivative liabilities		0.0
Natural gas derivatives:
Current	Derivative assets		8.1	Derivative liabilities		0.2
Long-term	Derivative assets		0.5	Derivative liabilities		0.1
Total derivatives designated as hedging instruments		$	8.7		$	0.3

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

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 June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	0.1	$	0.2
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.2
Current liabilities	$	0.0	$	0.1
Long-term liabilities		0.0		0.0
Total liabilities	$	0.0	$	0.1

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 June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.1	$	9.5
Long-term assets		0.5		0.3
Total assets	$	8.6	$	9.8
Current liabilities	$	0.2	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.2

Energy Related Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	8.1	Regulatory assets	$	0.2
Long-term	Regulatory liabilities		0.5	Regulatory assets		0.1
Total		$	8.6		$	0.3
(millions) Dec 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Tampa Electric Company [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.1	$	9.5
Long-term assets		0.5		0.3
Total assets	$	8.6	$	9.8
Current liabilities (1)	$	0.2	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.2

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

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 June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
(millions)	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Jun 30, 2014
Description
Derivative assets	$	9.8		$	(1.2	)	$	8.6
Derivative liabilities	$	(1.5	)	$	1.2		$	(0.3	)
Dec 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)

Effect of Hedging Instruments on OCI and Income

The following table presents the effect of hedging instruments on OCI and income for the three months and six months ended June 30:

(millions)	Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)	Three months ended Jun 30:			Six months ended Jun 30:
2014
Interest rate contracts:	Interest expense	$	0.0		$	0.2
Total		$	0.0		$	0.2
2013
Interest rate contracts:	Interest expense	($	0.2	)	($	0.4	)
Total		($	0.2	)	($	0.4	)

(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 June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2014		0.0		19.4
2015		0.0		25.0
2016		0.0		2.8
Total		0.0		47.2

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

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	8.1	Regulatory assets	$	0.2
Long-term	Regulatory liabilities		0.5	Regulatory assets		0.1
Total		$	8.6		$	0.3
(millions) Dec 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

XML

Discontinued Operations

6 Months Ended

Jun. 30, 2014

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations

15. Discontinued Operations

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

The following table provides selected components of discontinued operations:

Components of income from discontinued operations	Three months ended					Six months ended
	Jun 30,					Jun 30,
(millions)	2014		2013			2014		2013
Revenues	$	0.0	$	0.0		$	0.0	$	0.0
(Loss) Income from operations		0.0		(0.2	)		5.0		0.2
(Loss) Income from discontinued operations		0.0		(0.2	)		5.0		0.2
Less: Provision for income taxes		0.0		0.0			1.9		0.1
(Loss) Income from discontinued operations, net		0.0		(0.2	)		3.1		0.1

XML

Fair Value Measurements - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	$ 8.7	$ 10.0
Total Swap Liabilities	0.3	0.3
Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	8.7	10.0
Total Swap Liabilities	0.3	0.3
Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	8.6	9.8
Total Swap Liabilities	0.3	0.2
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	$ 0	$ 0

XML

Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Cash flows from operating activities
Net income	$ 108.5	$ 92.9
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	169.1	165.9
Deferred income taxes	62.0	52.1
Investment tax credits	(0.2)	(0.2)
Allowance for funds used during construction	(4.4)	(2.5)
Non-cash stock compensation	7.1	6.9
Gain on sales of business/assets, pretax	(0.1)	(0.2)
Deferred recovery clauses	(14.4)	(5.9)
Receivables, less allowance for uncollectibles	(36.6)	(38.5)
Inventories	(16.2)	(19.7)
Prepayments and other current assets	(2.1)	(4.3)
Taxes accrued	34.3	28.1
Interest accrued	2.5	2.0
Accounts payable	(36.0)	13.0
Other	(12.5)	(1.8)
Cash flows from operating activities	261.0	287.8
Cash flows from investing activities
Capital expenditures	(320.3)	(249.6)
Allowance for funds used during construction	4.4	2.5
Net proceeds from sales of business/assets	0.3	0.3
Cash flows used in investing activities	(315.6)	(246.8)
Cash flows from financing activities
Dividends	(95.9)	(95.6)
Common stock	3.0	7.4
Proceeds from long-term debt issuance	296.6	0
Repayment of long-term debt/Purchase in lieu of redemption	(83.3)	0
Net decrease in short-term debt	(84.0)	0
Cash flows from (used) in financing activities	36.4	(88.2)
Net decrease in cash and cash equivalents	(18.2)	(47.2)
Cash and cash equivalents at beginning of period	185.2	200.5
Cash and cash equivalents at end of period	167.0	153.3
Supplemental disclosure of non-cash activities
Capital expenditures accrued excluded above/not yet paid	8.6	(3.1)
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	129.5	104.1
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	150.5	146.0
Deferred income taxes	35.0	42.6
Investment tax credits	(0.2)	(0.2)
Allowance for funds used during construction	(4.4)	(2.5)
Deferred recovery clauses	(14.4)	(5.9)
Receivables, less allowance for uncollectibles	(29.1)	(43.0)
Inventories	(2.6)	(18.9)
Prepayments	(2.8)	(5.6)
Taxes accrued	100.5	63.5
Interest accrued	2.2	1.6
Accounts payable	(34.3)	13.9
Other	(10.6)	(0.2)
Cash flows from operating activities	319.3	295.4
Cash flows from investing activities
Capital expenditures	(312.7)	(239.9)
Allowance for funds used during construction	4.4	2.5
Net proceeds from sale of assets	0.1	0
Cash flows used in investing activities	(308.2)	(237.4)
Cash flows from financing activities
Dividends	(112.0)	(94.1)
Common stock	17.0	20.0
Proceeds from long-term debt issuance	296.6	0
Repayment of long-term debt/Purchase in lieu of redemption	(83.3)	0
Net decrease in short-term debt	(84.0)	0
Cash flows from (used) in financing activities	34.3	(74.1)
Net decrease in cash and cash equivalents	45.4	(16.1)
Cash and cash equivalents at beginning of period	9.8	45.2
Cash and cash equivalents at end of period	55.2	29.1
Supplemental disclosure of non-cash activities
Capital expenditures accrued excluded above/not yet paid	$ 8.6	$ (3.1)

XML

Consolidated Condensed Balance Sheets (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Allowance for uncollectibles	$ 3.8	$ 4.7
Common equity, shares authorized	400.0	400.0
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	217.8	217.3
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 2.3	$ 2.0

XML

Other Comprehensive Income

6 Months Ended

Jun. 30, 2014

Other Comprehensive Income

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three and six months ended June 30, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Jun 30,									Six months ended Jun 30,
(millions)	Gross			Tax			Net			Gross			Tax			Net
2014
Unrealized gain on cash flow hedges	$	0.1		$	0.0		$	0.1		$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.1			(0.1	)		0.0			0.5			(0.2	)		0.3
Gain on cash flow hedges		0.2			(0.1	)		0.1			0.5			(0.2	)		0.3
Amortization of unrecognized benefit costs (2)		0.8			(0.3	)		0.5			1.6			(0.6	)		1.0
Increase in unrecognized postemployment costs(3)		0.0			0.0			0.0			(12.9	)		4.7			(8.2	)
Total other comprehensive income (loss)	$	1.0		($	0.4	)	$	0.6		($	10.8	)	$	3.9		($	6.9	)
2013
Unrealized loss on cash flow hedges	($	0.7	)	$	0.3		($	0.4	)	($	0.4	)	$	0.2		($	0.2	)
Reclassification from AOCI to net income (1)		0.5			(0.2	)		0.3			0.8			(0.3	)		0.5
(Loss) Gain on cash flow hedges		(0.2	)		0.1			(0.1	)		0.4			(0.1	)		0.3
Amortization of unrecognized benefit costs (2)		1.1			(0.4	)		0.7			2.2			(0.8	)		1.4
Total other comprehensive income	$	0.9		($	0.3	)	$	0.6		$	2.6		($	0.9	)	$	1.7

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

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

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

Accumulated Other Comprehensive Loss
(millions)	Jun 30, 2014			Dec 31, 2013
Unrecognized pension loss and prior service credit (1)	($	19.7	)	($	20.5	)
Unrecognized other benefit loss, prior service cost and transition obligation (2)		7.1			15.1
Net unrealized losses from cash flow hedges (3)		(7.5	)		(7.8	)
Total accumulated other comprehensive loss	($	20.1	)	($	13.2	)

(1) Net of tax benefit of $12.1 million and $12.6 million as of June 30, 2014 and Dec. 31, 2013, respectively.

(2) Net of tax expense of $4.4 million and $9.1 million as of June 30, 2014 and Dec. 31, 2013, respectively.

(3) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended June 30,							Six months ended June 30,
(millions)	Gross		Tax			Net		Gross		Tax			Net
2014
Unrealized loss on cash flow hedges	$	0.0	$	0.0		$	0.0	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.0		0.0			0.0		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.0		0.0			0.0		0.4		(0.2	)		0.2
Total other comprehensive income	$	0.0	$	0.0		$	0.0	$	0.4	($	0.2	)	$	0.2
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		0.7		(0.3	)		0.4
Gain on cash flow hedges		0.4		(0.2	)		0.2		0.7		(0.3	)		0.4
Total other comprehensive income	$	0.4	($	0.2	)	$	0.2	$	0.7	($	0.3	)	$	0.4

Accumulated Other Comprehensive Loss
(millions)	Jun 30, 2014			Dec 31, 2013
Net unrealized losses from cash flow hedges (1)	($	7.6	)	($	7.8	)
Total accumulated other comprehensive loss	($	7.6	)	($	7.8	)

(1) Net of tax benefit of $4.7 million and $4.9 million as of June 30, 2014 and Dec. 31, 2013, respectively.

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Jul. 28, 2014
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Trading Symbol	TE
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	0000350563
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		233,407,893
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC COMPANY
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10

XML

Earnings Per Share

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share

9. Earnings Per Share

	For the three months ended Jun 30,						For the six months ended Jun 30,
(millions, except per share amounts)	2014			2013			2014			2013
Basic earnings per share
Net income from continuing operations	$	58.4		$	51.6		$	105.4		$	92.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Income before discontinued operations available to common shareholders - Basic	$	58.2		$	51.4		$	105.0		$	92.5
Income (Loss) from discontinued operations, net	$	0.0		($	0.2	)	$	3.1		$	0.1
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (Loss) from discontinued operations available to common shareholders - Basic	$	0.0		($	0.2	)	$	3.1		$	0.1
Net income	$	58.4		$	51.4		$	108.5		$	92.9
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Net income available to common shareholders - Basic	$	58.2		$	51.2		$	108.1		$	92.6
Average common shares outstanding - Basic		215.4			215.0			215.3			214.8
Earnings per share from continuing operations available to common shareholders - Basic	$	0.27		$	0.24		$	0.49		$	0.43
Earnings per share from discontinued operations available to common shareholders - Basic	$	0.00		$	0.00		$	0.01		$	0.00
Earnings per share available to common shareholders - Basic	$	0.27		$	0.24		$	0.50		$	0.43
Diluted earnings per share
Net income from continuing operations	$	58.4		$	51.6		$	105.4		$	92.8
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Income before discontinued operations available to common shareholders - Diluted	$	58.2		$	51.4		$	105.0		$	92.5
Income (Loss) from discontinued operations, net	$	0.0		($	0.2	)	$	3.1		$	0.1
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0			0.0
Income (Loss) from discontinued operations available to common shareholders - Diluted	$	0.0		($	0.2	)	$	3.1		$	0.1
Net income	$	58.4		$	51.4		$	108.5		$	92.9
Amount allocated to nonvested participating shareholders		(0.2	)		(0.2	)		(0.4	)		(0.3	)
Net income available to common shareholders - Diluted	$	58.2		$	51.2		$	108.1		$	92.6
Unadjusted average common shares outstanding - Diluted		215.4			215.0			215.3			214.8
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.5			0.5			0.5
Average common shares outstanding - Diluted		215.9			215.5			215.8			215.3
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.27		$	0.24		$	0.49		$	0.43
Earnings per share from discontinued operations available to common shareholders - Diluted	$	0.00		$	0.00		$	0.01		$	0.00
Earnings per share available to common shareholders - Diluted	$	0.27		$	0.24		$	0.50		$	0.43
Anti-dilutive shares		0.0			0.0			0.0			0.0

XML

Consolidated Condensed Statements of Income (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenues
Regulated electric and gas	$ 603.6	$ 604.0	$ 1,179.3	$ 1,143.1
Unregulated	122.7	131.9	231.1	253.9
Total revenues	726.3	735.9	1,410.4	1,397.0
Expenses
Fuel	169.7	174.5	319.3	314.5
Purchased power	19.9	20.5	38.1	35.1
Cost of natural gas sold	29.1	40.7	76.2	90.2
Other	126.8	129.6	247.4	250.4
Operation and maintenance other expense
Mining related costs	103.5	110.2	194.7	205.7
Other	4.8	3.4	7.9	4.7
Depreciation and amortization	84.2	83.9	169.1	165.9
Taxes, other than income	55.1	53.6	111.4	106.9
Total expenses	593.1	616.4	1,164.1	1,173.4
Income from continuing operations	133.2	119.5	246.3	223.6
Other income
Allowance for other funds used during construction	2.0	1.4	4.4	2.5
Other income	(0.2)	1.6	(0.9)	3.2
Total other income	1.8	3.0	3.5	5.7
Interest charges
Interest expense	42.9	43.5	85.4	86.5
Allowance for borrowed funds used during construction	(0.7)	(0.8)	(2.1)	(1.4)
Total interest charges	42.2	42.7	83.3	85.1
Income from continuing operations before provision for income taxes	92.8	79.8	166.5	144.2
Provision for income taxes	34.4	28.2	61.1	51.4
Net income from continuing operations	58.4	51.6	105.4	92.8
Discontinued operations
Income (Loss) from discontinued operations	0	(0.2)	5.0	0.2
Provision for income taxes	0	0	1.9	0.1
Income (Loss) from discontinued operations, net	0	(0.2)	3.1	0.1
Net income	$ 58.4	$ 51.4	$ 108.5	$ 92.9
Average common shares outstanding - Basic	215.4	215.0	215.3	214.8
Average common shares outstanding - Diluted	215.9	215.5	215.8	215.3
Earnings per share from continuing operations - Basic	$ 0.27	$ 0.24	$ 0.49	$ 0.43
Earnings per share from continuing operations - Diluted	$ 0.27	$ 0.24	$ 0.49	$ 0.43
Earnings per share from discontinued operations - Basic	$ 0.00	$ 0.00	$ 0.01	$ 0.00
Earnings per share from discontinued operations - Diluted	$ 0.00	$ 0.00	$ 0.01	$ 0.00
Earnings per share - Basic	$ 0.27	$ 0.24	$ 0.50	$ 0.43
Earnings per share - Diluted	$ 0.27	$ 0.24	$ 0.50	$ 0.43
Dividends paid per common share outstanding	$ 0.22	$ 0.22	$ 0.44	$ 0.44

XML

Regulatory

6 Months Ended

Jun. 30, 2014

Regulatory

3. Regulatory

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

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both June 30, 2014 and Dec. 31, 2013.

Regulatory Assets and Liabilities

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

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

Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun 30, 2014		Dec 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	68.1	$	67.4
Other:
Cost-recovery clauses		1.8		6.1
Postretirement benefit asset		177.6		182.7
Deferred bond refinancing costs (2)		7.6		8.0
Environmental remediation		52.0		51.4
Competitive rate adjustment		2.8		4.1
Other		7.7		7.7
Total other regulatory assets		249.5		260.0
Total regulatory assets		317.6		327.4
Less: Current portion		33.7		34.3
Long-term regulatory assets	$	283.9	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.6	$	9.8
Other:
Cost-recovery clauses		34.8		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.4		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		588.4		594.0
Total other regulatory liabilities		681.5		707.4
Total regulatory liabilities		687.1		717.2
Less: Current portion		65.7		85.8
Long-term regulatory liabilities	$	621.4	$	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:

	Jun 30,		Dec 31,
(millions)	2014		2013
Clause recoverable (1)	$	4.6	$	10.2
Components of rate base (2)		180.7		185.6
Regulatory tax assets (3)		68.1		67.4
Capital structure and other (3)		64.2		64.2
Total	$	317.6	$	327.4

(1) To be recovered through cost-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.

Storm Damage Cost Recovery

Prior to Nov. 1, 2013, Tampa Electric was accruing $8.0 million annually to a FERC-authorized and FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both June 30, 2014 and Dec. 31, 2013.

Regulatory Assets and Liabilities

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

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

Details of the regulatory assets and liabilities as of June 30, 2014 and Dec. 31, 2013 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Jun 30, 2014		Dec 31, 2013
Regulatory assets:
Regulatory tax asset (1)	$	68.1	$	67.4
Other:
Cost-recovery clauses		1.8		6.1
Postretirement benefit asset		177.6		182.7
Deferred bond refinancing costs (2)		7.6		8.0
Environmental remediation		52.0		51.4
Competitive rate adjustment		2.8		4.1
Other		7.7		7.7
Total other regulatory assets		249.5		260.0
Total regulatory assets		317.6		327.4
Less: Current portion		33.7		34.3
Long-term regulatory assets	$	283.9	$	293.1
Regulatory liabilities:
Regulatory tax liability (1)	$	5.6	$	9.8
Other:
Cost-recovery clauses		34.8		54.5
Transmission and delivery storm reserve		56.1		56.1
Deferred gain on property sales (3)		1.4		2.0
Provision for stipulation and other		0.8		0.8
Accumulated reserve - cost of removal		588.4		594.0
Total other regulatory liabilities		681.5		707.4
Total regulatory liabilities		687.1		717.2
Less: Current portion		65.7		85.8
Long-term regulatory liabilities	$	621.4	$	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	Jun 30,		Dec 31,
(millions)	2014		2013
Clause recoverable (1)		$4.6		$10.2
Components of rate base (2)		180.7		185.6
Regulatory tax assets (3)		68.1		67.4
Capital structure and other (3)		64.2		64.2
Total	$	317.6	$	327.4

(1) To be recovered through cost-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.

XML

New Accounting Pronouncements

6 Months Ended

Jun. 30, 2014

New Accounting Pronouncements

2. New Accounting Pronouncements

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for the company beginning in 2015.

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for the company beginning in fiscal 2017 and allows for either full retrospective adoption or modified retrospective adoption. The company is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

Tampa Electric Company [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

In April 2014, the FASB issued guidance regarding changing the criteria for reporting discontinued operations and enhancing convergence of the FASB’s and the IASB’s reporting requirements for discontinued operations. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. This standard is effective for TEC beginning in 2015.

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for TEC beginning in fiscal 2017 and allows for either full retrospective adoption or modified retrospective adoption. TEC is currently evaluating the impact of the adoption of this guidance on its financial statements but does not expect the impact to be significant.

XML

Variable Interest Entities

6 Months Ended

Jun. 30, 2014

Variable Interest Entities

14. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $7.0 million and $12.8 million of capacity pursuant to PPAs for the three and six months ended June 30, 2014, respectively and $5.0 million and $9.9 million for the three and six months ended June 30, 2013, respectively.

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

Tampa Electric Company [Member]

Variable Interest Entities

13. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 160 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $7.0 million and $12.8 million of capacity pursuant to PPAs for the three and six months ended June 30, 2014, respectively, and $5.0 million and $9.9 million for the three and six months ended June 30, 2013, respectively.

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

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies

10. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

The company believes the claim in the pending action described above in this item is without merit and intends to defend the matter vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to this matter.

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

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

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

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

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

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 June 30, 2014 TEC has estimated its ultimate financial liability to be $35.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of June 30, 2014 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
TECO Coal
Fuel purchase related (2)	$	0.0	$	0.7	$	4.0	$	4.7	$	0.6
Other subsidiaries
Fuel purchase/energy management (2)		0.0		0.0		92.9		92.9		0.1
Total	$	0.0	$	0.7	$	96.9	$	97.6	$	0.7
Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
Tampa Electric Company(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at June 30, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At June 30, 2014, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.

Tampa Electric Company [Member]

Commitments and Contingencies

8. Commitments and Contingencies

Legal Contingencies

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

Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. The suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, remains pending.

TEC believes the claim in the pending action described above in this item is without merit and intends to defend the matter vigorously. TEC is unable at this time to estimate the possible loss or range of loss with respect to this matter.

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 June 30, 2014 TEC has estimated its ultimate financial liability to be $35.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2014 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
Tampa Electric Company (2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at June 30, 2014. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At June 30, 2014, TEC was in compliance with all applicable financial covenants.

XML

Short-Term Debt

6 Months Ended

Jun. 30, 2014

Short-Term Debt

6. Short-Term Debt

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Jun 30, 2014						Dec 31, 2013
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		78.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	0.0	$	0.7	$	675.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

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

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

At June 30, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at June 30, 2014.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

Tampa Electric Company [Member]

Short-Term Debt

6. Short-Term Debt

At June 30, 2014 and Dec. 31, 2013, the following credit facilities and related borrowings existed:

Credit Facilities
	Jun 30, 2014						Dec. 31, 2013
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.7	$	325.0	$	6.0	$	0.7
1-year accounts receivable facility		150.0		0.0		0.0		150.0		78.0		0.0
Total	$	475.0	$	0.0	$	0.7	$	475.0	$	84.0	$	0.7

(1) Borrowings outstanding are reported as notes payable.

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

At June 30, 2014, these credit facilities require commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings at June 30, 2014.

Tampa Electric Company Accounts Receivable Facility

On Feb. 14, 2014, TEC and TRC amended their $150 million accounts receivable collateralized borrowing facility, entering into Amendment No. 12 to the Loan and Servicing Agreement with certain lenders named therein and Citibank, N.A. as Program Agent. The amendment (i) extends the maturity date to Feb. 13, 2015, (ii) provides that TRC will pay program and liquidity fees, which will total 70.0 basis points, (iii) continues to provide that the interest rates on the borrowings will be based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the LIBOR (if available) plus a margin, (iv) confirms that CAFCO, LLC will be the Committed Lender and Conduit Lender and (v) makes other technical changes.

XML

Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Collateral posted with or received from any counterparties	$ 0	$ 0
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.5	7.8
Net pretax gain expected to be reclassified from regulatory assets or liabilities	7.9
Tampa Electric Company [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.6	7.8
Net pretax gain expected to be reclassified from regulatory assets or liabilities	7.9
Interest Rate Swap [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	$ 7.5	$ 7.8
Diesel Fuel [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Dec. 31, 2014
Natural Gas Contracts [Member]
Derivative [Line Items]
Maximum length of time hedging in future cash flow	Dec. 31, 2016

XML

Income Taxes

6 Months Ended

Jun. 30, 2014

Income Taxes

4. Income Taxes

The company’s U.S. subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for years 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state and foreign jurisdictions include 2010 and forward.

The effective tax rate increased to 36.71% for the six months ended June 30, 2014 from 35.64% for the same period in 2013.

Tampa Electric Company [Member]

Income Taxes

4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the six months ended June 30, 2014 and 2013 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2012 consolidated federal income tax return in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and forward. Years 2013 and 2014 are currently under examination by the IRS under its Compliance Assurance Program. TECO Energy does not expect the results of current IRS examinations to significantly change the total amount of unrecognized tax benefits by the end of 2014. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2010 and forward.

XML

Employee Postretirement Benefits

6 Months Ended

Jun. 30, 2014

Employee Postretirement Benefits

5. Employee Postretirement Benefits

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

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Jun 30,	2014			2013			2014			2013
Components of net periodic benefit expense
Service cost	$	4.2		$	4.3		$	0.6		$	0.5
Interest cost on projected benefit obligations		8.2			7.2			2.6			2.4
Expected return on assets		(10.4	)		(9.5	)		0.0			0.0
Amortization of:
Prior service (benefit) cost		(0.1	)		(0.1	)		(0.1	)		(0.1	)
Actuarial loss		3.5			5.3			0.1			0.2
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income	$	5.4		$	7.2		$	3.2		$	3.0
Six months ended Jun 30,
Components of net periodic benefit expense
Service cost	$	8.3		$	9.1		$	1.2		$	1.2
Interest cost on projected benefit obligations		16.4			14.4			5.2			4.7
Expected return on assets		(20.7	)		(19.2	)		0.0			0.0
Amortization of:
Prior service (benefit) cost		(0.2	)		(0.2	)		(0.1	)		(0.2	)
Actuarial loss		6.7			10.3			0.1			0.5
Net pension expense recognized in the
TECO Energy Consolidated Condensed Statements of Income	$	10.5		$	14.4		$	6.4		$	6.2

For the 2014 plan year, TECO Energy is using an assumed long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2014 measurement dates. Additionally, TECO Energy made contributions of $26.5 million to its pension plan for the six months ended June 30, 2014.

For the three and six months ended June 30, 2014, TECO Energy and its subsidiaries reclassed $0.7 million and $1.3 million pretax, respectively, of unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three and six months ended June 30, 2014, TEC reclassed $2.7 million and $5.2 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

Tampa Electric Company [Member]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy, Inc. Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended June 30, 2014 and 2013, respectively, was $3.9 million and $5.6 million for pension benefits, and $2.6 million and $2.4 million for other postretirement benefits. TEC’s portion of the net pension expense for the six months ended June 30, 2014 and 2013, respectively, was $7.7 million and $10.9 million for pension benefits, and $5.2 million and $5.0 million for other postretirement benefits.

For the 2014 plan year, TECO Energy assumed a long-term EROA of 7.25% and a discount rate of 5.118% for pension benefits under its qualified pension plan, and a discount rate of 5.096% for its other postretirement benefits as of their Jan. 1, 2013 measurement dates. Additionally, TECO Energy made contributions of $26.5 million to its pension plan in the six months ended June 30, 2014. TEC’s portion of the contributions was $21.5 million.

Included in the benefit expenses discussed above, for the three and six months ended June 30, 2014, TEC reclassed $2.7 million and $5.2 million, respectively, of unamortized transition obligation, prior service cost and actuarial losses from regulatory assets to net income.

XML

Long-Term Debt

6 Months Ended

Jun. 30, 2014

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2014, total long-term debt had a carrying amount of $3,137.6 million and an estimated fair market value of $3,469.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $2,921.1 million and an estimated fair market value of $3,184.1 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the Notes). The Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Tampa Electric Company [Member]

Long-Term Debt

7. Long-Term Debt

Fair Value of Long-Term Debt

At June 30, 2014, TEC’s total long-term debt had a carrying amount of $2,097.2 million and an estimated fair market value of $2,329.6 million. At Dec. 31, 2013, total long-term debt had a carrying amount of $1,880.8 million and an estimated fair market value of $2,042.0 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the Notes). The Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the Notes, in whole or in part, at 100% of the principal amount of the Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

XML

Accounting for Derivative Instruments and Hedging Activities - Effect of Hedging Instruments on Other Comprehensive Income and Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ 0.1	$ (0.4)	$ 0	$ (0.2)
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0	(0.3)	(0.3)	(0.5)
Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0	(0.2)	0.2	(0.4)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0.1	(0.4)	0	(0.2)
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) Reclassified From AOCI Into Income	0	(0.1)	(0.1)	(0.1)
Interest rate contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	0	0	0
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense	Interest expense	Interest expense	Interest expense
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0	(0.2)	(0.2)	(0.4)
Interest rate contracts [Member] | Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Location of Gain/(Loss) Reclassified From AOCI Into Income			Interest expense	Interest expense
Amount of Gain/(Loss) Reclassified From AOCI Into Income	$ 0	$ (0.2)	$ 0.2	$ (0.4)

XML

Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Jun. 30, 2014 gal
Diesel Fuel Derivatives [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,000,000
Diesel Fuel Derivatives [Member] | 2014 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2014 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,000,000
Diesel Fuel Derivatives [Member] | 2015 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2015 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | 2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	47,200,000
Natural Gas Contracts [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	47,200,000
Natural Gas Contracts [Member] | 2014 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2014 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2014 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,400,000
Natural Gas Contracts [Member] | 2014 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,400,000
Natural Gas Contracts [Member] | 2015 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2015 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2015 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	25,000,000
Natural Gas Contracts [Member] | 2015 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	25,000,000
Natural Gas Contracts [Member] | 2016 [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2016 [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | 2016 [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,800,000
Natural Gas Contracts [Member] | 2016 [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,800,000

XML

Accounting for Derivative Instruments and Hedging Activities - Energy Related Derivatives (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current regulatory assets	$ 33.7	$ 34.3
Long-term regulatory assets	283.9	293.1
Regulatory assets	317.6	327.4
Current regulatory liabilities	65.7	85.8
Long-term regulatory liabilities	621.4	631.4
Regulatory liabilities	687.1	717.2
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	33.7	34.3
Long-term regulatory assets	283.9	293.1
Regulatory assets	317.6	327.4
Current regulatory liabilities	65.7	85.8
Long-term regulatory liabilities	621.4	631.4
Regulatory liabilities	687.1	717.2
Energy Related Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	0.2	0
Long-term regulatory assets	0.1	0.2
Regulatory assets	0.3	0.2
Current regulatory liabilities	8.1	9.5
Long-term regulatory liabilities	0.5	0.3
Regulatory liabilities	8.6	9.8
Energy Related Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	0.2	0
Long-term regulatory assets	0.1	0.2
Regulatory assets	0.3	0.2
Current regulatory liabilities	8.1	9.5
Long-term regulatory liabilities	0.5	0.3
Regulatory liabilities	$ 8.6	$ 9.8

XML

Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2014

Letters of Credit and Guarantees

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of June 30, 2014 is as follows:

Guarantees - TECO Energy
(millions) Guarantees for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
TECO Coal
Fuel purchase related (2)	$	0.0	$	0.7	$	4.0	$	4.7	$	0.6
Other subsidiaries
Fuel purchase/energy management (2)		0.0		0.0		92.9		92.9		0.1
Total	$	0.0	$	0.7	$	96.9	$	97.6	$	0.7
Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
Tampa Electric Company(2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1
Total	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at June 30, 2014. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

Tampa Electric Company [Member]

Letters of Credit and Guarantees

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of June 30, 2014 is as follows:

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After(1) 2018		Total		Liabilities Recognized at Jun 30, 2014
Tampa Electric Company (2)	$	0.0	$	0.0	$	0.7	$	0.7	$	0.1

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

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TEC under these agreements at June 30, 2014. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

XML

Other Comprehensive Income - Other Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	$ 0.1	$ (0.7)	$ 0	$ (0.4)
Reclassification from AOCI to net income, Gross	0.1	0.5	0.5	0.8
Gain (Loss) on cash flow hedges, Gross	0.2	(0.2)	0.5	0.4
Amortization of unrecognized benefit costs, Gross	0.8	1.1	1.6	2.2
Increase in unrecognized post employment costs, Gross	0		(12.9)
Total other comprehensive income (loss), Gross	1.0	0.9	(10.8)	2.6
Unrealized gain (loss) on cash flow hedges, Tax	0	0.3	0	0.2
Reclassification from AOCI to net income, Tax	(0.1)	(0.2)	(0.2)	(0.3)
Gain (loss) on cash flow hedges, Tax	(0.1)	0.1	(0.2)	(0.1)
Amortization of unrecognized benefit costs, Tax	(0.3)	(0.4)	(0.6)	(0.8)
Increase in unrecognized post employment costs, Tax	0		4.7
Total other comprehensive income (loss), Tax	(0.4)	(0.3)	3.9	(0.9)
Unrealized gain (loss) on cash flow hedges, Net	0.1	(0.4)	0	(0.2)
Reclassification from AOCI to net income, Net	0	0.3	0.3	0.5
Gain (loss) on cash flow hedges, Net	0.1	(0.1)	0.3	0.3
Amortization of unrecognized benefit costs, Net	0.5	0.7	1.0	1.4
Increase in unrecognized post employment costs, Net	0	0	(8.2)	0
Total other comprehensive income (loss), Net	0.6	0.6	(6.9)	1.7
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross		0		0
Reclassification from AOCI to net income, Gross		0.4		0.7
Gain (Loss) on cash flow hedges, Gross		0.4		0.7
Total other comprehensive income (loss), Gross		0.4		0.7
Unrealized gain (loss) on cash flow hedges, Tax	0	0	0	0
Reclassification from AOCI to net income, Tax	0	(0.2)	(0.2)	(0.3)
Gain (loss) on cash flow hedges, Tax	0	(0.2)	(0.2)	(0.3)
Total other comprehensive income (loss), Tax	0	(0.2)	(0.2)	(0.3)
Unrealized gain (loss) on cash flow hedges, Net	0	0	0	0
Reclassification from AOCI to net income, Net	0	0.2	0.2	0.4
Gain (loss) on cash flow hedges, Net	0	0.2	0.2	0.4
Total other comprehensive income (loss), Net	$ 0	$ 0.2	$ 0.2	$ 0.4

XML

Accounting for Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2014

Accounting for Derivative Instruments and Hedging Activities

12. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

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

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 30, 2014, all of the company’s physical contracts qualify for the NPNS exception.

The following table presents the derivatives that are designated as cash flow hedges at June 30, 2014 and Dec. 31, 2013:

Total Derivatives(1)
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.2	$	9.7
Long-term assets		0.5		0.3
Total assets	$	8.7	$	10.0
Current liabilities	$	0.2	$	0.1
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.3

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

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties.

Offsetting of Derivative Assets and Liabilities
(millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Jun 30, 2014
Description
Derivative assets	$	9.9		$	(1.2	)	$	8.7
Derivative liabilities	$	(1.5	)	$	1.2		$	(0.3	)
Dec 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)

The following table presents the derivative hedges of diesel fuel contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for diesel fuel used in the production of coal:

Diesel Fuel Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	0.1	$	0.2
Long-term assets		0.0		0.0
Total assets	$	0.1	$	0.2
Current liabilities	$	0.0	$	0.1
Long-term liabilities		0.0		0.0
Total liabilities	$	0.0	$	0.1

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.1	$	9.5
Long-term assets		0.5		0.3
Total assets	$	8.6	$	9.8
Current liabilities	$	0.2	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.2

The ending balance in AOCI related to the cash flow hedges and interest rate swaps at June 30, 2014 is a net loss of $7.5 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

The following tables present the fair values and locations of derivative instruments recorded on the balance sheet at June 30, 2014 and Dec. 31, 2013:

Derivatives Designated as Hedging Instruments
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Contracts:
Diesel fuel derivatives:
Current	Derivative assets	$	0.1	Derivative liabilities	$	0.0
Long-term	Derivative assets		0.0	Derivative liabilities		0.0
Natural gas derivatives:
Current	Derivative assets		8.1	Derivative liabilities		0.2
Long-term	Derivative assets		0.5	Derivative liabilities		0.1
Total derivatives designated as hedging instruments		$	8.7		$	0.3

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

The following tables present the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	8.1	Regulatory assets	$	0.2
Long-term	Regulatory liabilities		0.5	Regulatory assets		0.1
Total		$	8.6		$	0.3
(millions) Dec 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Based on the fair value of the instruments at June 30, 2014, net pretax gains of $7.9 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 six months ended June 30:

For the three months ended Jun 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)					Effective Portion (1)
2014
Interest rate contracts	$	0.0			Interest expense	$	0.0
Commodity contracts:
Diesel fuel derivatives		0.1			Mining related costs		0.0
Total	$	0.1				$	0.0
2013
Interest rate contracts	$	0.0			Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		(0.4	)		Mining related costs		(0.1	)
Total	($	0.4	)			($	0.3	)
For the six months ended Jun 30: (millions)	Amount of Gain/(Loss) on Derivatives Recognized in OCI			Location of Gain/(Loss) Reclassified From AOCI Into Income		Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)					Effective Portion	(1)
2014
Interest rate contracts	$	0.0			Interest expense	($	0.2	)
Commodity contracts:
Diesel fuel derivatives		0.0			Mining related costs		(0.1	)
Total	$	0.0				($	0.3	)
2013
Interest rate contracts	$	0.0			Interest expense	($	0.4	)
Commodity contracts:
Diesel fuel derivatives		(0.2	)		Mining related costs		(0.1	)
Total	($	0.2	)			($	0.5	)

(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 six months ended June 30, 2014 and 2013, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the six months ended June 30:

(millions)	Fair Value Asset/ (Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income
2014
Interest rate swaps	$	0.0		$	0.0		($	0.2	)
Diesel fuel derivatives		0.1			0.0			(0.1	)
Total	$	0.1		$	0.0		($	0.3	)
2013
Interest rate swaps	$	0.0		$	0.0		($	0.4	)
Diesel fuel derivatives		(1.1	)		(0.2	)		(0.1	)
Total	($	1.1	)	($	0.2	)	($	0.5	)

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

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2014 for financial diesel fuel contracts and Dec. 31, 2016 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

(millions)	Diesel Fuel Contracts (Gallons)				Natural Gas Contracts (MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		1.0		0.0		19.4
2015		0.0		0.0		0.0		25.0
2016		0.0		0.0		0.0		2.8
Total		0.0		1.0		0.0		47.2

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

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of June 30, 2014, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

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

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions are generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. As of June 30, 2014, substantially all positions with counterparties were net assets.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments. Substantially all of the company’s open positions with counterparties as of June 30, 2014 were asset positions.

Tampa Electric Company [Member]

Accounting for Derivative Instruments and Hedging Activities

10. Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

A company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of June 30, 2014, all of TEC’s physical contracts qualify for the NPNS exception.

The following table presents the derivative hedges of natural gas contracts at June 30, 2014 and Dec. 31, 2013 to limit the exposure to changes in the market price for natural gas used to produce energy and natural gas purchased for resale to customers:

Natural Gas Derivatives
(millions)	Jun 30, 2014		Dec 31, 2013
Current assets	$	8.1	$	9.5
Long-term assets		0.5		0.3
Total assets	$	8.6	$	9.8
Current liabilities (1)	$	0.2	$	0.0
Long-term liabilities		0.1		0.2
Total liabilities	$	0.3	$	0.2

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

The ending balance in AOCI related to previously settled interest rate swaps at June 30, 2014 is a net loss of $7.6 million after tax and accumulated amortization. This compares to a net loss of $7.8 million in AOCI after tax and accumulated amortization at Dec. 31, 2013.

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at June 30, 2014 and Dec. 31, 2013. There was no collateral posted with or received from any counterparties:

Offsetting of Derivative Assets and Liabilities
(millions)	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Jun 30, 2014
Description
Derivative assets	$	9.8		$	(1.2	)	$	8.6
Derivative liabilities	$	(1.5	)	$	1.2		$	(0.3	)
Dec 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)

The following table presents the effect of energy related derivatives on the fuel recovery clause mechanism in the Consolidated Condensed Balance Sheets as of June 30, 2014 and Dec. 31, 2013:

Energy Related Derivatives
	Asset Derivatives			Liability Derivatives
(millions) Jun 30, 2014	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	8.1	Regulatory assets	$	0.2
Long-term	Regulatory liabilities		0.5	Regulatory assets		0.1
Total		$	8.6		$	0.3
(millions) Dec 31, 2013	Balance Sheet Location (1)	Fair Value		Balance Sheet Location (1)	Fair Value
Commodity Contracts:
Natural gas derivatives:
Current	Regulatory liabilities	$	9.5	Regulatory assets	$	0.0
Long-term	Regulatory liabilities		0.3	Regulatory assets		0.2
Total		$	9.8		$	0.2

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

Based on the fair value of the instruments at June 30, 2014, net pretax gains of $7.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next 12 months.

The following table presents the effect of hedging instruments on OCI and income for the three months and six months ended June 30:

(millions)	Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)	Three months ended Jun 30:			Six months ended Jun 30:
2014
Interest rate contracts:	Interest expense	$	0.0		$	0.2
Total		$	0.0		$	0.2
2013
Interest rate contracts:	Interest expense	($	0.2	)	($	0.4	)
Total		($	0.2	)	($	0.4	)

(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 six months ended June 30, 2014 and 2013, all hedges were effective.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Dec. 31, 2016 for the financial natural gas contracts. The following table presents by commodity type TEC’s derivative volumes that, as of June 30, 2014, are expected to settle during the 2014, 2015 and 2016 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2014		0.0		19.4
2015		0.0		25.0
2016		0.0		2.8
Total		0.0		47.2

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 June 30, 2014, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

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

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions are generally not adjusted as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions. As of June 30, 2014, substantially all positions with counterparties were net assets.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments. Substantially all of TEC’s open positions with counterparties as of June 30, 2014 were asset positions.

XML

Pending Acquisition of New Mexico Gas Company

6 Months Ended

Jun. 30, 2014

Business Combinations [Abstract]

Pending Acquisition of New Mexico Gas Company

17. Pending Acquisition of New Mexico Gas Company

Pending Acquisition of New Mexico Gas Company

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

On May 14, 2014, the Joint Applicants announced they had reached a settlement agreement in the case with certain interveners, which was not opposed by NMPRC staff or any other interveners in the proceeding. On June 30, 2014, the hearing examiner issued a certification of the stipulation recommending approval of the stipulation.

A meeting of the NMPRC to consider the hearing examiner’s certification has not been scheduled. It is anticipated that the NMPRC will issue a final order approving the acquisition and certification of stipulation in time for the transaction to close in the third quarter of 2014.

In July 2014, TECO Energy completed a public offering of common stock, the proceeds from which are intended to be used to pay a portion of the acquisition price (see Note 18). With TECO Energy’s consent, NMGC and NMGI each entered into a Note Purchase Agreement on July 30, 2014, contemplating the issuance of $70 million and $200 million of notes, respectively, conditioned upon, and to be issued at, closing of the acquisition. The proceeds from the NMGC notes are to be used to repay existing debt at closing and the proceeds from the NMGI notes are to be primarily used to repay existing debt and to fund the transaction, costs and expenses.

XML

Short-Term Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified			6 Months Ended		6 Months Ended			3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member]	Jun. 30, 2014 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Feb. 14, 2014 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Jun. 30, 2014 Tampa Electric Company [Member] Minimum [Member]	Jun. 30, 2013 Tampa Electric Company [Member] Minimum [Member]	Jun. 30, 2014 Tampa Electric Company [Member] Maximum [Member]	Jun. 30, 2013 Tampa Electric Company [Member] Maximum [Member]
Line of Credit Facility [Line Items]
Commitment fees, percentage			0.70%		0.70%			0.125%	0.125%	0.30%	0.30%
Weighted-average interest rate				0.56%
Outstanding borrowings			$ 0
Amended credit facility	$ 675.0	$ 675.0	$ 475.0	$ 475.0	$ 150.0	$ 150.0	$ 150.0
Debt instrument maturity date			Feb. 13, 2015
Basis spread on federal funds rate			0.50%		0.50%

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Regulatory assets:
Regulatory assets	$ 317.6	$ 327.4
Less: Current portion	33.7	34.3
Long-term regulatory assets	283.9	293.1
Regulatory liabilities:
Regulatory liabilities	687.1	717.2
Less: Current portion	65.7	85.8
Long-term regulatory liabilities	621.4	631.4
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	317.6	327.4
Less: Current portion	33.7	34.3
Long-term regulatory assets	283.9	293.1
Regulatory liabilities:
Regulatory liabilities	687.1	717.2
Less: Current portion	65.7	85.8
Long-term regulatory liabilities	621.4	631.4
Regulatory Tax Liability [Member]
Regulatory liabilities:
Regulatory liabilities	5.6	9.8
Regulatory Tax Liability [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	5.6	9.8
Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	34.8	54.5
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	34.8	54.5
Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Transmission and Delivery Storm Reserve [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	56.1
Deferred Gain on Property Sales [Member]
Regulatory liabilities:
Regulatory liabilities	1.4	2.0
Deferred Gain on Property Sales [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	1.4	2.0
Provision for Stipulation and Other [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	0.8
Provision for Stipulation and Other [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	0.8
Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	588.4	594.0
Accumulated Reserve - Cost of Removal [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	588.4	594.0
Total Other Regulatory Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	681.5	707.4
Total Other Regulatory Liabilities [Member] | Tampa Electric Company [Member]
Regulatory liabilities:
Regulatory liabilities	681.5	707.4
Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	68.1	67.4
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	68.1	67.4
Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	1.8	6.1
Cost-Recovery Clauses [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	1.8	6.1
Postretirement Benefit Asset [Member]
Regulatory assets:
Regulatory assets	177.6	182.7
Postretirement Benefit Asset [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	177.6	182.7
Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	7.6	8.0
Deferred Bond Refinancing Costs [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	7.6	8.0
Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	52.0	51.4
Environmental Remediation [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	52.0	51.4
Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	2.8	4.1
Competitive Rate Adjustment [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	2.8	4.1
Other [Member]
Regulatory assets:
Regulatory assets	7.7	7.7
Other [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	7.7	7.7
Total Other Regulatory Assets [Member]
Regulatory assets:
Regulatory assets	249.5	260.0
Total Other Regulatory Assets [Member] | Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	$ 249.5	$ 260.0

XML

Consolidated Condensed Statements of Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Statement [Abstract]
Franchise fees and gross receipts taxes	$ 27.8	$ 26.7	$ 55.0	$ 52.1

XML

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2014

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for both utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

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 June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three months and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

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

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

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.

Tampa Electric Company [Member]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

See TEC’s 2013 Annual Report on Form 10-K for a complete detailed discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly-owned subsidiary of TECO Energy, Inc. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13).

All significant intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of June 30, 2014 and Dec. 31, 2013, and the results of operations and cash flows for the periods ended June 30, 2014 and 2013. The results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2014.

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

Revenues

As of June 30, 2014 and Dec. 31, 2013, unbilled revenues of $57.0 million and $46.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

The regulated utilities are allowed to recover certain costs on a dollar-per-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.8 million and $55.0 million, respectively, for the three and six months ended June 30, 2014, compared to $26.7 million and $52.1 million, respectively, for the three and six months ended June 30, 2013.

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.

XML

Segment Information - Schedule of Segment Information (Parenthetical) (Detail)	6 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]
Internally allocated interest costs, pre tax rate	6.00%
Capital structure assumption, debt to equity ratio	50.00%

XML

Variable Interest Entities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 19.9	$ 20.5	$ 38.1	$ 35.1
Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	19.9	20.5	38.1	35.1
Power Purchase Agreements [Member] | Variable Interest Entities [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	7.0	5.0	12.8	9.9
Power Purchase Agreements [Member] | Variable Interest Entities [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 7.0	$ 5.0	$ 12.8	$ 9.9
Minimum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range			117
Minimum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range			117
Maximum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range			160
Maximum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range			160

XML

Subsequent Events

6 Months Ended

Jun. 30, 2014

Subsequent Events [Abstract]

Subsequent Events

18. Subsequent Events

Public Offering of 15.5 million in Common Shares

On July 1, 2014, the company entered into an underwriting agreement with Morgan Stanley & Co. LLC, as representative of the several underwriters named therein, pursuant to which the company agreed to offer and sell 15.5 million shares of its common stock in an underwritten public offering at a public offering price of $18.10 per share. The company received approximately $271 million in net proceeds from the offering after underwriting fees and offering expenses. The shares were delivered to the underwriters on July 8, 2014.

Pursuant to the terms of the underwriting agreement, the company granted the underwriters a 30-day option to purchase up to an additional 2.3 million shares. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

The company plans to use the net proceeds from this offering to fund, in part, the company’s previously announced acquisition of New Mexico Gas Company and for general corporate purposes.

NMGC and NMGI Note Purchase Agreement

NMGC and NMGI each entered into a Note Purchase Agreement on July 30, 2014, contemplating the issuance of $70 million and $200 million of notes, respectively, conditioned upon, and to be issued at, closing of the acquisition. (See Note 17)

XML

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

6 Months Ended

Jun. 30, 2014

TECO Guatemala [Member]

Components of Discontinued Operations

The following table provides selected components of discontinued operations:

Components of income from discontinued operations	Three months ended					Six months ended
	Jun 30,					Jun 30,
(millions)	2014		2013			2014		2013
Revenues	$	0.0	$	0.0		$	0.0	$	0.0
(Loss) Income from operations		0.0		(0.2	)		5.0		0.2
(Loss) Income from discontinued operations		0.0		(0.2	)		5.0		0.2
Less: Provision for income taxes		0.0		0.0			1.9		0.1
(Loss) Income from discontinued operations, net		0.0		(0.2	)		3.1		0.1

XML

Segment Information

6 Months Ended

Jun. 30, 2014

Segment Information

11. Segment Information

TECO Energy is an electric and gas utility holding company with 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 Jun 30,	Tampa Electric		Peoples Gas		TECO Coal			Other & Eliminations			TECO Energy
2014
Revenues - external	$	512.5	$	90.7	$	120.6		$	2.5		$	726.3
Sales to affiliates		0.2		0.4		0.0			(0.6	)		0.0
Total revenues		512.7		91.1		120.6			1.9			726.3
Depreciation and amortization		61.7		13.4		8.7			0.4			84.2
Total interest charges(1)		23.3		3.4		1.5			14.0			42.2
Internally allocated interest (1)		0.0		0.0		1.5			(1.5	)		0.0
Provision (benefit) for income taxes		37.1		4.8		(0.7	)		(6.8	)		34.4
Net income (loss) from continuing operations		62.2		7.5		0.8			(12.1	)		58.4
Income from discontinued operations, net		0.0		0.0		0.0			0.0			0.0
Net income (loss)	$	62.2	$	7.5	$	0.8		($	12.1	)	$	58.4
2013
Revenues - external	$	502.6	$	101.3	$	128.4		$	3.6		$	735.9
Sales to affiliates		0.3		0.5		0.0			(0.8	)		0.0
Total revenues		502.9		101.8		128.4			2.8			735.9
Depreciation and amortization		60.8		13.2		9.5			0.4			83.9
Total interest charges(1)		23.3		3.3		1.7			14.4			42.7
Internally allocated interest (1)		0.0		0.0		1.7			(1.7	)		0.0
Provision (benefit) for income taxes		31.5		5.0		(0.9	)		(7.4	)		28.2
Net income (loss) from continuing operations		50.6		7.9		0.7			(7.6	)		51.6
Income from discontinued operations, net		0.0		0.0		0.0			(0.2	)		(0.2	)
Net income (loss)	$	50.6	$	7.9	$	0.7		($	7.8	)	$	51.4
(millions) Six months ended Jun 30,	Tampa Electric		Peoples Gas		TECO Coal			Other & Eliminations			TECO Energy
2014
Revenues - external	$	965.4	$	213.1	$	226.7		$	5.2		$	1,410.4
Sales to affiliates		0.5		0.6		0.0			(1.1	)		0.0
Total revenues		965.9		213.7		226.7			4.1			1,410.4
Depreciation and amortization		123.8		26.7		17.7			0.9			169.1
Total interest charges(1)		45.3		6.8		3.0			28.2			83.3
Internally allocated interest (1)		0.0		0.0		3.0			(3.0	)		0.0
Provision (benefit) for income taxes		63.7		14.0		(2.9	)		(13.7	)		61.1
Net income (loss) from continuing operations		107.4		22.1		(0.8	)		(23.3	)		105.4
Income from discontinued operations, net		0.0		0.0		0.0			3.1			3.1
Net income (loss)	$	107.4	$	22.1	$	(0.8	)	$	(20.2	)	$	108.5
2013
Revenues - external	$	920.4	$	223.2	$	246.3		$	7.1		$	1,397.0
Sales to affiliates		0.5		0.5		0.0			(1.0	)		0.0
Total revenues		920.9		223.7		246.3			6.1			1,397.0
Depreciation and amortization		119.8		26.2		19.2			0.7			165.9
Total interest charges(1)		46.7		6.7		3.4			28.3			85.1
Internally allocated interest (1)		0.0		0.0		3.3			(3.3	)		0.0
Provision (benefit) for income taxes		51.3		13.7		(1.0	)		(12.6	)		51.4
Net income (loss) from continuing operations		82.4		21.7		3.7			(15.0	)		92.8
Income from discontinued operations, net		0.0		0.0		0.0			0.1			0.1
Net income (loss)	$	82.4	$	21.7	$	3.7		$	(14.9	)	$	92.9
At Jun 30, 2014
Total assets	$	6,311.9	$	1,034.1	$	333.3		($	58.5	)	$	7,620.8
At Dec 31, 2013
Total assets	$	6,126.9	$	1,021.2	$	316.3		($	16.4	)	$	7,448.0

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for January 2013 through June 2014 were at a pretax rate of 6.00% based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

Tampa Electric Company [Member]

Segment Information

9. Segment Information

(millions) Three months ended Jun 30,	Tampa Electric		Peoples Gas		Other & Eliminations			Tampa Electric Company
2014
Revenues - external	$	512.6	$	90.7	$	0.0		$	603.3
Sales to affiliates		0.1		0.4		(0.5	)		0.0
Total revenues		512.7		91.1		(0.5	)		603.3
Depreciation and amortization		61.7		13.4		0.0			75.1
Total interest charges		23.3		3.4		0.0			26.7
Provision for income taxes		37.1		4.8		0.0			41.9
Net income	$	62.2	$	7.5	$	0.0		$	69.7
2013
Revenues - external	$	502.8	$	101.3	$	0.0		$	604.1
Sales to affiliates		0.1		0.5		(0.6	)		0.0
Total revenues		502.9		101.8		(0.6	)		604.1
Depreciation and amortization		60.8		13.2		0.0			74.0
Total interest charges		23.3		3.3		0.0			26.6
Provision for income taxes		31.5		5.0		0.0			36.5
Net income	$	50.6	$	7.9	$	0.0		$	58.5
Six months ended Jun 30,
2014
Revenues - external	$	965.7	$	213.1	$	0.0		$	1,178.8
Sales to affiliates		0.2		0.6		(0.8	)		0.0
Total revenues		965.9		213.7		(0.8	)		1,178.8
Depreciation and amortization		123.8		26.7		0.0			150.5
Total interest charges		45.3		6.8		0.0			52.1
Provision for income taxes		63.7		14.0		0.0			77.7
Net income	$	107.4	$	22.1	$	0.0		$	129.5
Total assets at Jun 30, 2014	$	6,061.9	$	1,002.4	($	12.4	)	$	7,051.9
2013
Revenues - external	$	920.7	$	223.2	$	0.0		$	1,143.9
Sales to affiliates		0.2		0.5		(0.7	)		0.0
Total revenues		920.9		223.7		(0.7	)		1,143.9
Depreciation and amortization		119.8		26.2		0.0			146.0
Total interest charges		46.7		6.7		0.0			53.4
Provision for income taxes		51.3		13.7		0.0			65.0
Net income	$	82.4	$	21.7	$	0.0		$	104.1
Total assets at Dec 31, 2013	$	5,895.4	$	989.3	($	8.9	)	$	6,875.8