10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2013

OR

¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
TECO Energy, Inc.
Common Stock, $1.00 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if TECO Energy, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     YES  x    NO  ¨

Indicate by check mark if Tampa Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     YES  ¨    NO  x

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.     YES  ¨    NO  x

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 Web site, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

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 Act).    YES  ¨    NO  x

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

The aggregate market value of TECO Energy, Inc.’s common stock held by non-affiliates of the registrant as of June 28, 2013 was approximately $3.69 billion based on the closing sale price as reported on the New York Stock Exchange.

The aggregate market value of Tampa Electric Company’s common stock held by non-affiliates of the registrant as of June 28, 2013 was zero.

The number of shares of TECO Energy, Inc.’s common stock outstanding as of Feb. 13, 2014 was 218,067,617. As of Feb. 13, 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.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement relating to the 2014 Annual Meeting of Shareholders of TECO Energy, Inc. are incorporated by reference into Part III.

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

This combined Form 10-K 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. Tampa Electric Company makes no representations as to the information relating to TECO Energy, Inc.’s other operations.

Cover page of 172

Index to Exhibits begins on page 168

DEFINITIONS

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

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

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IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
ISO	independent system operator
ITCs	investment tax credits
KW	Kilowatt(s)
KWH	kilowatt-hour(s)
LIBOR MAP-21	London Interbank Offered Rate 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.
NOL	net operating loss
Note	Note      to consolidated financial statements
NOx	nitrogen oxide
NPNS	normal purchase normal sale
NYMEX	New York Mercantile Exchange
O&M expenses	operations and maintenance expenses
OATT	open access transmission tariff
OCI	other comprehensive income
OTC	over-the-counter
OTTI	other than temporary impairment
PBGC	Pension Benefit Guarantee Corporation
PBO	postretirement benefit obligation
PCI	pulverized coal injection
PCIDA	Polk County Industrial Development Authority
PGA	purchased gas adjustment
PGS	Peoples Gas System, the gas division of Tampa Electric Company
PM	particulate matter
PPA	power purchase agreement
PPSA	Power Plant Siting Act
PRP	potentially responsible party
PUHCA 2005	Public Utility Holding Company Act of 2005
REIT	real estate investment trust
REMIC	real estate mortgage investment conduit
RFP	request for proposal
ROE	return on common equity
Regulatory ROE	return on common equity as determined for regulatory purposes
RPS	renewable portfolio standards
RTO	regional transmission organization
S&P	Standard and Poor’s
SCR	selective catalytic reduction

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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

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PART I

Item 1. BUSINESS.

TECO ENERGY

TECO Energy, Inc. (TECO Energy) was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of Tampa Electric Company. TECO Energy and its subsidiaries had approximately 3,900 employees as of Dec. 31, 2013.

TECO Energy’s Corporate Governance Guidelines, the charter of each committee of the Board of Directors, and the code of ethics applicable to all directors, officers and employees, the Code of Ethics and Business Conduct, are available on the Investors section of TECO Energy’s website, www.tecoenergy.com, or in print free of charge to any investor who requests the information. TECO Energy also makes its SEC (www.sec.gov) filings available free of charge on the Investors section of TECO Energy’s website as soon as reasonably practicable after they are filed with or furnished to the SEC.

TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary TECO Diversified, owns TECO Coal.

Unless otherwise indicated by the context, “TECO Energy” or the “company” means the holding company, TECO Energy, Inc. and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries. TECO Energy’s business segments and revenues for those segments, for the years indicated, are identified below.

TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provides retail electric service to almost 700,000 customers in West Central Florida with a net winter system generating capacity of 4,668 MW. PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With almost 350,000 customers, PGS has operations in Florida’s major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2013 was almost 1.7 billion therms.

TECO Coal, a Kentucky corporation, has 10 subsidiaries located in Eastern Kentucky, Tennessee and Virginia. These entities own mineral rights, own or operate surface and underground mines and own interests in coal processing and loading facilities.

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Revenues from Continuing Operations
(millions)	2013		2012		2011
Tampa Electric	$	1,950.5	$	1,981.3	$	2,020.6
PGS		393.5		398.9		453.5
Total regulated businesses	$	2,344.0	$	2,380.2	$	2,474.1
TECO Coal		496.2		608.9		733.0
Other		11.1		7.5		2.8
Total revenues from continuing operations	$	2,851.3	$	2,996.6	$	3,209.9

For additional financial information regarding TECO Energy’s significant business segments including geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements.

Discontinued Operations/Asset Dispositions

TECO Guatemala, a Florida corporation, owned subsidiaries that participated in two contracted Guatemalan power plants, Alborada and San José. TECO Energy, Inc. completed the sale of its generating and transmission assets in Guatemala during 2012 as part of a business strategy to focus on the domestic electric and gas utilities.

On Sept. 27, 2012, TECO Guatemala entered into an agreement to sell all of the equity interests in the Alborada and San José power stations, related facilities and operations in Guatemala, for a total purchase price of $227.5 million in cash. The sale of the Alborada Power Station closed on the same date for a selling price of $12.5 million.

On Dec. 19, 2012, the closing occurred on the sale of the San José Power Station and related facilities in Guatemala for a purchase price of $215.0 million.

See Notes 19, 20 and 21 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding these discontinued operations and asset dispositions.

Pending Acquisition of NMGI

In May 2013, TECO Energy announced it had entered into an agreement to purchase all of the capital stock of NMGI, the parent company of NMGC. Completion of the acquisition is subject to various customary conditions, including, among others, receipt of all required regulatory approvals. For more information regarding this pending acquisition, see MD&A-Pending Acquisition of NMGI.

TAMPA ELECTRIC – Electric Operations

TEC was incorporated in Florida in 1899 and was reincorporated in 1949. TEC is a public utility operating within the State of Florida. Its Tampa Electric division is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties, with an estimated population of over one million. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has three electric generating stations in or near Tampa, one electric generating station in southwestern Polk County, Florida and one electric generating station in long-term reserve standby located near Sebring, a city in Highlands County in South Central Florida.

Tampa Electric had 2,385 employees as of Dec. 31, 2013, of which 895 were represented by the International Brotherhood of Electrical Workers and 178 were represented by the Office and Professional Employees International Union.

In 2013, approximately 48% of Tampa Electric’s total operating revenue was derived from residential sales, 30% from commercial sales, 9% from industrial sales and 13% from other sales, including bulk power sales for resale. Approximately 5% of revenues were attributable to governmental municipalities. The sources of operating revenue and MWH sales for the years indicated were as follows:

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Operating Revenue
(millions)	2013		2012		2011
Residential	$	936.8	$	958.9	$	994.7
Commercial		581.2		612.3		612.6
Industrial – Phosphate		71.9		75.7		62.0
Industrial – Other		100.4		101.2		99.3
Other retail sales of electricity		177.4		184.0		185.2
Total retail		1,867.7		1,932.1		1,953.8
Sales for resale		8.5		16.2		21.7
Other		74.3		33.0		45.1
Total operating revenues	$	1,950.5	$	1,981.3	$	2,020.6
Megawatt-hour Sales
(thousands)	2013		2012		2011
Residential		8,470		8,395		8,718
Commercial		6,090		6,185		6,207
Industrial		2,026		2,002		1,804
Other retail sales of electricity		1,832		1,827		1,835
Total retail		18,418		18,409		18,564
Sales for resale		222		267		352
Total energy sold		18,640		18,676		18,916

No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on Tampa Electric. Tampa Electric’s business is not highly seasonal, but winter peak loads are experienced due to electric space heating, fewer daylight hours and colder temperatures and summer peak loads are experienced due to the use of air conditioning and other cooling equipment.

Regulation

Tampa Electric’s retail operations are regulated by the FPSC, which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters.

In general, the FPSC’s pricing objective is to set rates at a level that provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.

The costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include O&M expenses, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate the individual company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed ROE. Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other interested parties.

Tampa Electric’s results for the first ten months of 2013, and all of 2012 and 2011, reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

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

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

        This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that an expansion of TEC’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa

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Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective in 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than TEC could seek a review of Tampa Electric’s base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013 and effective Nov. 1, 2013, Tampa Electric ceased accruing $8.0 million annually to the FERC-authorized and FPSC-approved self-insured storm damage reserve.

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

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Non-power goods-and-services transactions between Tampa Electric and its affiliates are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may be disallowed for recovery from Tampa Electric’s retail and wholesale customers.

On Nov. 6, 2012, Tampa Electric received notification from the FERC that its accounting practices and financial reporting processes would be audited, along with its compliance with the FERC’s records retention requirements. This was considered a routine audit by the FERC staff, though it has been approximately 20 years since Tampa Electric last had a FERC accounting audit.

No material issues have been identified as a result of the audit, and Tampa Electric expects to have an “exit” audit conference with the FERC staff in 2014 and thereafter to receive a letter from the FERC describing the results of the completed audit.

By June 30, 2014, the company will file its required triennial market-power analysis, demonstrating that the company does not have wholesale market power using FERC’s two analytical screens. This compliance filing is made in support of the company’s continued ability to affect wholesale market-based rate transactions everywhere, except within Tampa Electric’s balancing-authority area.

Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Matters section).

Competition

Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Distributed generation could also be a source of competition in the future, but has not been a significant factor to date. Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.

Unlike the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including approximately 30 other investor-owned, municipal and other utilities, as well as co-generators and other unregulated power generators with uncontracted excess capacity. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a long-term basis. Competition in these markets is primarily based on having available energy to sell to the wholesale market and the price. In Florida, available energy for the wholesale markets is affected by the state’s PPSA, which sets the state’s electric energy and environmental policy, and governs the building of new generation involving steam capacity of 75 MW or more. The PPSA requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. The effect of the PPSA has been to limit the number of unregulated generating units with excess capacity for sale in the wholesale power markets in Florida.

Tampa Electric is not a major participant in the wholesale market because it uses its lower cost generation to serve its retail customers rather than the wholesale market. Over the past three years, gross revenues from wholesale sales, which include fuel that is a pass-through cost, have averaged less than 1% of Tampa Electric’s total revenue.

        FPSC rules promote cost-competitiveness in the building of new steam generating capacity by requiring IOUs, such as Tampa Electric, to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 MW. These rules, which allow independent power producers and others to bid to supply the new generating capacity, provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids and provide more stringent standards for the IOUs to recover cost overruns in the event that the self-build option is deemed the most cost-effective.

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Fuel

Approximately 61% of Tampa Electric’s generation of electricity for 2013 was coal-fired, with natural gas representing approximately 39% and oil representing less than 1%. Tampa Electric used its generating units to meet approximately 92% of the total system load requirements, with the remaining 8% coming from purchased power. Tampa Electric’s average delivered fuel cost per MMBTU and average delivered cost per ton of coal burned have been as follows:

Average cost per MMBTU	2013		2012		2011		2010		2009
Coal	$	3.36	$	3.57	$	3.46	$	3.08	$	3.05
Oil		30.01		25.88		21.21		16.43		16.01
Gas (Natural)		5.23		5.34		6.20		6.74		8.00
Composite		4.00		4.19		4.38		4.46		5.02
Average cost per ton of coal burned		77.79		84.59		83.17		74.80		72.98

Tampa Electric’s generating stations burn fuels as follows: Bayside Station burns natural gas; Big Bend Station, which has SO₂ scrubber capabilities and NO_x reduction systems, burns a combination of high-sulfur coal and petroleum coke, No. 2 fuel oil and natural gas at CT4; Polk Power Station burns a blend of low-sulfur coal and petroleum coke (which is gasified and subject to sulfur and particulate matter removal prior to combustion), natural gas and oil; and Phillips Station, which burned residual fuel oil and was placed on long-term standby in September 2009.

Coal. Tampa Electric burned approximately 4.7 million tons of coal and petroleum coke during 2013 and estimates that its combined coal and petroleum coke consumption will be about 4.9 million tons in 2014. During 2013, Tampa Electric purchased approximately 83% of its coal under long-term contracts with five suppliers, and approximately 17% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 81% of its coal and petroleum coke requirements in 2014 under long-term contracts with six suppliers and the remaining 19% in the spot market.

Tampa Electric’s long-term contracts provide for revisions in the base price to reflect changes in several important cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.

In 2013, approximately 85% of Tampa Electric’s coal supply was deep-mined, approximately 8% was surface-mined and the remaining was petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric’s coal supply or results of its operations. Tampa Electric cannot predict, however, the effect of any future mining laws and regulations.

Natural Gas. As of Dec. 31, 2013, approximately 48% of Tampa Electric’s 1,250,000 MMBTU gas storage capacity was full. Tampa Electric has contracted for 80% of its expected gas needs for the April 2014 through October 2014 period. In early March 2014, to meet its generation requirements, Tampa Electric expects to issue RFPs to meet its remaining 2014 gas needs and begin contracting for its 2015 gas needs. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.

Oil. Tampa Electric has agreements in place to purchase low sulfur No. 2 fuel oil for its Big Bend and Polk Power stations. All of these agreements have prices that are based on spot indices.

Franchises and Other Rights

Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights-of-way as it carries for its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture.

Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. The City of Temple Terrace reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed. In the absence of such right to purchase, based on judicial precedent, if the franchise agreement is not renewed, Tampa Electric would be able to continue to use public rights-of-way within the municipality, subject to reasonable rules and regulations imposed by the municipalities.

Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates through August 2043.

Franchise fees payable by Tampa Electric, which totaled $42.8 million at Dec. 31, 2013, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

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Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the County Commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.

Environmental Matters

Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act, and material Clean Water Act implications and impacts by federal and state legislative initiatives. TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites.

Air Quality Control

Emission Reductions

Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC) and conversion of coal-fired units to natural-gas fired combined cycle; implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add BACT emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.

Tampa Electric, through voluntary negotiations in 1999 with the EPA, the U.S. Department of Justice and the FDEP, signed a Consent Decree and Consent Final Judgment, as settlement of federal and state litigation to dramatically decrease emissions from its power plants. Tampa Electric has fulfilled the obligations of the Consent Decree and the court terminated the Consent Decree on November 22, 2013. Termination of the Consent Final Judgment is in progress and is expected to be completed during the first half of 2014.

The emission reduction requirements of these agreements resulted in the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (Bayside Power Station), enhanced availability of flue-gas desulfurization systems (scrubbers) at Big Bend Station to help reduce SO_2, and installation of SCR systems for NO_x reduction on Big Bend Units 1 through 4. Cost recovery for the SCRs began for each unit in the year that the unit entered service through the ECRC (see the Regulation section).

As a result of the actions taken under the consent decree, emissions of all pollutant types have been significantly reduced. Since 1998, Tampa Electric has reduced annual SO₂, NO_x and PM emissions from its facilities by 164,000 tons (94%), 63,000 tons (91%) and 4,500 tons (87%), respectively.

Reductions in mercury emissions also have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of the SCRs at Big Bend Power Station, which have led to a system wide reduction of mercury emissions of more than 90% from 1998 levels.

Carbon Reductions and GHG

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system wide emissions of CO₂ by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO₂ to remain near 1990 levels until the addition of the next base load unit, which is scheduled to be in service in January 2017 (see the Tampa Electric and Capital Expenditures sections). Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Station coal-fired units resulted in an annual decrease in CO₂ emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 30% and 15%, respectively.

Tampa Electric’s power plants currently emit approximately 16 million tons of CO₂ per year. Assuming a projected long-term average annual load growth of more than 1.0%, Tampa Electric could emit approximately 17 million tons of CO₂ (an increase of approximately 6%) by 2020 if natural gas-fired peaking and combined-cycle generation additions are used to meet customer demand.

        Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. 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 cannot predict whether the FPSC would grant such recovery. Tampa Electric’s current solid-based energy generation is about 55% of its total system output in 2013, compared to being approximately 84% of its output in 2001. This is due to the conversion of the coal-fired Gannon Power Station into the natural gas-fired Bayside Power Station. However, solid fuel-fired facilities remain a significant component of Tampa Electric’s diverse generation fleet and additional solid fuel units could be considered in the future.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS.

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This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

The estimated amounts represent only the portion of the cleanup costs attributable to Tampa Electric. The estimates to perform the work are based on Tampa Electric’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, Tampa Electric could be liable for more than Tampa Electric’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.

Capital Expenditures

Tampa Electric’s 2013 capital expenditures included approximately $41 million primarily for upgrades to scrubbers and modifications to coal combustion by-product storage areas at the Big Bend Power Station. See the Liquidity, Capital Expenditures section of MD&A for information on estimated future capital expenditures related to environmental compliance.

PEOPLES GAS SYSTEM – Gas Operations

PGS operates as the gas division of TEC. PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the state of Florida.

Gas is delivered to the PGS system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that serves almost 350,000 customers. The system includes approximately 11,600 miles of mains and 6,700 miles of service lines (see PGS’s Franchises and Other Rights section below).

PGS had 553 employees as of Dec. 31, 2013. A total of 148 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.

In 2013, the total throughput for PGS was almost 1.7 billion therms. Of this total throughput, 6% was gas purchased and resold to retail customers by PGS, 85% was third-party supplied gas that was delivered for retail transportation-only customers and 9% was gas sold off-system. Industrial and power generation customers consumed approximately 61% of PGS’s annual therm volume, commercial customers consumed approximately 26%, off-system sales customers consumed 9% and the remaining balance was consumed by residential customers.

While the residential market represents only a small percentage of total therm volume, residential operations comprised about 33% of total revenues. Approximately 5% of revenues are attributed to governmental municipalities.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also seen increased interest and development in natural gas vehicles. There are 21 compressed natural gas filling stations connected to the PGS distribution system.

Revenues and therms for PGS for the years ended Dec. 31 were as follows:

			Revenues						Therms
(millions)	2013		2012		2011		2013		2012		2011
Residential	$	128.1	$	125.4	$	140.8		74.4		70.8		77.7
Commercial		133.4		134.1		138.0		438.1		421.4		409.3
Industrial		13.4		10.3		8.8		272.0		237.3		205.0
Off system sales		56.7		73.7		106.0		143.1		224.0		231.0
Power generation		9.9		12.4		10.6		744.4		913.5		614.3
Other revenues		42.2		34.9		39.9
Total	$	383.7		$390.8	$	444.1		1,672.0		1,867.0		1,537.3

No significant part of PGS’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on PGS. PGS’s business is not highly seasonal, but winter peak throughputs are experienced due to colder temperatures.

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Regulation

The operations of PGS are regulated by the FPSC separately from the regulation 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 seeks to set rates at a level that provides an opportunity for a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.

The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’s weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed ROE. Base rates are determined in FPSC revenue requirements proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties. For a description of recent proceeding activity, see the Regulation-PGS Rates section of MD&A.

PGS’s results reflect base rates established in May 2009, when the FPSC approved a base rate increase of $19.2 million which became effective on Jun. 18, 2009 and reflects an ROE of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million.

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the PGA clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2013, the FPSC approved PGS’s 2014 PGA cap factor for the period January 2014 through December 2014.

In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm charge for energy conservation and pipeline replacement programs. The conservation charge is intended to permit PGS to recover, on a dollar-for-dollar basis, prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are mandated by Florida law and approved and monitored by the FPSC. PGS is also permitted to earn a return, depreciation expenses and applicable taxes associated with the replacement of cast iron/bare steel infrastructure. PGS projects to have all cast iron and bare steel removed from its system within 10 years. Lastly, the FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers.

In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’s distribution system. In general, the FPSC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal Regulations.

PGS is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters (see the Environmental Matters section).

Competition

Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.

In Florida, gas service is unbundled for all non-residential customers. PGS has a “NaturalChoice” program, offering unbundled transportation service to all non-residential customers, as well as residential customers consuming in excess of 1,999 therms annually, allowing these customers to purchase commodity gas from a third party but continue to pay PGS for the transportation. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 20,500 transportation-only customers as of Dec. 31, 2013 out of approximately 35,000 eligible customers.

Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation-only services at discounted rates.

Gas Supplies

PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.

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Gas is delivered by FGT through 66 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville division receives gas delivered by the Southern Natural Gas pipeline through two gate stations located northwest of Jacksonville. Gulfstream Natural Gas Pipeline provides delivery through six gate stations. PGS also has one interconnection with its affiliate SeaCoast Gas Transmission, LLC in Clay County, Florida.

Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers, except during localized emergencies affecting the PGS distribution system and on abnormally cold days.

Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by the FERC. PGS actively markets any excess capacity available on a day-to-day basis to partially offset costs recovered through the PGA clause.

PGS procures natural gas supplies using base-load and swing-supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices or a fixed price for the contract term.

Neither PGS nor any of the interconnected interstate pipelines have storage facilities in Florida. PGS occasionally faces situations when the demands of all of its customers for the delivery of gas cannot be met. In these instances, it is necessary that PGS interrupt or curtail deliveries to its interruptible customers. In general, the largest of PGS’s industrial customers are in the categories that are first curtailed in such situations. PGS’s tariff and transportation agreements with these customers give PGS the right to divert these customers’ gas to other higher priority users during the period of curtailment or interruption. PGS pays these customers for such gas at the price they paid their suppliers or at a published index price, and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.

Franchises and Other Rights

PGS holds franchise and other rights with 110 municipalities throughout Florida. These franchises govern the placement of PGS’s facilities on the public rights-of-way as it carries on its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing PGS’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events they are subject to forfeiture.

Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’s property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.

PGS’s franchise agreements with the incorporated municipalities within its service area have various expiration dates ranging from the present through 2043. PGS expects to negotiate nine franchises in 2014; five will be renewals of existing agreements and four will be new agreements. Franchise fees payable by PGS, which totaled $8.2 million at Dec. 31, 2013, are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.

Utility operations in areas outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commission of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates, and these rights are, therefore, considered perpetual.

Environmental Matters

PGS’s operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment that generally require monitoring, permitting and ongoing expenditures.

TEC is one of several PRPs for certain superfund sites and, through PGS, for former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa Electric – Electric Operations.

Capital Expenditures

During the year-ended Dec. 31, 2013, PGS did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2014 through 2018 period.

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TECO COAL

Overview

TECO Coal, with offices located in Corbin, Kentucky, is a wholly owned subsidiary of TECO Energy, Inc. and through its subsidiaries operates surface and underground mines as well as coal processing facilities in eastern Kentucky, Tennessee and southwestern Virginia.

TECO Coal owns no operating assets but holds all of the common stock of Gatliff Coal Company, Rich Mountain Coal Company, Clintwood Elkhorn Mining Company, Pike-Letcher Land Company, Premier Elkhorn Coal Company, Perry County Coal Corporation and Bear Branch Coal Company. TECO Coal owns, controls and operates, by lease or mineral rights, surface and underground mines and coal processing and loading facilities. TECO Coal produces, processes and sells bituminous, predominately low sulfur coal of metallurgical, PCI, steam and industrial grades.

TECO Coal is a supplier of metallurgical and PCI coal for use in the steel-making process and a supplier of thermal coal to electric utilities and manufacturing industries. TECO Coal also exports metallurgical and PCI coals internationally, primarily to European markets.

Metallurgical, PCI and industrial stoker coals accounted for approximately 54% of TECO Coal’s 2013 coal sales volume. Thermal coal accounted for approximately 46% of 2013 coal sales volume.

As of Dec. 31, 2013, TECO Coal owned or leased mineral rights to approximately 298.2 million tons of proven and probable coal reserves. Of the total proven and probable reserves, approximately 80% are low sulfur reserves with high BTU content. Total proven and probable reserves are expected to support current production levels for more than 20 years.

The tons sold for 2013, 2012 and 2011 by market category is set forth in Table 1 below:

Coal Sales by Market Category

(Millions of Tons)

Table 1

	Metallurgical, PCI & Industrial Stoker					Thermal
Year	Tons		% Volume			Tons		% Volume
2013		3.1		54	%		2.7		46	%
2012		2.7		44	%		3.5		56	%
2011		3.7		46	%		4.4		54	%

Sales of thermal coal during 2013, 2012 and 2011 were made primarily to utilities and industrial customers throughout the eastern part of the United States. Sales of metallurgical and PCI coal during those years were made primarily to steel companies and coke plants in North America and Europe.

TECO Coal currently operates 18 underground mines, which employ the room and pillar mining method, and seven surface mines.

In 2013, TECO Coal sold 5.8 million tons of coal. All of this coal was sold to customers other than the TECO Coal affiliate, Tampa Electric.

No significant part of TECO Coal’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect, and the business is not highly seasonal.

History

In 1967, Cal-Glo Coal Company was formed. It mined a product containing low sulfur, low ash fusion characteristic and high energy content. Realizing the potential for this product to meet its combustion, quality, and environmental requirements, Tampa Electric purchased Cal-Glo Coal Company in 1974. In 1982, after several years of continued growth and success, TECO Coal Corporation was formed and Cal-Glo Coal Company was renamed as Gatliff Coal Company. Rich Mountain Coal Company was established in 1987, when leases were signed for properties in Campbell County, Tennessee.

In 1988, Gatliff Coal Company began selling coal to the ferro-silicon and silicon markets. Also in that year, properties were acquired in Pike County, Kentucky, and Clintwood Elkhorn Mining Company was formed. Premier Elkhorn Coal Company and Pike-Letcher Land Company were formed in 1991, when additional property was acquired in Pike and Letcher Counties, Kentucky.

In 1997, Bear Branch Coal Company secured key leases for properties located in Perry County and Knott County, Kentucky.

In 2000, Perry County Coal Corporation was purchased. It is located in Perry, Knott and Leslie Counties, Kentucky.

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Mining Operations

TECO Coal currently has four mining complexes, all operating in Kentucky, with a portion of Clintwood Elkhorn Mining Company operating in Virginia as well. A mining complex is defined as all mines that supply a single wash plant, except in the case of Clintwood Elkhorn Mining Company, which provides production for two active wash plants. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as eleven individual underground or surface mines. TECO Coal uses two distinct extraction techniques: continuous underground mining and dozer and front-end loader surface mining, sometimes accompanied by highwall mining.

The complexes have been developed at locations in close proximity to the TECO Coal preparation plants and rail shipping facilities. Coal is transported from TECO Coal’s mining complexes to customers by means of railroad cars, trucks, barges or vessels, with rail shipments representing approximately 89% of 2013 coal shipments. The following map shows the locations of the four mining complexes and TECO Coal’s offices in Corbin, Kentucky.

Facilities

Coal mined by the operating companies of TECO Coal is processed and shipped from facilities located at each of the operating companies, with Clintwood Elkhorn Mining Company having two facilities. The equipment at each facility is in good condition and regularly maintained by qualified personnel. Table 2 below is a summary of TECO Coal processing facilities:

Processing Facilities Summary

Table 2

COMPANY	FACILITY	LOCATION	RAILROAD SERVICE	UTILITY SERVICE
Clintwood Elkhorn	Clintwood #2 Plant	Biggs, KY	Norfolk Southern	American Electric Power
Clintwood Elkhorn	Clintwood #3 Plant	Hurley, VA	Norfolk Southern	American Electric Power
Premier Elkhorn	Burke Branch Plant	Myra, KY	CSXT Railroad	American Electric Power
Perry County Coal	Davidson Branch Plant	Hazard, KY	CSXT Railroad	American Electric Power

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Significant Projects

Significant projects for 2013 included the following:

Premier Elkhorn Coal

• Premier Elkhorn began the transition to highwall mining on three surface mines. This mining process is expected to lower the overall mining ratio for the surface mines, as well as allow us to emphasize the greater recovery of high quality specialty coal. The first highwall miner was in operation in July 2013, with the second and third expected to be in operation in February 2014 and early second quarter 2014, respectively.

• Premier Elkhorn continued evaluation of the recently discovered reserves of the New Frontier–Burke Branch Development project and continued permitting for the construction phases of the project for slope and shaft construction. Much of the identified reserves are owned by TECO Coal.

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Mining Complexes

Table 3 below shows annual production for each mining complex for each of the last three years and 2013 coal sales.

MINING COMPLEXES

Table 3

	Mine	Mining		Tons Produced (in Millions)						Tons Sold (1) (in Millions)		Year Established Or
Location	Type	Equipment	Transportation	2013		2012		2011		2013		Acquired
Gatliff Coal Co.
Bell County, KY/ Knox County, KY/ Campbell County, TN	S	D/L	T		0.0		0.0		0.0		0.0		1974
Clintwood Elkhorn Mining
Pike County, KY/ Buchanan County, VA	U, S	CM, D/L, HM, A	R, R/V		1.6		2.0		1.8		1.7		1988
Premier Elkhorn Coal Co.
Pike County, KY/ Letcher County, KY/ Floyd County, KY	U, S	CM, D/L	R, T, R/B, T/B, R/V		1.6		2.0		2.2		2.1		1991
Perry County Coal Co.
Perry County, KY/ Leslie County, KY/ Knott County, KY	U, S	CM, D/L, HM	R, T, R/B, T/B, R/V		2.0		2.3		3.1		2.0		2000
			Totals:		5.2		6.3		7.1		5.8

(1) Tons sold include both amounts produced by TECO Coal subsidiaries and a limited amount of purchased coal.

S – Surface

CM – Continuous Miner

U – Underground

D/L – Dozers and Front-End Loaders

HM – Highwall Miner

A – Auger

R – Rail

R/B – Rail to Barge

R/V – Rail to Ocean/Lake Vessel

T – Truck

T/B – Truck to Barge

Gatliff Coal

Gatliff Coal Company discontinued surface mine operations in Bell County, Kentucky in late autumn 2009. Poor market conditions and a depletion of the low sulfur content coal that was previously required on its sales contract led to this cessation of mining operations. Gatliff Coal had no production in 2011, 2012 or 2013, leaving a reserve base of 3.4 million recoverable tons of predominantly low sulfur underground mineable coal, which may later be recovered by Gatliff Coal or by neighboring competing coal companies for coal royalty considerations. Rich Mountain Coal Company formerly operated as a contractor for Gatliff Coal’s Tennessee production but is currently in non-producing reclamation status.

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Clintwood Elkhorn Mining

Clintwood Elkhorn Mining Company has two coal preparation facilities. One is located near Biggs, Kentucky in Pike County, and is supplied by ten underground mines. Facilities include a 125 car unit train load-out capable of loading 4,000 tons per hour. The second Clintwood Elkhorn Mining facility is located near Hurley, Virginia and is supplied by one underground mine and two surface mines. Some mines have supplied both locations during the course of the year. The second facility also includes a 100 car unit train load-out capable of loading 650 tons per hour. Principal products at both locations include High Volatile metallurgical coal and thermal coal. Products from both locations are shipped domestically to customers in North America via Norfolk Southern Corporation and vessels via the Great Lakes. International customers receive their products via ocean vessels from Lamberts Point, Virginia. CMMA completed a baseline audit for Clintwood Elkhorn for the year ended 2013. CMMA has estimated by audit methodology that there are 55.2 million recoverable tons of demonstrated coal reserves, as of Dec. 31, 2013. Of the demonstrated reserves, an estimated 46.5 million recoverable tons, or 84%, are of proven (measured) status and 8.7 million tons, or 16%, are of probable (indicated) status. All of the reserves are leased. By market category, the demonstrated reserves are: 49.5 million tons of metallurgical coal and 5.7 million tons of thermal coal. In total, Clintwood Elkhorn Mining produced 1.6 million tons of coal in 2013 and currently has a reserve base of 55.2 million recoverable tons.

Premier Elkhorn Coal Company

Located near Myra, in Pike County, Kentucky, Premier Elkhorn Coal Company is supplied by production from four underground mines and three surface mines. Principal products include metallurgical and PCI coal for the steel mills, high-quality thermal coal for utilities and specialty stoker products for ferro-silicon and industrial customers. Facilities include a unit train load-out with a 200 car siding capable of loading at 6,000 tons per hour. Products from this location are shipped via CSXT Railroad and trucking contractors to destinations in North America and internationally. In total, Premier Elkhorn Coal produced 1.6 million tons of coal in 2013 and currently has a reserve base of 103.9 million recoverable tons.

In 2011, CMMA completed an audit of the Glamorgan and Lower Banner coal deposits associated with the New Frontier Project-Burke Branch Development, which is controlled by TECO Coal’s Premier Elkhorn Coal operating subsidiary. The subject property is located in Pike and Letcher Counties in eastern Kentucky, and a substantial portion of the mineral rights for the subject coal deposits is owned by TECO Coal’s subsidiary, Pike-Letcher Land. The remainder of the mineral is leased from other entities under long-term lease agreements.

The CMMA audit reviewed the classification of the TECO Coal tons by proven and probable reserves and non-reserve coal deposit (resource) categories, based on a pro-forma economic review of the demonstrated reserve areas. TECO Coal estimates that it controls 65.0 million recoverable tons of demonstrated coal reserves within the Burke Branch Development, as of Aug. 31, 2011. Of these TECO Coal total demonstrated reserves, an estimated 56.6 million recoverable tons, or 87%, are owned and 8.4 million tons, or 13%, are leased. An additional 23.4 million tons have been estimated by TECO Coal and classified as non-reserve coal deposits (resources). These resource tons have some potential to be reclassified as reserve in the future depending on various factors such as favorable results of additional exploration, property acquisition, investment of capital for project development, improvements in coal markets or mining technology.

TECO Coal has received an amendment to an existing permit to allow surface excavation and development as well as slope access to a portion of these reserves and a revision to an existing permit to allow mining of a portion of the Lower Banner coal seam reserves. An additional amendment has been submitted to modify surface areas required for development of the slopes and shafts.

Perry County Coal Corporation

Located in Perry County, Kentucky, near Hazard, Perry County Coal Corporation is supplied by production from three underground mines and two surface mines. Principal products include PCI, high quality thermal coal for utilities, and industrial stoker products. Facilities include a 1,350 ton per hour preparation plant and a 120 car unit train load-out capable of loading 5,000 tons per hour. Products from this location are shipped via CSXT Railroad and trucking contractors.

Perry County Coal produced 2.0 million tons of coal in 2013, leaving a total reserve base of 135.7 million recoverable tons.

Sales and Marketing

The TECO Coal marketing and sales force includes sales directors, distribution/transportation managers and administrative personnel. Primary customers are steel companies, utilities and industrial plants. TECO Coal sells coal under long-term agreements, which are generally classified as greater than 12 months, and on a spot basis, which is generally classified as 12 months or less.

The terms of these coal sales contracts result from bidding and negotiations with customers. Consequently, these contracts typically vary significantly in price, quantity, quality, length, and may contain terms and conditions that allow for periodic price reviews, price adjustment mechanisms, recovery of governmental impositions as well as provisions for force majeure, suspension, termination, treatment of environmental legislation and assignment.

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Current sales are made to both domestic and European markets, and the metallurgical coal from the Burke Branch Development is expected to be marketed to new markets and customers in Europe, South America and Asia.

Distribution

TECO Coal transports coal from its mining complexes to customers by rail, barge, vessel and trucks. The company employs transportation specialists who coordinate the development of acceptable shipping schedules with our customers, transportation providers and mining facilities.

Competition

Primary competitors of TECO Coal are other coal suppliers, many of which are located in Central Appalachia. Even though consolidation and bankruptcy have decreased the number of coal suppliers, the industry is still intensely competitive. To date, TECO Coal has been able to compete for coal sales by mining specialty coals, including coals used for making coke and furnace injection, and high-quality thermal coal and by effectively managing production and processing costs.

Employees

As of Dec. 31, 2013, TECO Coal and its subsidiaries employed a total of 754 employees.

Regulations

Mine Safety and Health

The operations of underground mines, including all related surface facilities, are subject to the Federal Coal Mine Safety and Health Act of 1969, the 1977 Amendment and the Miner Act of 2006. TECO Coal’s subsidiaries are also subject to various Kentucky, Tennessee and Virginia mining laws which require approval of roof control, ventilation, dust control and other facets of the coal mining business. Federal and state inspectors inspect the mines to ensure compliance with these laws. TECO Coal believes it is in substantial compliance with the standards of the various enforcement agencies. It is unaware of any mining laws or regulations that would materially affect the market price of coal sold by its subsidiaries, although mining accidents within the industry could lead to new legislation that could impose additional costs on TECO Coal.

Black Lung Legislation

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must make payment of federal black lung benefits to claimants who are current and former employees, certain survivors of a miner who dies from black lung disease, and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1973. Historically, a small percentage of the miners currently seeking federal black lung benefits are awarded these benefits by the federal government. The trust fund is funded by an excise tax on coal production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

In December 2000, the Department of Labor issued amendments to the regulations implementing the federal black lung laws that, among other things, establish a presumption in favor of a claimant’s treating physician, limit a coal operator’s ability to introduce medical evidence, and redefine Coal Workers Pneumoconiosis to include chronic obstructive pulmonary disease. These changes in the regulations, and regulations introduced by the 2010 Patient Protection and Affordable Care Act, have slightly increased the percentage of claims approved and the overall cost of Black Lung to coal operators. While costs have risen only slightly from these changes, there is potential for additional, higher increases in the future. TECO Coal, with the help of its consulting actuaries, intends to continue monitoring claims very closely.

Workers’ Compensation

TECO Coal is liable for workers’ compensation benefits for traumatic injury and occupational exposure claims under state workers’ compensation laws. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment.

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Environmental Laws

Surface Mining Control and Reclamation Act

Coal mining operations are subject to the Surface Mining Control and Reclamation Act of 1977 which places a charge of $0.135 and $0.315 on every net ton of underground and surface coal mined, respectively, to create a fund for reclaiming land and water adversely affected by past coal mining. Other provisions establish standards for the control of environmental effects and reclamation of surface coal mining and the surface effects of underground coal mining and requirements for federal and state inspections.

Clean Air Act/Clean Water Act

While conducting their mining operations, TECO Coal’s subsidiaries are subject to various federal, state and local air and water pollution standards. In 2013, TECO Coal had expenditures of approximately $2.6 million for environmental protection and reclamation programs. TECO Coal expects to spend approximately $2.2 million on these programs in 2014.

CERCLA (Superfund)

The CERCLA – commonly known as Superfund, affects coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault.

Under the EPA’s Toxic Release Inventory process, companies are required to report annually listed toxic materials that exceed defined quantities.

Glossary of Selected Mining Terms

Assigned reserves. Coal which has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others.

Bituminous Coal. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 BTU per pound. It is dense and often has well-defined bands of bright and dull material.

BTU (British Thermal Unit). A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit.

Central Appalachia. Coal producing regions of eastern Kentucky, eastern Tennessee, western Virginia and southern West Virginia.

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”

Coal washing. The process of removing impurities, such as ash and sulfur based compounds, from coal.

Compliance coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million BTUs, which is equivalent to 0.72% sulfur per pound of 12,000 BTU coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act.

Continuous miner. A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

Continuous mining. One of two major underground mining methods now used in the United States. This process utilizes a continuous miner. The continuous miner removes or “cuts” the coal from the seam. The loosened coal then falls onto a conveyor for removal to a shuttle car or larger conveyor belt system.

Deep mine. An underground coal mine.

Dozer and Front-end loader mining. An open-cast method of mining that uses large dozers together with trucks and loaders to remove overburden, which is used to backfill pits after coal removal.

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Ferro-silicon. An alloy of iron and silicon used in the production of carbon steel.

Force Majeure. An event that may prevent the company from conducting its mining operations in whole or in part as a result of: Acts of God, wars, riots, fires, explosions, breakdowns or accidents; strikes, lockouts or other labor difficulties; lack or shortages of labor, materials, utilities, energy sources; compliance with governmental rules, regulations or other governmental requirements; or any other like causes.

High Vol Metallurgical coal. Coal that averages approximately 35% volatile matter. Volatile matter refers to a constituent that becomes gaseous when heated to certain temperatures.

Highwall miner. An auger-like apparatus that drives parallel rectangular entries from the surface up to 1,000 feet deep.

Industrial coal. Coal used by industrial steam boilers to produce electricity or process steam. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

Long-term contracts. Contracts with terms greater than 12 months.

Low ash fusion. Coal that when burned typically produces ash that has a melting point below 2,450 degrees Fahrenheit.

Low sulfur coal. Coal that when burned emits 1.6 pounds or less of sulfur dioxide per million BTUs.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality, composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal has a particularly high BTU, but low ash content.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Overburden ratio. The amount of overburden commonly stated in cubic yards that must be removed to excavate one ton of coal.

Pillar. An area of coal left to support the overlying strata in a mine, sometimes left permanently to support surface structures.

Pneumoconiosis. A lung disease caused by long-continued inhalation of mineral or metallic dust.

Preparation plant. Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

Probable (Indicated) reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Proven (Measured) reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.

Pulverized Coal Injection (PCI). A system whereby coal is pulverized and injected into blast furnaces in the production of steel and/or steel products.

Reclamation. The process of restoring land and the environment to their approximate original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Recoverable reserves. The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.

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Reserves. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

Resource (non-reserve coal deposit). A coal-bearing body that does not qualify as a commercially viable coal reserve. Resources may be classified as such by either limited property control, geologic limitations, insufficient exploration or other limitations. In the future, it is possible that portions of the resource could be re-classified as reserve if those limitations are removed or mitigated by: improving market conditions, additional property control, favorable results of exploration, advances in technology, etc.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place. Same as “top.”

Room and pillar mining. In the underground room and pillar method of mining, continuous mining machines cut three to nine entries into the coal bed and connect them by driving crosscuts, leaving a series of rectangular pillars or columns of coal to help support the mine roof and control the flow of air. As mining advances, a grid-like pattern of entries and pillars is formed. Additional coal may be recovered from the pillars as this panel of coal is retreated.

Spot market. Sales of coal under an agreement for shipments over a period of one year or less.

Thermal coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Sulfur content. Coal is commonly described by its sulfur content due to the importance of sulfur in environmental regulations. “Low sulfur” coal has a variety of definitions but is typically used to describe coal consisting of 1.0% or less sulfur. A majority of TECO Coal’s Central Appalachian reserves are of low sulfur grades.

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.

Tipple. A structure that facilitates the loading of coal into rail cars.

Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds; a “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.

Unassigned reserves. Coal that has not been committed and that would require new mineshafts, mining equipment or plant facilities before operations could begin in the property.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.

Unit train. A train of a specified number of cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

Utility coal. Coal used by power plants to produce electricity or process steam. It generally is lower in BTU heat content and higher in volatile matter than metallurgical coal.

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TECO GUATEMALA

TECO Guatemala, a wholly-owned subsidiary of TECO Energy, had subsidiaries with interests in independent power projects in Guatemala, which were sold during 2012.

TECO Guatemala indirectly owned 100% of CGESJ, the owner of an electric generating station located in Guatemala, which consisted of a single-unit pulverized-coal baseload facility (the San José Power Station). This facility was the first coal-fueled plant in Central America and meets environmental standards set by Guatemala and the World Bank. In 1996, CGESJ signed a U.S. dollar-denominated PPA with EEGSA, the largest private distribution company in Central America, to provide 120 MW of capacity and energy for 15 years beginning in 2000. TEMSA, an indirect wholly-owned subsidiary, provided unloading services to third parties in addition to receiving the coal shipments for CGESJ.

TCAE, an entity 96.06% owned by TPS Guatemala One, Ltd., an indirect subsidiary of TECO Guatemala, and the owner of an oil-fired electric generating facility (the Alborada Power Station), had a U.S. dollar-denominated PPA with EEGSA to provide 78 MW of capacity ending in 2015. EEGSA was responsible for providing the fuel for the power station, with a subsidiary of TECO Guatemala providing assistance in fuel administration.

TECO Guatemala’s plants in Guatemala operated under environmental permits issued by the local environmental authorities. At the time of construction, these facilities were built in compliance with the World Bank Guidelines of 1988 and 1994.

On Sept. 27, 2012, TECO Guatemala entered into an agreement to sell all of the equity interests in the Alborada and San José power stations, related facilities and operations in Guatemala for a total purchase price of $227.5 million in cash. The sale of the Alborada Power Station closed on the same date for a selling price of $12.5 million.

On Dec. 19, 2012, the closing occurred on the (i) San José power station and related facilities in Guatemala for a purchase price of $213.5 million and (ii) the remaining TECO Guatemala operations company for a purchase price of $1.5 million.

See Notes 19, 20 and 21 to the TECO Energy, Inc. Consolidated Financial Statements for more information regarding these discontinued operations and asset dispositions.

On Dec. 19, 2013, the ICSID tribunal hearing TGH’s arbitration claim against the Republic of Guatemala under DR-CAFTA issued an award in the case. The ICSID tribunal unanimously found in favor of TGH and awarded damages of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the prime rate plus 2%. In addition, the tribunal ruled that Guatemala must reimburse TGH for approximately $7.5 million of the costs it incurred in pursuing the arbitration.

The ICSID tribunal found that Guatemala breached its treaty obligation to grant TGH fair and equitable treatment under the terms of the DR-CAFTA, thereby causing damages to TGH for which it is entitled to compensation. In sum, the tribunal found that Guatemala’s repudiation of fundamental regulatory principles applying to the tariff review process was arbitrary and breached elementary standards of due process in administrative matters.

Each party has 120 days from the date of the award to seek annulment of the decision.

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EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, current positions and principal occupations during the last five years of the current executive officers of TECO Energy are described below.

		Current Positions and Principal
Name	Age	Occupations During The Last Five Years
John B. Ramil	58	President and Chief Executive Officer, TECO Energy, Inc., and Chief Executive Officer, Tampa Electric Company, August 2010 to date; President and Chief Operating Officer, TECO Energy, Inc., July 2004 to August 2010.
Charles A. Attal, III	54	Senior Vice President-General Counsel and Chief Legal Officer, TECO Energy, Inc., and General Counsel of Tampa Electric Company, February 2009 to date; Vice President General Counsel and Chief Legal Officer, TECO Energy, Inc. and General Counsel of Tampa Electric Company, July 2007 to February 2009.
Phil L. Barringer	60	Senior Vice President of Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., January 30, 2013 to date; Vice President of Corporate Services and Chief Human Resources Officer, TECO Energy, Inc., January 1, 2013 to January 30, 2013; Chief Human Resources Officer and Procurement Officer of Tampa Electric Company, January 2013 to date; Vice President-Human Resources of TECO Energy, Inc. and Tampa Electric Company, July 2009 to December 2012; President, TECO Guatemala, July 2009 to date (operating companies sold December 2012); and prior thereto, Vice President-Controller, Operations of TECO Energy, Inc. and Chief Accounting Officer of Tampa Electric Company.
Deirdre A. Brown	53	Senior Vice President of Corporate Strategy and Technology and Chief Ethics and Compliance Officer, TECO Energy, Inc., January 30, 2013 to date; Vice President of Business Strategy, Technology and Compliance and Chief Ethics and Compliance Officer, TECO Energy, Inc., January 1, 2013 to January 30, 2013; Vice President-Business Strategy and Compliance and Chief Ethics and Compliance Officer, TECO Energy, Inc., July 2009 to January 1, 2013; Vice President-Regulatory Affairs of Tampa Electric Company and Vice President-Customer Service, Tampa Electric Division of Tampa Electric Company, April 2006 to July 2009.
Sandra W. Callahan	61	Senior Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., February 2011 to date, and Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), Tampa Electric Company, October 2009 to date; Vice President-Finance and Accounting and Chief Financial Officer (Chief Accounting Officer), TECO Energy, Inc., October 2009 to February 2011; Vice President-Finance and Accounting and Chief Financial Officer (Treasurer and Chief Accounting Officer), TECO Energy, Inc. and Tampa Electric Company, July 2009 to October 2009; Vice President-Treasury and Risk Management (Treasurer and Chief Accounting Officer), TECO Energy, Inc., January 2007 to July 2009; Vice President-Treasurer and Assistant Secretary, Tampa Electric Company, April 2005 to July 2009.
Gordon L. Gillette	54	President, Tampa Electric Company, July 2009 to date; Executive Vice President and Chief Financial Officer, TECO Energy, Inc., July 2004 to July 2009; President, TECO Guatemala, October 2004 to July 2009.
Clark Taylor	64	President of TECO Coal Corporation, April 2011 to date; and prior thereto, Vice President-Controller of TECO Coal Corporation.

There is no family relationship between any of the persons named above or between executive officers and any director of the company. The term of office of each officer extends to the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on April 30, 2014, and until such officer’s successor is elected and qualified.

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Item 1A. RISK FACTORS.

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 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, including to European customers, and demand in that continent has been reduced due to the European debt crisis and the resulting economic weakness. Continued economic weakness and the resulting lower demand for metallurgical coal in the European and Asian 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 CO₂ post-combustion from conventional coal-fired units such as Tampa Electric’s Big Bend units. New rules requiring post-combustion CO₂ 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 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.

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In a June 25, 2013 memorandum to the EPA, President Obama directed that agency 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. The new standards for existing power plants are due in June 2014. It is unclear how the EPA may design such rules. It is likely that both rules will be subject to legal challenges and litigation, which could have a material impact on both the timing and substance of any proposed new rules.

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 a number of new rules, including the CAIR/CSAPR and Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT) for emissions to 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 proposed 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.

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 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, the company is exposed to extreme weather events, such as hurricanes. Extreme weather conditions can be destructive, causing outages and property damage that require the company 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 the company has 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.

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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 low natural gas prices and increased competition from lower cost producing areas would keep demand and selling prices low, which would reduce TECO Coal’s profitability, 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 a modest increase in natural gas prices as occurred in the second half of 2013, 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 profitability will be reduced. If these conditions were to persist, 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.

The utilities’ forecasts are based on normal weather patterns and historical trends in customer energy-usage patterns. Tampa Electric’s and PGS’s 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 Tampa Electric’s infrastructure 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.

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 Tampa Electric’s transmission and distribution system infrastructure is 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.

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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.

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.

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 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.

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.

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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 in Europe and 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. 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.

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.

Risks Associated With the Acquisition of New Mexico Gas Company

The acquisition of NMGI may not be completed or regulatory approval may be subject to unfavorable conditions, and if completed, changing market conditions, associated costs and other factors prior to, or following, the acquisition, could adversely affect the anticipated benefits of the transaction and the company’s results.

On May 25, 2013, the company entered into a stock purchase agreement to acquire the common stock of NMGI, the parent company of NMGC. In order to complete this transaction, the company must obtain approval from the NMPRC. The NMPRC 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 impact 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 the company’s business, financial condition, results of operations or stock price.

In order to finance the New Mexico Gas acquisition, we plan to incur additional indebtedness and issue equity securities, which could have an adverse effect on our financial health.

We currently expect to finance the New Mexico Gas acquisition with a combination of TECO Energy common equity, cash on hand and long-term debt at NMGC and NMGI. 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 issuance of equity securities will result 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 permanent financing we expect, 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.

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The closing of the NMGC acquisition may be delayed, which would delay the realization of accretion to our earnings from the acquisition.

As previously disclosed, TECO Energy must obtain approval for the acquisition from the NMPRC prior to closing the transaction. On Dec. 2, 2013, the Hearing Examiner, in the application for approval of the acquisition, issued an order approving the motion filed by TECO Energy, Inc., NMGC, Continental Energy Systems LLC, the Staff of the NMPRC, and the New Mexico Attorney General’s Office (the “Parties”) requesting additional time for proceedings in the matter.

On Jan. 10, 2014, a meeting was held with the Parties and the Hearing Examiner to establish a new schedule. The new key dates established in that meeting are: Staff and intervenor testimony due on or before Feb. 28, 2014, hearings before the Hearing Examiner to follow on March 24 to 28, 2014. The date for a final decision is yet to be determined. With this schedule, closing will likely occur in the third quarter of 2014.

At the time of the acquisition announcement in May 2013, based on certain schedule assumptions, TECO Energy had indicated that with a closing in the first quarter of 2014, it expected the transaction to be accretive to earnings in the first full year post-closing in 2015. With the new projected schedule and less time to achieve full integration in 2014, the transaction is now expected to begin to be accretive to earnings twelve months after closing.

Profitability at NMGC is heavily dependent upon the sale of energy for residential heating. Warmer-than-normal weather conditions, the effects of global warming and climate change, or other factors that influence customer energy usage may affect NMGC’s energy sales and adversely impact its financial position.

NMGC’s earnings are primarily generated by the sale of natural gas for residential heating. Significantly warmer-than-normal weather conditions, or other factors such as global warming or climate change may results in reduced natural gas sales and lower profitability.

In connection with the acquisition of NMGC, 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. See the Credit Facilities section and Significant Financial Covenants table in the Liquidity, Capital Resources sections of the Management’s Discussion & Analysis for descriptions of these tests and covenants.

As of Dec. 31, 2013, 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.

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, Capital Resources sections of the Management’s Discussion & Analysis.

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 of which it expects to refinance a portion. 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. Although we believe we have appropriate credit policies in place to manage the non-performance risk associated with these transactions, 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.

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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 Jan. 1, 2014 measurement date, the funded percentage of our plan is expected to be approximately 98%. 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.

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, Tampa Electric and PGS are 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.

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

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.

Item 1B. UNRESOLVED STAFF COMMENTS.

None.

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Item 2. PROPERTIES.

TECO Energy believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric are subject to a first mortgage bond indenture under which no bonds are currently outstanding.

TAMPA ELECTRIC

Tampa Electric has three electric generating stations in service, with a December 2013 net winter generating capability of 4,668 MW. Tampa Electric assets include the Big Bend Power Station (1,572 MW capacity from four coal units and 61 MW from a CT), the Bayside Power Station (1,839 MW capacity from two natural gas combined cycle units and 244 MW from four CTs) and the Polk Power Station (220 MW capacity from the IGCC unit and 732 MW from four CTs).

The Big Bend coal fired units went into service from 1970 to 1985 and the CT was installed in 2009. The Polk IGCC unit began commercial operation in 1996. Bayside Unit 1 was completed in April 2003, Unit 2 was completed in January 2004 and Units 3 through 6 were completed in 2009. In 2009, Tampa Electric placed the Phillips Power Station on long-term reserve standby. In July of 2012, Tampa Electric placed the City of Tampa Partnership Station in long-term reserve standby.

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,330 Mega Volts Amps. The transmission system consists of approximately 1,310 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 6,292 pole miles of overhead lines and 4,851 trench miles of underground lines. As of Dec. 31, 2013, there were 671,381 meters in service. All of this property is located in Florida.

All plants and important fixed assets are held in fee except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances and minor defects of a nature common to properties of the size and character of those of Tampa Electric.

Tampa Electric has easements or other property rights for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. It has the power of eminent domain under Florida law for the acquisition of any such rights-of-way for the operation of transmission and distribution lines. Transmission and distribution lines located in public ways are maintained under franchises or permits.

TEC has a long-term lease for the office building in downtown Tampa which serves as headquarters for TECO Energy, Tampa Electric and PGS.

PEOPLES GAS SYSTEM

PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 18,300 miles of pipe, including approximately 11,600 miles of mains and 6,700 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

PGS’s operations are located in 14 operating divisions throughout Florida. While most of the operations and administrative facilities are owned, a small number are leased.

TECO COAL

Property Control

Operations of TECO Coal and its subsidiaries are conducted on both owned and leased properties totaling approximately 294,000 acres in Kentucky, Tennessee and Virginia. TECO Coal’s current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property. As is typical in the coal mining industry, TECO Coal generally has not obtained title insurance in connection with its acquisitions of coal reserves and/or related surface properties. In many cases, the seller or lessor will grant the purchasing or leasing entity a warranty of property title. When leasing coal reserves and/or related surface properties where mining has previously occurred, TECO Coal may opt not to perform a separate title confirmation due to the previous mining activities on such a property. In cases involving less significant properties and consistent with industry practices, title and boundaries to less significant properties are now verified during lease or purchase negotiations.

In situations where property is controlled by lease, the lease terms are generally sufficient to allow the reserves for the associated operation to be mined within the initial lease term. The terms of many of these leases extend until the exhaustion of the mineable and merchantable coal from the leased property. If, however, extensions of the original lease term become necessary, provisions have generally been made within the original lease to extend the lease term upon continued payment of minimum royalties.

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Coal Reserves

As of Dec. 31, 2013, the TECO Coal operating companies had a combined estimated 298.2 million tons of proven and probable recoverable reserves. All of the reserves consist of high quality bituminous coal. Reserves are the portion of the proven and probable tonnage that meet TECO Coal’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels. Additionally, other controlled areas presently identified as resource total 69.6 million tons of coal.

Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

Proven (Measured) Reserves - Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, working or drill holes: grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Probable (Indicated) Reserves - Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but for which the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Drill hole spacing for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). In this method of classification, “proven” reserves are considered to be those lying within one-quarter mile (1,320 feet) of a valid point of measurement and “probable” reserves are those lying between one-quarter mile and three-quarters mile (3,960 feet) from such an observation point.

Reserve estimates are prepared by TECO Coal’s staff of geologists. There are two chief geologists with the responsibility to track changes in reserve estimates, supervise TECO Coal’s other geologists and coordinate third party reviews of reserve estimates by qualified mining consultants. Annually, a third-party reserve audit is performed by CMMA on TECO Coal’s newly identified reserves. The results of that audit are reflected in the numbers within this report.

The following table (Table 4) shows recoverable reserves by quantity and the method of property control as well as the Assigned and Unassigned reserves per mining complex.

RECOVERABLE RESERVES BY QUANTITY⁽¹⁾

(Millions of tons)

Table 4

												Assigned(2)				Unassigned(2)
Mining Complex	Location	Total		Proven		Probable		Owned		Leased		2014		2013		2014		2013
Gatliff Coal	Bell County, KY/ Knox County, KY/ Campbell County, TN		3.4		3.0		0.4		1.2		2.2		0.5		0.5		2.9		2.9
Clintwood Elkhorn Mining	Pike County, KY/ Buchanan County, VA		55.2		46.5		8.7		0.0		55.2		55.2		60.8		0.0		0.0
Premier Elkhorn Coal	Pike County, KY/Letcher County, KY/ Floyd County, KY		103.9		63.4		40.5		85.0		18.9		52.9		58.6		51.0		51.0
Perry County Coal	Perry County, KY/ Leslie County, KY/ Knott County, KY		135.7		87.5		48.2		1.4		134.3		130.5		131.9		5.2		5.2
Totals:			298.2		200.4		97.8		87.6		210.6		239.1		251.8		59.1		59.1

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Notes:

(1) Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. Reserve information reflects a moisture of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.

(2) Assigned reserves means coal which has been committed by TECO Coal to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by TECO Coal to others. Unassigned reserves represent coal which has not been committed, and which would require new mineshafts, mining equipment, or plant facilities before operations could begin in the property.

RECOVERABLE RESERVES BY QUALITY⁽¹⁾

(Millions of tons)

Table 5

	Recoverable		Sulfur Content						Average BTU
Mining Complex	Reserves		< 1%(2)		>1%(2)		Compliance Tons(3)		As received	Coal Type(4)
Gatliff Coal		3.4		3.2		0.2		0.0	12,000-13,100	LSU
Clintwood Elkhorn Mining		55.2		41.4		13.8		14.8	12,500-13,500	HVM, LSU, PCI
Premier Elkhorn Coal		103.9		88.5		15.4		57.0	12,700-13,100	HVM, IS, LSU, PCI
Perry County Coal		135.7		106.0		29.7		82.8	12,500-13,100	LSU, PCI, V
Totals:		298.2		239.1		59.1		154.6

Notes:

(1) Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.

(2) <1% or >1% refers to sulfur content as a percentage in coal by weight.

(3) Compliance coal is any coal that emits less than 1.2 pounds of sulfur dioxide per million BTU when burned. Compliance coal meets sulfur emission standards imposed by Title IV of the Clean Air Act.

(4) Reserve holdings include metallurgical, PCI and thermal coal reserves. Although metallurgical and PCI coal reserves receive the highest selling price in the current market when marketed to steel-making customers, they can also be marketed as an ultra-high BTU, low sulfur utility coal for electricity generation.

HVM – High Vol Metallurgical

PCI – Pulverized Coal Injection

LSU – Low Sulfur Utility

V – Various

IS – Industrial Stoker

Market Allocation of Reserves

The table below shows the allocation of TECO Coal reserves by market category (metallurgical, PCI, and thermal coal), which was prepared by TECO Coal at its four operating subsidiaries. As shown below, a substantial portion of the Clintwood Elkhorn Mining coal reserves has been allocated to the metallurgical category (with the remainder to the thermal coal category), a substantial portion of the Premier Elkhorn Coal reserves has been allocated to the PCI and metallurgical categories (with the remainder to the thermal coal category), a substantial portion of the Perry County coal reserves has been allocated to the PCI category (with the remainder to the thermal coal category), and all of the Gatliff Coal reserves has been allocated to the thermal coal category.

At TECO Coal’s request, CMMA completed an audit of the methodology used by TECO Coal to conduct such allocation of its coal tonnage estimates. CMMA reviewed information provided by TECO Coal and TECO Coal’s methodology of processing, which included examination by certified professional geologists of all supplied coal deposit maps and supporting coal quality data using industry-accepted standards. The audit performed by CMMA concluded that TECO Coal’s methodology of allocating its demonstrated reserves by market category is reasonably and responsibly prepared in accordance with industry accepted standards and in general conformance with SEC Industry Guide 7.

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Market conditions may not always permit sales of coal into the particular market as identified, however the objective of this reserve allocation is to recognize the market potential for planning and investment purposes.

The following table (Table 6) shows the recoverable reserves by market category per mining complex and in total. The total reserve mix is defined by percentage as 40% metallurgical, 40.6% PCI, (for a combined 80.6% specialty coals) and 19.4% thermal coal.

RESERVES BY MARKET CATEGORY

Table 6

Mining Complex	Met Reserves							PCI Reserves							Thermal Reserves							Grand Totals
	Proven		Probable		Total			Proven		Probable		Total			Proven		Probable		Total
Gatliff Coal		0.0		0.0		0.0			0.0		0.0		0.0			2.8		0.6		3.4			3.4
Clintwood Elkhorn Mining		41.4		8.1		49.5			0.0		0.0		0.0			0.0		5.7		5.7			55.2
Premier Elkhorn Coal		33.4		36.0		69.4			13.2		2.0		15.2			16.8		2.5		19.3			103.9
Perry County Coal		0.0		0.0		0.0			67.5		38.5		106.0			19.9		9.8		29.7			135.7
Totals:		74.8		44.1		118.9			80.7		40.5		121.2			39.5		18.6		58.1			298.2
% of Totals:						39.9	%						40.6	%						19.5	%

Reserve Estimation Procedure

TECO Coal’s reserves are based on over 3,800 data points, including drill holes, prospect measurements and mine measurements. Reserve estimates also include information obtained from on-going exploration drilling and in-mine channel sampling programs. Reserve classification is determined by evaluation of engineering and geologic information along with economic analysis. These reserves are adjusted periodically to reflect fluctuations in the economics in the market and/or changes in engineering parameters and/or geologic conditions. Additionally, the information is constantly being updated to reflect new data for existing property as well as new acquisitions and depleted reserves.

This data may include elevation, thickness, and where samples are available, the quality of the coal from individual drill holes and channel samples. The information is assembled by geologists and engineers at TECO Coal, and is computer modeled from which preliminary reserve estimations are generated. The information derived from the geological database is then combined with data on ownership or control of the mineral and surface interests to determine the extent of the reserves in a given area. Determinations of reserves are made after in-house geologists have reviewed the computer generated models and enhanced the grid models to better reflect regional trends.

During TECO Coal’s reserve evaluation and mine planning, TECO Coal takes into account factors such as restrictions under railroads, roads, buildings, power lines, or other structures. Depending on these factors, coal recovery may be limited or, in some instances, entirely prohibited. Current engineering practices are used to determine potential subsidence zones. The footprint of the relevant structure, as well as a safety angle-of-draw, is considered when mining near or under such facilities. Also, as part of TECO Coal’s reserve and mineability evaluation, TECO Coal reviews legal, economic and other technical factors. Final review and recoverable reserve determination is completed after a thorough analysis by in-house engineers, geologists and finance associates.

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Item 3. LEGAL PROCEEDINGS.

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, material 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 or financial condition.

For a discussion of certain legal proceedings and environmental matters, including an update of previously disclosed legal proceedings and environmental matters, see Notes 12 and 9, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.

Item 4. MINE SAFETY DISCLOSURES.

TECO Coal is subject to regulation by the MSHA under the Federal Mine Safety and Health Act of 1977 (the Mine Act). 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 (the Dodd-Frank Act) and the adopted Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this annual report.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The following table shows the high and low sale prices for shares of TECO Energy common stock, which is listed on the New York Stock Exchange, and dividends paid per share, per quarter.

	1 st Quarter		2 nd Quarter		3 rd Quarter		4 th Quarter
2013
High	$	17.87	$	19.22	$	17.99	$	17.75
Low		16.71		16.40		16.15		16.40
Close		17.82		17.19		16.54		17.24
Dividend	$	0.22	$	0.22	$	0.22	$	0.22
2012
High	$	19.41	$	18.33	$	18.64	$	18.14
Low		17.35		16.90		17.26		16.12
Close		17.55		18.06		17.74		16.76
Dividend	$	0.22	$	0.22	$	0.22	$	0.22

The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 14, 2014 was 11,476.

Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends to its common shareholders are dividends and other distributions from its operating companies.

See Liquidity, Capital Resources – Covenants in Financing Agreements section of MD&A, and Notes 6, 7 and 12 to the TECO Energy Consolidated Financial Statements for additional information regarding significant financial covenants.

All of TEC’s common stock is owned by TECO Energy and, therefore, there is no market for the stock. TEC pays dividends on its common stock substantially equal to its net income. Such dividends totaled $222.1 million in 2013, $228.3 million in 2012 and $240.7 million in 2011. See the Restrictions on Dividend Payments and Transfer of Assets section in Note 1 to the Tampa Electric Company Consolidated Financial Statements for a description of restrictions on dividends on its common stock.

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Set forth below is a table showing shares of TECO Energy common stock deemed repurchased by the issuer.

	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
Oct. 1, 2013 – Oct. 31, 2013		771	$	16.95		0.0		0.0
Nov. 1, 2013 – Nov. 30, 2013		6,957	$	17.06		0.0		0.0
Dec. 1, 2013 – Dec. 31, 2013		469	$	16.96		0.0		0.0
Total 4th Quarter 2013		8,197	$	17.04		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.

Shareholder Return Performance Graph

The following graph shows the cumulative total shareholder return on TECO Energy’s common stock on a yearly basis over the five-year period ended Dec. 31, 2013, and compares this return with that of the S&P 500 Index, the S&P Multi Utility Index and the Dow Jones U.S. Coal Index. The graph assumes that the value of the investment in TECO Energy’s common stock and each index was $100 on Dec. 31, 2008 and that all dividends were reinvested.

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Item 6. SELECTED FINANCIAL DATA OF TECO ENERGY, INC.

(millions, except per share amounts)
Years ended Dec. 31,	2013			2012			2011		2010		2009
Revenues (1)	$	2,851.3		$	2,996.6		$	3,209.9	$	3,363.5	$	3,302.2
Net income from continuing operations (1)		197.8			246.0			250.8		211.6		182.4
Net income from discontinued operations attributable to TECO Energy (1)		(0.1	)		(33.3	)		21.8		27.4		31.5
Net income attributable to TECO Energy		197.7			212.7			272.6		239.0		213.9
Total assets		7,448.0			7,334.9			7,307.2		7,270.9		7,219.5
Long-term debt, including current portion		2,921.1			2,972.7			3,073.4		3,226.4		3,309.5
EPS - Basic
From continuing operations (1)	$	0.92		$	1.14		$	1.17	$	0.99	$	0.85
From discontinued operations attributable to TECO Energy (1)		0.00			(0.15	)		0.10		0.13		0.15
Attributable to TECO Energy	$	0.92		$	0.99		$	1.27	$	1.12	$	1.00
EPS - Diluted
From continuing operations (1)	$	0.92		$	1.14		$	1.17	$	0.98	$	0.85
From discontinued operations attributable to TECO Energy (1)		0.00			(0.15	)		0.10		0.13		0.15
Attributable to TECO Energy	$	0.92		$	0.99		$	1.27	$	1.11	$	1.00
Dividends paid per common share outstanding	$	0.880		$	0.880		$	0.850	$	0.815	$	0.800

(1) Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19 to the TECO Energy Consolidated Financial Statements.

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Item 7.

MANAGEMENT’S DISCUSSION & ANALYSIS

OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS

This Management’s Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. Such statements are based on our current expectations as of the date we filed this report, and we do not undertake to update or revise such forward-looking statements, except as may be required by law. These forward-looking statements include references to our anticipated capital expenditures, liquidity and financing requirements, projected operating results, future environmental matters, and regulatory and other plans. Important factors that could cause actual results to differ materially from those projected in these forward-looking statements are discussed under “Risk Factors.”

TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management’s Discussion & Analysis, “we,” “our,” “ours” and “us” refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.

OVERVIEW

We are an energy-related holding company with regulated electric and gas utility operations in Florida, Tampa Electric and PGS, respectively. In May 2013, we signed an agreement to acquire the largest regulated gas distribution utility in New Mexico which, upon closing would increase our regulated customer base by approximately 50%. Our only remaining unregulated business is TECO Coal, which owns and operates coal production facilities in the Central Appalachian coal production region.

Our regulated utilities, Tampa Electric and PGS, operate in the Florida market. Tampa Electric serves almost 695,000 retail customers in a 2,000-square-mile service area in West Central Florida and has electric generating plants with a winter peak generating capacity of 4,668 MW. PGS, Florida’s largest gas distribution utility, serves approximately 347,000 residential, commercial, industrial and electric power generating customers in all major metropolitan areas of the state, with a total natural gas throughput of almost 1.7 billion therms in 2013.

Our unregulated business, TECO Coal, through its subsidiaries operates surface and underground mines and related coal-processing facilities in eastern Kentucky, southwestern Virginia and Tennessee, producing metallurgical-grade and high-quality steam coals. Sales in 2013 were 5.8 million tons.

In 2012, we sold our ownership interest in TECO Guatemala, which through its subsidiaries, owned a coal-fired generating facility and a 96% ownership interest in an oil-fired peaking power generating plant, both in Guatemala.

PENDING ACQUISITION OF NMGI

In May 2013, we announced the signing of an agreement to acquire the regulated natural gas distribution utility NMGC for $950 million including the assumption of $200 million of existing NMGC debt, subject to customary closing adjustments. Under the terms of the agreement, TECO Energy will acquire NMGI, the owner of NMGC. The transaction is subject to approval by the NMPRC. The federal approval process, a Hart-Scott-Rodino antitrust review, was completed without comment in 2013. The transaction is expected to be accretive to earnings beginning 12 months after closing.

NMGC serves approximately 509,000, primarily residential, customers throughout New Mexico. Upon closing of the transaction, TECO Energy subsidiaries will serve more than 1.5 million regulated electric and gas utility customers in Florida and New Mexico. NMGC has approximately 740 employees, and the majority of its customers are located in the Central Rio Grande Corridor region, which is one of the fastest growing regions in the state. The company serves approximately 60 percent of the state’s population with customers in 23 of New Mexico’s 33 counties. Customers are served through a combination of approximately 1,600 miles of transmission pipeline and 10,000 miles of distribution lines.

The transaction is supported by a fully committed bridge financing facility. The permanent financing is expected to be a combination of $350 to $400 million of TECO Energy common equity, cash on hand and approximately $250 million of long-term debt at NMGI and NMGC.

        As discussed above, the acquisition is subject to approval by the NMPRC. In July 2013, we filed a joint application with NMGC and Continental Energy Systems LLC with the NMPRC for approval of the acquisition. On Dec. 2, 2013, the Hearing Examiner in the application for approval of the acquisition issued an order approving the motion filed by TECO Energy, Inc., NMGC, Continental Energy Systems LLC, the Staff of the NMPRC, and the New Mexico Attorney General’s Office (the “Parties”) requesting additional time for proceedings in the matter.

On Jan. 10, 2014, the Parties and the Hearing Examiner met to establish a new schedule. The new key dates established in that meeting are: Staff and intervenor testimony due on or before Feb. 28, hearings before the Hearing Examiner to follow on March 24 to 28. The date for a final decision is yet to be determined. With this schedule, closing will likely occur in the third quarter of 2014. Also under this schedule, closing of the transaction will not occur by July 24, 2014, which will trigger the need to file a new Hart-Scott-Rodino Premerger Notification and Report Form with the Department of Justice. Closing of the transaction would be subject to renewed clearance from anti-trust regulators and expiration of the new waiting period under the filings.

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Except where specifically noted and discussed this MD&A excludes the impact of NMGC and related financing activities on our expected financial results throughout the forecast periods presented herein. (See the Item 1A Risk Factors, Financing Activities Related to NMGC, Credit Facility Related to NMGC and TECO Finance Bridge Facility Related to NMGC sections and See Note 22 to the TECO Energy Consolidated Financial Statements.)

2013 PERFORMANCE

All amounts included in this MD&A are after tax, unless otherwise noted.

In 2013, our net income attributable to TECO Energy was $197.7 million, or $0.92 per share, compared with $212.7 million, or $0.99 per share, in 2012. Net income from continuing operations was $197.8 million, or $0.92 per share, in 2013, compared with $246.0 million, or $1.14 per share, in 2012.

In 2013, non-GAAP results from continuing operations, which exclude $6.2 million of costs associated with the pending acquisition of NMGC, were $204.0 million, or $0.95 on a per-share basis, compared with $246.0 million, or $1.14 per share, in 2012 when there were no adjustments to GAAP results.

The most significant factor impacting the year-over-year-comparison of results was the impact of weak coal markets, which reduced TECO Coal’s earnings by $41.2 million. Tampa Electric and PGS benefited from customer growth of 1.5% and 1.3%, respectively, and therm sales and net income at the gas utility increased. While we expected Tampa Electric’s 2013 results to be lower than 2012, initial revenues from its rate settlement became effective in November and significantly mitigated the impact of the rate base and O&M expense growth that had necessitated the company’s 2013 rate filing.

Major events in 2013 included Tampa Electric’s base rate case settlement, receiving final approval for Tampa Electric’s Polk Power Station generation expansion project, and activities toward achieving a successful closing and integration of NMGC in 2014. In September, the FPSC approved a settlement agreement among Tampa Electric and intervenors that resolved all issues in Tampa Electric’s 2013 base rate case and provided for additional base rates to become effective in 2017 at the time the generation expansion project commences service, thus eliminating the need for an additional rate case in 2016 and providing revenue clarity for at least four years (see the Tampa Electric section). In 2013, Tampa Electric obtained the final approvals for the conversion of the Polk Power Station Units 2-5 from peaking service to combined cycle. The final air emissions permits were received in January 2014, and construction commenced at that time.

In 2012, net income was $212.7 million, or $0.99 per share, compared with $272.6 million, or $1.27 per share, in 2011. The 2012 full-year net income from continuing operations was $246.0 million, or $1.14 per share, compared with $250.8 million, or $1.17 per share, in 2011. The 2012 full-year loss reported in discontinued operations, which was related to the sale of TECO Guatemala, was $33.3 million, or $0.15 per share, compared with net income of $21.8 million, or $0.10 per share, in 2011.

There were no charges or gains to cause non-GAAP results to differ from net income in 2012 or in 2011.

OUTLOOK

Our outlook for 2014 results reflects our expectations that our Florida utilities will deliver strong earnings growth and returns at or above the middle of their allowed ROE ranges, and that TECO Coal results will be about break-even and cash positive. We expect that the combined earnings growth of our two regulated Florida utilities will exceed 13% in 2014. The major driver for Tampa Electric is the expected $50 million of higher base revenues as a result of the 2013 rate settlement. We expect that O&M expenses in 2014 will be lower than 2013, and that continued growth in the local economy will yield annual customer growth similar to 2013. As construction spending on the Polk Power Station increases, Tampa Electric is expected to have higher AFUDC earnings as well. We anticipate that PGS will earn above the midpoint of its allowed ROE range of 9.75% to 11.75%, with continued customer growth as well as volume growth, driven in part by positive trends in the state and local economies and continued interest in converting vehicle fleets to compressed natural gas.

The drivers impacting 2014 are summarized below and discussed in further detail in the individual operating company sections. The discussion below excludes any impact from the acquisition of NMGC or related financing activities. Results from NMGC will depend on the timing of the closing, the interest rate on the debt to be issued and the number of shares sold to finance the transaction, among other factors.

        Tampa Electric expects customer growth in 2014 to continue at a pace similar to 2013, with 1.5% higher average number of customers. Total retail energy sales growth is expected to average about 0.5% lower than customer growth due to lower average customer usage. Sales to the lower margin industrial-phosphate customers are expected to be lower in 2014 due to increased self-generation from new generating and transmission facilities owned by these customers, after the in-service dates for these facilities were delayed in 2013. PGS expects customer growth consistent with trends in 2013 when the average number of customers increased 1.2%. PGS expects energy sales volumes to be higher than in 2013, assuming normal weather conditions, as mild winter temperatures reduced natural gas volumes sold in 2013. It also expects to benefit from customers converting from petroleum and other fuel sources to natural gas due to the attractive economics. Interest in compressed natural gas (CNG) vehicle fleets is growing steadily with additional filling stations and more vehicle conversions expected in 2014.

Due to the current very weak domestic and international coal market conditions, we expect TECO Coal’s results to be about break even, but cash positive at the middle of the cost and sales guidance ranges in 2014. TECO Coal expects to sell between 5.5 and 6.0 million tons in 2014 with 80% of its sales contracted and priced, 15% of its sales committed but subject to quarterly price adjustments, and 5% unsold. The average selling price across all products is expected to be $80 per ton, which is $5 per ton lower than in 2013, while the fully-loaded, all-in cost of production is expected to be in a range between $79 and $83 per ton, which is lower than the $84 per ton average cost in 2013 and reflects the benefit of actions taken in 2013 to reduce costs.

These forecasts are based on our current assumptions described in each operating company discussion, which are subject to risks and uncertainties (see the Risk Factors section).

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Our priority for the use of cash is investment in our Florida utilities to support their capital spending programs while maintaining their capital structures and financial integrity, and over time reduction of parent debt. In 2014, we will use cash on hand to fund a portion of the NMGC acquisition. In 2014, we expect to make additional equity contributions to Tampa Electric and PGS of $125 million and $25 million, respectively. Our opportunities to invest capital in Tampa Electric are expected to grow significantly over the next several years as it completes its next increment of new generating capacity. We anticipate capital spending in 2014 to increase to $700 million at the regulated Florida utilities, including the investments in generating capacity additions at Tampa Electric and opportunities to grow the PGS system described below (see the Liquidity, Capital Resources section).

TECO Coal, with its dedicated work force and management team, has delivered strong earnings and cash flow to us for many years. With our focus clearly on growing our regulated operations, we do not consider TECO Coal to be a core holding. The coal business is a commodity business, which, by its nature, is cyclical with earnings volatility, which is not the earnings profile we believe our investors seek. If an opportunity to sell TECO Coal presents itself, we would consider such an offer. In the event of a sale of this business, we could use the proceeds to pay for a portion of the acquisition of NMGC, or repay parent debt. However, at this time a sale of TECO Coal on acceptable terms is uncertain.

We have evaluated trends, strategies and opportunities affecting our regulated utilities, to sharpen the focus on developing longer-range plans to take advantage of emerging growth opportunities and some fundamental changes in our industry. Over time, we expect these initiatives to contribute to organic earnings growth. Some of the areas that we are currently focused on include:

• We believe there are opportunities to grow the use of CNG for fleet vehicles. In 2013, the Florida legislature enacted legislation supportive of CNG vehicle conversions through rebates and tax incentives. To date, we have had success working with fleet owners to install 21 CNG filling stations with completed conversions or planned conversions in 2014 of almost 1,000 vehicles of various sizes to CNG. The number of vehicles already converted or committed to conversion will consume almost 10 million therms annually, the equivalent consumption of more than 43,000 typical residential customers. Such conversions offer compelling economics to customers, and expand PGS therm sales without significant capital investment by PGS.

• We are looking closely at Smart Grid applications that have proven technology and offer operating and financial benefits to our overall operations. These include, among other opportunities, transitioning automatic meter reading technology to advanced metering infrastructure, which would include a significant investment in our communications infrastructure but would also result in O&M expense savings.

• We also recognize that there is a growing demand for natural gas generation in Florida over the next decade. We project that Florida may need between 0.8 and 1.25 billion cubic feet per day (Bcf/day) by as early as 2016. Given our expertise in this area, we continue to evaluate opportunities to partner with transmission and end-use natural gas customers.

At PGS, the business model for system expansion evolved over the past several years to focus on extending the system to serve large commercial and industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future make it attractive for these customers to convert from fuels that are currently more expensive on a cost per MMBTU basis.

Previously, during periods of robust residential growth, PGS extended its system to serve large residential housing developments, and commercial growth followed the residential development. In the current environment where fewer large residential projects are being developed, commercial and industrial-led expansion allows PGS to continue to provide clean and economical natural gas to areas of the state previously unserved and to be positioned to serve future residential growth.

RESULTS SUMMARY

The table below compares our GAAP net income to our non-GAAP results. A reconciliation between GAAP net income and non-GAAP results is contained in the Reconciliation of GAAP net income from continuing operations to non-GAAP results tables for 2013. A non-GAAP financial measure is a numerical measure that includes or excludes amounts, or is subject to adjustments that have the effect of including or excluding amounts that are excluded or included from the most directly comparable GAAP measure (see the Non-GAAP Information section).

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Results Comparisons

(millions)	2013		2012		2011
Net income attributable to TECO Energy	$	197.7	$	212.7	$	272.6
Net income from continuing operations	$	197.8	$	246.0	$	250.8
Non-GAAP results from continuing operations	$	204.0	$	246.0	$	250.8

The table below provides a summary of revenues, earnings per share, net income and shares outstanding for the 2013-2011 period.

Earnings Summary

(millions) Except per-share amounts	2013			2012			2011
Consolidated revenues	$	2,851.3		$	2,996.6		$	3,209.9
Earnings per share – basic
Earnings per share from continuing operations	$	0.92		$	1.14		$	1.17
Earnings (loss) per share from discontinued operations		—			(0.15	)		0.10
Earnings per share attributable to TECO Energy	$	0.92		$	0.99		$	1.27
Earnings per share – diluted
Earnings per share from continuing operations	$	0.92		$	1.14		$	1.17
Earnings (loss) per share from discontinued operations		—			(0.15	)		0.10
Earnings per share attributable to TECO Energy	$	0.92		$	0.99		$	1.27
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Net income (loss) from discontinued operations		(0.1	)		(33.3	)		21.8
Net income attributable to TECO Energy		197.7			212.7			272.6
Charges and (gains)(1)		6.2			—			—
Non-GAAP results	$	204.0		$	212.7		$	272.6
Average common shares outstanding (millions)
Basic		215.0			214.3			213.6
Diluted		215.5			215.0			215.1

(1) See the GAAP to non-GAAP reconciliation table that follows.

The following table shows the specific adjustments made to GAAP net income for each segment to develop our 2013 non-GAAP results.

There were no charges or gains in 2012 or 2011 to cause non-GAAP results to differ from net income from continuing operations.

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2103 Reconciliation of GAAP Net Income to Non-GAAP Results

Net income impact (millions)	Tampa Electric		PGS		TECO Coal		Parent/ other(1)			Total Continuing Operations		Discontinued Operations(1)			Total
GAAP Net income attributable to TECO Energy	$	190.9	$	34.7	$	9.0	$	(36.8	)	$	197.8	$	(0.1	)	$	197.7
Costs associated with the acquisition of NMGC		—		—		—		6.2			6.2		—			6.2
Total charges		—		—		—		6.2			6.2					6.2
Non-GAAP results	$	190.9	$	34.7	$	9.0	$	(30.6	)	$	204.0	$	(0.1	)	$	203.9

(1) Certain costs previously included in Parent/other have been recast to Discontinued Operations.

NON-GAAP INFORMATION

From time to time, in this MD&A, we provide non-GAAP results, which present financial results after elimination of the effects of certain identified charges and gains. In 2012 and 2011, there were no charges or gains to cause non-GAAP results to differ from net income from continuing operations. We believe that the presentation of this non-GAAP financial performance provides investors a measure that reflects the company’s operations under our business strategy. We also believe that it is helpful to present a non-GAAP measure of performance that clearly reflects the ongoing operations of our business and allows investors to better understand and evaluate the business as it is expected to operate in future periods. Management and the board of directors use this non-GAAP presentation as a yardstick for measuring our performance, making decisions that are dependent upon the profitability of our various operating units and in determining levels of incentive compensation.

The non-GAAP measure of financial performance we use is not a measure of performance under accounting principles generally accepted in the United States and should not be considered an alternative to net income or other GAAP figures as an indicator of our financial performance or liquidity. Our non-GAAP presentation of results may not be comparable to similarly titled measures used by other companies.

While none of the particular excluded items are expected to recur, there may be adjustments to previously estimated gains or losses related to the disposition of assets or additional debt extinguishment activities. We recognize that there may be items that could be excluded in the future. Even though charges may occur, we believe the non-GAAP measure is important in addition to GAAP net income for assessing our potential future performance, because excluded items are limited to those that we believe are not indicative of future performance.

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OPERATING RESULTS

This MD&A utilizes TECO Energy’s consolidated financial statements, which have been prepared in accordance with GAAP, and separate non-GAAP measures to analyze the financial condition of the company. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, asset impairment testing and others (see the Critical Accounting Policies and Estimates section).

The following table shows the segment revenues, net income and earnings per share contributions from continuing operations of our business segments on a GAAP basis (see Note 14 to the TECO Energy Consolidated Financial Statements).

(millions) Except per share amounts		2013			2012			2011
Segment revenues (1)
Regulated companies	Tampa Electric	$	1,950.5		$	1,981.3		$	2,020.6
	PGS		393.5			398.9			453.5
Total regulated		$	2,344.0		$	2,380.2		$	2,474.1
	TECO Coal	$	496.2		$	608.9		$	733.0
Net income (2)
Regulated companies	Tampa Electric	$	190.9		$	193.1		$	202.7
	PGS		34.7			34.1			32.6
Total regulated			225.6			227.2			235.3
	TECO Coal		9.0			50.2			51.5
	Parent/other(4)		(36.8	)		(31.4	)		(36.0	)
Net income from continuing operations			197.8			246.0			250.8
Net income (loss) from discontinued operations			(0.1	)		(33.3	)		21.8
Net income attributable to TECO Energy		$	197.7		$	212.7		$	272.6
Earnings per share - basic (2)(3)
Regulated companies	Tampa Electric	$	0.89		$	0.90		$	0.95
	PGS		0.16			0.16			0.15
Total regulated			1.05			1.06			1.10
	TECO Coal		0.04			0.23			0.24
	Parent/other(4)		(0.17	)		(0.15	)		(0.17	)
Earnings per share from continuing operations			0.92			1.14			1.17
Earnings (loss) per share from discontinued operations			—			(0.15	)		0.10
Earnings per share attributable to TECO Energy		$	0.92		$	0.99		$	1.27
Average shares outstanding – basic			215.0			214.3			213.6

(1) Segment revenues include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements.

(2) Segment net income and earnings per share are reported on a basis that includes internally allocated interest costs to the unregulated companies. Internally allocated interest costs were at a pretax interest rate of 6.00% for 2013 and 2012, and 6.25% for 2011.

(3) The number of shares used in the earnings-per-share calculations is basic shares.

(4) From continuing operations

TAMPA ELECTRIC

Electric Operations Results

Net income in 2013 was $190.9 million compared with $193.1 million in 2012. Results in 2013 reflected 1.5% customer growth, higher base revenues effective Nov. 1, 2013 as a result of the rate case settlement, and energy sales, weather and customer usage patterns similar to 2012. Higher O&M was partially offset by lower interest expense. Net income included $6.3 million of AFUDC– equity, which represents allowed equity cost capitalized to construction costs, compared with $2.6 million in the 2012 period. Net income also reflected $3.6 million lower earnings on assets recovered through the ECRC due to an FPSC rule revising the return on investment calculation effective Jan. 1, 2013.

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In 2013, total degree days in Tampa Electric’s service area were 1% below normal, and 1% below the prior full-year period, reflecting generally milder weather early in the year. Pretax base revenues were $13 million higher than in 2012, primarily due to $10 million of higher base rates effective Nov. 1, 2013, and higher energy sales late in the year due to unusually warm early winter weather. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 0.4% in 2013 compared with 2012. The energy sales shown in the summary table below reflect the energy sales based on the timing of billing cycles, which can vary from period to period.

O&M expenses, excluding all FPSC-approved cost-recovery clauses, increased $19.4 million in 2013, reflecting $8.2 million of higher accruals for performance-based incentive compensation for all employees based on achievement of financial goals and higher costs to operate and maintain the transmission and distribution systems. Compared to 2012, depreciation and amortization expense increased $0.7 million, reflecting the impact of additions to facilities to serve customers, largely offset by approximately $4.0 million of lower amortization on software retroactive to Jan. 1, 2013, due to the change in life for software agreed to in the base rate case settlement. Interest expense decreased $11.1 million, due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

Net income in 2012 was $193.1 million, compared to $202.7 million in 2011. Results in 2012 reflected a mild winter weather period and an extremely rainy summer period, and lower per-customer average usage, partially offset by 1.2% growth in the average number of customers, higher O&M expense and lower interest expenses. Net income in 2012 included $2.6 million of AFUDC-equity, compared with $1.0 million in the 2011 period.

In 2012, total degree days in Tampa Electric’s service area were normal, but almost 3% below the prior year, reflecting mild winter weather and an unusually rainy summer weather pattern (the second wettest summer period on record) offset by higher than normal degree days in the normally mild spring and fall periods, which do not generate significantly higher energy sales. Pretax base revenue was almost $6.0 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather, voluntary conservation that typically occurs during periods without extreme weather, and changes in customer usage patterns. In 2012, total net energy for load was 0.3% higher than in 2011.

In 2012, O&M expense, excluding all FPSC-approved cost-recovery clauses, increased $11.8 million reflecting higher generating system maintenance expenses, higher costs to operate and maintain the distribution system and higher pension and other employee benefit expenses, partially offset by lower bad-debt expense. Compared to the 2011 full-year period, depreciation and amortization expense increased $9.6 million, reflecting additions to facilities to serve customers. Interest expense decreased $7.4 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.

Base Rates

Prior to Nov. 1, 2013, Tampa Electric’s results reflected base rates established in March 2009, when the FPSC awarded $104.0 million higher revenue requirements effective in May 2009 that authorized an ROE mid-point of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for combustion turbines and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

As a result of growth in rate base from required infrastructure added to serve customers, increasing pressure on O&M expense, and an economic recovery that was slower than expected compared to the assumptions in Tampa Electric’s last base rate proceeding in 2009, on April 5, 2013, Tampa Electric filed its petition with the FPSC for an increase in base rates and miscellaneous service charges in the amount of $134.8 million. In the petition, Tampa Electric requested an ROE level of 11.25% and a capital structure identical to that approved in 2009, with 54% equity.

After extensive testimony by Tampa Electric and discovery by five intervening parties and the FPSC Staff, on Sept. 6, 2013, Tampa Electric and all of the intervening parties reached a Stipulation and Settlement Agreement resolving all of the issues in the proceeding. On Sept. 11, 2013, the FPSC approved the settlement that authorized base rate increases implemented at four different dates.

Under the settlement agreement, Tampa Electric was granted $57.5 million higher annual base rates effective Nov.1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million increase effective Nov.1, 2015, and $110 million of higher base rates effective Jan. 1, 2017, or when the Polk 2 – 5 conversion enters commercial service, whichever is later (see the Regulation section).

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The table below provides a summary of Tampa Electric’s revenue and expenses and energy sales by customer type.

Summary of Operating Results

(millions)	2013		% Change			2012		% Change			2011
Revenues	$	1,950.5		(1.6	)	$	1,981.3		(1.9	)	$	2,020.6
O&M expenses		427.0		13.7			375.7		7.6			349.2
Depreciation and amortization		238.8		0.5			237.6		7.0			221.1
Taxes, other than income		149.7		(1.1	)		151.3		5.4			143.6
Non-fuel operating expenses		815.5		6.7			764.6		7.0			713.9
Fuel expense		681.9		(1.8	)		694.7		(5.3	)		733.5
Purchased power expense		64.6		(38.7	)		105.3		(16.4	)		125.9
Total fuel & purchased power expense		746.5		(6.7	)		800.0		(6.9	)		859.4
Total operating expenses		1,562.0		(0.2	)		1,564.6		(0.6	)		1,573.3
Operating income		388.5		(6.8	)		416.7		(6.6	)		447.3
AFUDC equity		6.3		142.3			2.6		160.0			1.0
Net income	$	190.9		(1.1	)	$	193.1		(4.7	)	$	202.7
Megawatt-Hour Sales (thousands)
Residential		8,470		0.9			8,395		(3.7	)		8,718
Commercial		6,090		(1.5	)		6,185		(0.4	)		6,207
Industrial		2,027		1.2			2,001		10.9			1,804
Other		1,832		0.2			1,828		(0.3	)		1,835
Total retail		18,418		—			18,409		(0.8	)		18,564
Sales for resale		222		(16.8	)		267		(24.2	)		352
Total energy sold		18,640		(0.2	)		18,676		(1.3	)		18,916
Retail customers - (thousands) Average		694.7		1.5			684.2		1.2			675.8
Retail net energy for load		19,178		(0.4	)		19,255		0.3			19,205

Operating Revenues

In 2013, retail MWh sales, as measured on a billing cycle basis shown in the table above, were essentially unchanged from 2012. Similar to 2012, sales in 2013 reflected a mild winter and a rainy summer period and lower per customer usage, partially offset by 1.5% customer growth and improvements in the local economy. Pretax base revenue, which included $10.0 million of higher revenue as a result of the base rate settlement described above, was approximately $13.0 million higher than in 2012. In 2013, total retail net energy for load decreased 0.4%, compared to the 2012 period. In 2013, total degree days in Tampa Electric’s service area were 1% below normal, and 1% below 2012, reflecting generally milder weather early in the year.

In 2012, retail MWh sales, as measured on a billing cycle basis shown in the table above, decreased 0.8% despite 1.2% higher average number of customers, an improving local economy and higher sales to the lower margin phosphate-industrial customers. In 2012, total degree days in Tampa Electric’s service area were normal, but almost 3% below 2011, reflecting mild winter weather and an unusually rainy summer weather pattern offset by higher than normal degree days in the normally mild spring and fall periods, which do not generate significantly higher energy sales. Pretax base revenue was almost $6.0 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather, changes in customer usage patterns and voluntary conservation that typically occurs during periods without extreme weather. In 2012, total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, was 0.3% higher than in 2011.

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, smaller single-family houses and increased multi-family housing.

Sales for resale, which are a decreasing portion of Tampa Electric’s energy sales, declined 16.8% in 2013 and 24.2% in 2012, primarily due to changes in Tampa Electric’s wholesale rates and reduced demand due to the mild weather.

Customer and Energy Sales Growth Outlook

        The Florida economy continues to improve following the economic downturn, as evidenced by lower levels of unemployment, and slow improvements in the new housing construction market, which was a major driver of growth in the Florida economy for many years (see the Risk Factors section). In general, economists are forecasting a continued improvement in the unemployment rate in 2014, and an acceleration of improvement in the economy in 2014 and beyond. The 2014 forecast used by Tampa Electric reflects a continuation of the customer growth that was experienced in 2013. Energy sales are expected to reflect continued lower per customer usage in response to increased energy efficiency, voluntary conservation, and economic conditions. The average number of customers increased 1.5% in 2013 and 1.2% in 2012.

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Longer-term, assuming continued economic recovery and resumed growth from population increases and more robust business expansion, Tampa Electric expects average annual customer growth of about 1.5% and weather-normalized average retail energy sales growth about 0.5% lower than customer growth in the near term, and about 0.3% lower than customer growth over the longer-term. This energy sales growth projection reflects increased lighting and appliance efficiency, smaller new single family homes, increased percentage of multi-family homes, changes in usage patterns and changes in population trends. These growth projections assume continued local area economic growth, normal weather, and a continuation of the current energy market structure.

The economy in Tampa Electric’s service area continued to grow in 2013 after modest growth in 2012 and 2011. The Tampa metropolitan area had the largest gain in jobs of 22 metropolitan areas in Florida, with more than 35,000 new jobs led primarily by business services, construction and healthcare related businesses. The total nonfarm employment in the Tampa metropolitan area increased 3.5% in 2013 following a 1.8% increase in 2012 and 1.2% in 2011. The increase in nonfarm employment compared favorably with the state of Florida’s increase of 2.5%. The local Tampa area unemployment rate decreased to 5.7% at the end of 2013 compared with 7.6% at year-end 2012 and 9.5% at year-end 2011. The Tampa area year-end 2013 unemployment rate was below the state of Florida’s 6.2% rate and the national rate of 7.0%. The Tampa area, Florida and national unemployment rates were 7.6%, 8.0% and 7.8%, respectively, at year-end 2012, and 9.5%, 9.7% and 8.5%, respectively, at year-end 2011.

Operating Expenses

Total pretax operating expenses were 0.2% lower in 2013, driven primarily by higher other operating expenses more than offset by lower fuel and purchased-power expense. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expenses increased $19.4 million in 2013 reflecting $8.2 million of higher accruals for performance-based incentive compensation for all employees based on achievement of financial goals and higher costs to operate and maintain the transmission and distribution systems.

Total pretax operating expenses decreased 0.6% in 2012 driven primarily by lower fuel and purchased power expenses. Excluding all FPSC approved cost-recovery clause related expenses, which are net-income neutral, O&M expense increased 6.6%, or $11.8 million, driven by higher generating system maintenance expenses, higher costs to operate and maintain the distribution system and higher pension and other employee benefit expenses, partially offset by lower bad-debt expense.

Compared to 2012, depreciation and amortization expense increased $0.7 million in 2013 primarily as a result of approximately $4.0 million of lower amortization on software retroactive to Jan. 1, 2013, due to the change in depreciable life for software agreed to in the base rate case settlement, more than offset by depreciation of additions to facilities to serve customers. In 2014, depreciation expense is expected to increase at more normal levels, similar to those experienced in 2012. Compared to 2011, depreciation and amortization expense increased $9.5 million in 2012, reflecting additions to facilities to serve customers.

Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense is expected to decrease in 2014 due to lower employee-related costs, lower storm damage expense accruals, and lower pension expense driven by higher discount rates partially offset by higher costs to operate the system and reliably serve customers. Under the rate settlement approved by the FPSC in September 2013, Tampa Electric discontinued its annual $8 million pretax storm damage expense accrual effective Nov. 1, 2013.

Fuel Prices and Fuel Cost Recovery

In November 2013, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2014. The rates include the expected cost for natural gas and coal in 2014, and the net over-recovery of fuel, purchased power and capacity clause expenses.

Total fuel cost decreased in both 2013 and 2012, due to increased natural gas-fired generation and lower costs for natural gas and coal. Purchased-power expense decreased in 2013 and 2012 as the cost-per-MWh decreased, due to lower natural gas prices, which is the primary fuel used by other generators in Florida. Delivered natural gas prices decreased 2% in 2013 after a 14.0% decline in 2012 as a result of low natural gas prices due to mild winter weather and abundant supplies from on-shore domestic natural gas produced from shale formations, and storage inventories above historic averages. Delivered coal costs decreased 5.3% in 2013. The average coal and natural gas costs were $3.38/MMBTU and $5.23/MMBTU, respectively, in 2013.

        Natural gas futures as traded on the NYMEX and various forecasts for natural gas prices indicate that natural gas prices are expected to increase in 2014, as fewer new natural gas wells are drilled in on-shore shale gas formations due to the low prices received by the producers, and a shift by the producers to drilling for more oil than natural gas. Cold winter weather early in 2014 and resulting draws on inventories in storage, improved industrial demand from continued improvement in the economy, and the expectation for more-normal weather are expected to contribute to higher prices as well. Beyond 2014, forecasts are for stable to slightly rising natural gas prices for several years due to increased availability of domestic supplies of natural gas. Delivered coal prices decreased 5.3% in 2013 due to lower transportation costs as a result of lower fuel oil prices, and lower prices for coal purchased in the spot market. Tampa Electric’s primary coal supplies are from the Illinois Basin, which have been more stable than the Central Appalachian coal-producing region over the past several years. Excluding normal escalation and transportation costs, Tampa Electric’s coal prices are expected to remain stable in 2014 due to long-term supply contracts.

Energy Supply

Tampa Electric’s generation increased in line with energy sales growth in 2013, and purchased power decreased due to higher gas-fired generation by Tampa Electric. Tampa Electric’s generation decreased in 2012 due to the mild weather and lower cost natural gas-fired generation available within Florida, which increased MWh purchased but at a lower cost. Lower natural gas prices also contributed to the decrease in purchased-power expense on a per-MW basis.

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Prior to the conversion of the coal-fired Gannon Station to the natural gas-fired Bayside Power Station in 2003, nearly all of Tampa Electric’s generation was from coal. Upon completion of that conversion, the mix shifted with the increased use of natural gas. Coal is expected to continue to represent a significant portion of Tampa Electric’s fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit 1. Longer term, natural gas prices are expected to remain stable for several years, and we expect to maintain the generation mix at about current levels.

Polk Power Station Units 2 – 5 Combined Cycle Conversion

In 2011, Tampa Electric announced that, subject to FPSC approval, it planned to convert four CTs in peaking service at the Polk Power Station to combined cycle with an early 2017 in-service date. In 2012, as required under Florida regulations, Tampa Electric issued a request for proposal to determine its lowest cost option to provide generating capacity beginning in early 2017. The bid process showed that the lowest cost option to serve customers, over the long-term, was Tampa Electric’s planned conversion of CTs to combined-cycle operation.

In September 2012, Tampa Electric submitted a petition to the FPSC for a Determination of Need for the conversion of these peaking CTs to combined-cycle service. In December 2012, the FPSC conducted a hearing for the need, and the FPSC made a bench decision to approve the Polk Power Station Units 2 – 5 conversion. In November 2013, the governor of Florida and the Cabinet, acting as the Power Plant Siting Board, approved the construction of the conversion. In January 2014, the final emission permits were received and construction commenced. The capital expenditures for the conversion and the related transmission system improvements to support the additional generating capacity are included in the capital expenditure forecast located in the Capital Expenditures section. Capital spending in 2014 will support engineering and design, equipment procurement and initial construction. (See the Capital Expenditures and Regulation sections.)

PGS

Operating Results

In 2013, PGS reported net income of $34.7 million, compared with $34.1 million in 2012. Results reflected a 1.3% higher average number of customers and higher therm sales to all retail customer classes, due to more-normal first quarter weather and better economic conditions. Sales to power generation customers and off-system sales decreased due to the expiration of two contracts with power generators, new participants in the market, and higher natural gas prices in 2013 compared to 2012. Non-fuel O&M expense increased $4.0 million compared to 2012 due to higher employee related costs, including $1.5 million of higher accruals for performance-based incentive compensation for all employees based on achievement of financial goals, and an insurance recovery that reduced O&M expenses in 2012. Interest expense decreased $1.6 million, due to lower long-term debt interest rates and a lower interest rate on customer deposits.

In 2013, total throughput for PGS was almost 1.7 billion therms, down 10% from 2012 levels due to the lower volumes transported for power generation customers and lower off-system sales. Industrial and power generation customers represented approximately 61% of annual therm volume, commercial customers used approximately 26%, approximately 9% was sold off-system, and the remainder was consumed by residential customers.

In 2012, PGS reported net income of $34.1 million, compared with $32.6 million in 2011. Results in 2012 reflected a 1.2% higher average number of customers, but lower sales to residential customers due to mild winter weather more than offset by higher sales to commercial and industrial customers and power generation customers due to improving economic conditions. Volumes for the low-margin transportation service for electric power generators were higher than in 2011 due to low natural gas prices, which made it more economical to use natural gas for power generation. Non-fuel O&M expense decreased $2.1 million, compared with 2011, due in part to an insurance recovery of legal expenses associated with environmental-contamination claims. In 2011, O&M expense included $2.5 million related to legal expenses associated with environmental-contamination claims. Interest expense decreased $1.0 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits. Depreciation expense increased $1.4 million reflecting additions to facilities to serve customers.

In 2012, the total throughput for PGS was almost 1.9 billion therms. Industrial and power generation customers consumed approximately 62% of PGS’s annual therm volume, commercial customers used approximately 22%, approximately 12% was sold off system, and the balance was consumed by residential customers.

Residential operations were about 32% of total revenues in each of the past three years. New residential construction, which includes natural gas and conversions of existing residences to natural gas has slowed significantly, compared to the pre-2007 period, due to the weaker Florida housing market. Like most other natural gas distribution utilities, PGS is adjusting to lower per-customer usage due to improving appliance efficiency. As customers replace existing gas appliances with newer, more efficient models, per-customer usage tends to decline.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also experienced increased interest in the usage of CNG as an alternative fuel for vehicles. Currently, there are 21 CNG fueling stations connected to the PGS system, and, at this time, an additional six stations are expected to be added in 2014, however the number of new stations may increase as the year progresses. Such initiatives add therm sales, at lower-margin transportation rates, to the gas system without requiring significant capital investment by PGS.

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The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a PGA. Because this charge may be adjusted monthly based on a cap approved by the FPSC annually, PGS normally has a lower percentage of under- or over-recovered gas cost variances than Tampa Electric.

The table below provides a summary of PGS’s revenue and expenses and therm sales by customer type.

Summary of Operating Results

(millions)	2013		% Change			2012		% Change			2011
Revenues	$	393.5		(1.3	)	$	398.9		(12.0	)	$	453.5
Cost of gas sold		142.6		(9.5	)		157.6		(25.4	)		211.3
Operating expenses		181.1		6.5			170.0		(1.3	)		172.2
Operating income		69.8		(2.1	)		71.3		1.9			70.0
Net income		34.7		1.8			34.1		4.6			32.6
Therms sold – by customer segment
Residential		74.4		5.0			70.8		(8.9	)		77.7
Commercial		438.1		4.0			421.4		3.0			409.2
Industrial		415.1		(10.0	)		461.3		5.8			436.1
Power generation		744.4		(18.5	)		913.5		48.7			614.3
Total		1,672.0		(10.4	)		1,867.0		21.4			1,537.3
Therms sold – by sales type
System supply		249.5		(25.4	)		334.3		(5.4	)		353.3
Transportation		1,422.5		(7.2	)		1,532.7		29.5			1,184.0
Total		1,672.0		(10.4	)		1,867.0		21.4			1,537.3
Customer (thousands) – average		347.4		1.3			342.9		1.2			338.8

In Florida, natural gas service is unbundled for non-residential customers and residential customers that use more than 1,999 therms annually that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation-only sales. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings impact to the company when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to customers through its “NaturalChoice” program. At year-end 2013, approximately 20,500 out of 35,000 of PGS’s eligible non-residential customers had elected to take service under this program.

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PGS Outlook

In 2014, PGS expects continued customer growth at rates in line with those experienced in 2013, reflecting its expectations that the housing markets in many areas of the state that it serves are now recovering. Assuming normal weather, therm sales to weather-sensitive customers, especially residential customers, are expected to increase in 2014 compared to 2013 when mild winter weather late in the year limited sales. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense is expected to decrease slightly in 2014 primarily due to higher costs to operate the system more than offset by lower employee-related expenses, which includes pension expense driven by higher discount rates in the current interest rate environment and better pension plan asset performance in 2013. Depreciation expense is expected to increase from continued capital investments in facilities to reliably serve customers.

Since its acquisition by TECO Energy in 1997, PGS has expanded its gas distribution system into areas of Florida not previously served by natural gas, such as the lower southwest coast in the Fort Myers and Naples areas and the northeast coast in the Jacksonville area. In 2014, PGS expects capital spending to support moderate residential and commercial customer growth, system expansion to serve large commercial and industrial customers, continued interest in conversion of vehicle fleets to CNG and replacement of cast iron and bare steel pipe.

Due to the current rate of new residential development in Florida, which is considerably slower than the 2005 to 2007 period, the PGS business model for system expansion has evolved to focus on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are currently three to four times more expensive on a cost-per-MMBTU basis.

Gas Supplies

PGS purchases gas from various suppliers, depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.

Gas is delivered by the FGT through 66 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville Division receives gas delivered by the Southern Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. PGS also receives gas delivered by Gulfstream Natural Gas Pipeline through six gate stations, and by its affiliate, SeaCoast Gas Transmission LLC, through a single gate station in northeast Florida.

PGS procures natural gas supplies using baseload and swing-supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices, or a fixed price for the contract term.

TECO COAL

In 2013, TECO Coal recorded net income of $9.0 million on sales of 5.8 million tons, compared with $50.2 million on sales of 6.3 million tons in 2012. The 2013 full-year average net selling price was almost $85 per ton, compared with $95 per ton in 2012. The lower sales volumes and lower selling prices in 2013 reflect the current ongoing weak domestic and international coal markets. The all-in total cost of sales was $84 per ton, compared with $85 per ton in the 2012 period. The cost of sales in the first quarter of 2013 included some higher-cost tons from December 2012 inventory that included costs associated with personnel reductions and with idling certain mining operations. TECO Coal recorded a $3.6 million income tax benefit in 2013 that included a $3.7 million tax depletion benefit and a $1.9 million benefit from the reversal of previously accrued state taxes, compared with a 24% effective income tax rate, or a $15.7 million tax expense, in 2012.

In 2012, TECO Coal recorded net income of $50.2 million on sales of 6.3 million tons, compared with $51.5 million on sales of 8.1 million tons in 2011. Lower sales volumes in 2012 reflect much weaker coal market conditions than in 2011. Because the 2012 sales were contracted at a time when the markets were much stronger, the 2012 average net per-ton selling price was more than $95 per ton, compared with almost $88 per ton in 2011. The all-in total per-ton cost of sales was more than $85 per ton compared with almost $80 per ton in 2011. The 2012 cost of sales reflected spreading fixed costs over fewer tons, and costs associated with personnel reductions and with idling certain mining operations. TECO Coal’s effective income tax rate was 24% in 2012, compared with 23% in 2011.

TECO Coal Outlook

        In 2014, we expect TECO Coal’s net income to decrease compared with 2013 to about break-even levels from lower contract selling prices. TECO Coal has 80% of its expected 2014 sales of between 5.5 and 6.0 million tons contracted and priced. An additional 15% of expected sales are committed but unpriced and subject to quarterly pricing based on the Asian benchmark price for metallurgical coal. The average selling price across all products is expected to be $80 per ton in 2014, and specialty coal volumes are expected to represent about 70% of total sales.

The all-in total cost of production is expected to be below 2013 levels in a range between $79 and $83 per ton due to actions taken in 2013 and 2012 to reduce mining costs, including converting traditional surface mining operations to lower cost high-wall mining operations, and lower royalty payments and severance taxes, which are a function of selling price. 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 record tax depletion tax benefits.

Various federal tax overhaul proposals include provisions to eliminate depletion accounting for mineral extraction companies, which would increase TECO Coal’s effective income tax rate and reduce net income if those proposals are implemented (see the Risk Factors section).

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In November 2011, TECO Coal announced that it had made a new discovery of an additional 65 million tons of proven and probable metallurgical coal reserves on properties it controls, and an additional estimated 9 million tons of metallurgical coal classified as resource (non-reserve coal deposits) due to seam thickness. There is an additional 14 million tons of coal classified as resource pending further geologic studies (see Item 2 Properties in the TECO Coal section). These metallurgical coal reserves are located below existing reserves and substantially all of these reserves are owned by TECO Coal, which eliminates royalty payments. The coal from these reserves can be transported by conveyor belt to an existing preparation plant, which has adequate capacity, and thus eliminate trucking costs. TECO Coal has received the permit amendments from the state of Kentucky related to surface development activities to access these reserves. TECO Coal performed preliminary surface and infrastructure development in 2012, but does not expect to begin the work required to bring these reserves into production until there are clear indications that the current weak metallurgical coal market conditions are improving (see the Capital Investments section of Liquidity, Capital Resources). TECO Coal allocates its reserves by market category. As a result of this allocation, 40% of the reserves are classified as metallurgical coal, 40% as soft coking/PCI coal and 20% as steam coal. See Item 2 Properties in the TECO Coal section for a discussion of this allocation.

Since 2008, the issuance of permits by the USACE under Section 404 of the Clean Water Act required for surface mining activities in the Central and Northern Appalachian mining regions has been challenged in the courts by various entities. These challenges have been appealed by various mining companies affected on a number of occasions, but very few permits have been issued over the past several years. At this time, TECO Coal has all of the permits required to meet its 2014 sales projections. See the Environmental section, the Section 404 of the Clean Water Act and Coal Surface Mine Permits section for a more detailed discussion of surface mining permit activities.

Coal Markets

Prices for metallurgical coal have been very volatile over the past three years, with higher prices in 2010 driven by increased demand from expanding economies in China and India and recovering demand in the U.S. and Europe. During 2010, spot prices for various grades of metallurgical coal produced by TECO Coal and others reportedly ranged from $110 to $180 per short ton. Hard coking coal produced in Australia and sold primarily in Asian markets is the benchmark for metallurgical coal prices worldwide, and it has ranged from $335 per metric ton in the first half of 2011, due to disruptions in supplies from Australia as a result of flooding, to $235 per metric ton in January 2012, to $143 per metric ton in January 2014. The decline in metallurgical coal prices has been driven by oversupply in the market and concerns related to worldwide demand for steel in China and the weak international economy.

In 2012 and 2011, demand for coal used by utilities to generate electricity declined due to low natural gas prices, which made it more economical to generate electricity with natural gas than with coal, mild winter weather, and the slow economic recovery in the United States. Prices for Central Appalachian (CAPP) coal used by utilities did not improve in 2013, and in some periods declined further. Future demand for CAPP coal by utilities is uncertain due to the impact of certain proposed EPA regulations on utilities’ ability to burn coal. Various industry reports, and estimates by the EPA, indicated that a number of smaller, older coal-fired utility boilers without current environmental controls would be retired in response to the proposed rules. In December 2011, the United States District Court for the District of Columbia stayed the implementation of the EPA’s proposed CSAPR (see the Environmental section). In January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied the EPA’s request for reconsideration of its ruling against CSAPR, significantly reducing the possibility that the rule will be enforced in its current form. Despite the stay of CSAPR in 2011, demand for coal by utilities remains weak.

In 2013, the EPA released draft rules for GHG emissions from new utility power plants which would, if implemented as proposed, essentially eliminate the use of coal as a fuel by requiring the use of carbon capture and sequestration. The EPA is scheduled to release draft rules for GHG emission from existing utility power plants in 2014, which increases the uncertainty of future coal use by utilities.

The significant factors that could influence TECO Coal’s results in 2014 include the cost of production, the pricing on uncontracted tons, and customers taking contracted volumes. Longer-term factors that could influence results include inventories at thermal coal users, weather, the ability for utilities to continue to burn coal under new rules proposed by the EPA, the ability to obtain environmental permits for mining operations, general economic conditions, the level of natural gas prices, commodity price changes that impact the cost of production, and changes in environmental regulations (see the Environmental Compliance and Risk Factors sections).

PARENT/OTHER

In 2013, the cost for Parent/other was $36.8 million, compared with $31.4 million in 2012. The non-GAAP cost from continuing operations for Parent/other in 2013 was $30.6 million, which excluded $6.2 million of costs associated with the pending acquisition of NMGC, compared with $31.4 million in 2012.

In 2012, the cost for Parent/other in continuing operations was $31.4 million, compared with $36.0 million in 2011. Results for 2012 reflect tax items and lower interest expense as a result of the mid-year 2011 debt retirement, and a charge of $0.8 million associated with the early retirement of the remaining $8.8 million of TECO Energy parent debt. The total cost for Parent/other for 2012 was $35.4 million, compared with $36.6 million in the same period in 2011. Total cost for 2012 includes transaction costs and tax items recorded at Parent related to the TECO Guatemala discontinued operations.

The 2014 non-GAAP cost for Parent/other is expected to be similar to 2013 levels. This forecast excludes any transaction costs, which will be treated as non-GAAP costs, associated with the NMGC acquisition that will be recorded at Parent/other.

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DISCONTINUED OPERATIONS (TECO GUATEMALA)

The 2013 cost of $0.1 million reported in discontinued operations was related to the 2012 sale of TECO Guatemala.

On Sept. 28, 2012, TECO Energy announced that its international power subsidiary, TECO Guatemala, entered into agreements to sell all of its equity interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala, for a total purchase price of $227.5 million in cash. On Dec. 19, 2012, the sale closed on the San José Power Station and related facilities and operations for a price of $215.0 million (see Note 19 to the TECO Energy Consolidated Financial Statements). The sale of the Alborada Power Station closed on Sept. 27, 2012, for a price of $12.5 million.

The 2012 losses in discontinued operations of $33.3 million reflect the results from operations of $18.2 million for the generating plants in Guatemala through the closing of the sales, a $28.6 million loss on assets sold including transaction costs, and a $22.9 million charge associated with foreign tax credit write offs.

On Jan. 13, 2009, TECO Guatemala Holdings, LLC’s (TGH), a wholly-owned subsidiary of TECO Energy.) delivered a Notice of Intent to the Guatemalan government that it intended to file an arbitration claim against the Republic of Guatemala under the Dominican Republic Central America – United States Free Trade Agreement (DR – CAFTA) alleging a violation of fair and equitable treatment of its investment in EEGSA. On Oct. 20, 2010, TGH filed a Notice of Arbitration with the International Centre for Settlement of Investment Disputes (ICSID) to proceed with its arbitration claim. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, TGH has retained its rights under this claim.

TGH filed the arbitration claim with ICSID in 2010, alleging a violation of fair and equitable treatment of its investment in Empresa Eléctrica de Guatemala, S.A. (EEGSA), the largest private distribution company in Central America. TGH’s investment was sold on Oct. 21, 2010. The arbitration was prompted by actions of the Guatemalan government in July 2008, which, among other things, unilaterally reset the distribution tariff for EEGSA at levels well below the tariffs in effect at the time that the distribution tariff was reset.

On Dec. 19, 2013, the ICSID tribunal hearing TGH’s arbitration claim against the Republic of Guatemala issued an award in the case. The ICSID tribunal found that Guatemala breached its treaty obligation to grant TGH fair and equitable treatment under the terms of the DR-CAFTA, thereby causing damages to TGH for which it is entitled to compensation. In sum, the tribunal found that Guatemala’s repudiation of fundamental regulatory principles applying to the tariff review process was arbitrary and breached elementary standards of due process in administrative matters.

The ICSID tribunal unanimously found in favor of TGH and awarded damages of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010, at a rate equal to the prime rate plus 2%. In addition, the tribunal ruled that Guatemala must reimburse TGH for approximately $7.5 million of the costs it incurred in pursuing the arbitration.

Pursuant to ICSID’s rules and procedures, each party has 120 days after the date of the award to file an application for its annulment. Pending the outcome of a potential annulment filing, results in 2013 do not reflect any benefit of this decision.

OTHER ITEMS IMPACTING NET INCOME

Other Income (Expense)

Other income (expense) of $9.9 million in 2013 and of $10.8 million in 2012 included miscellaneous services at the utilities such as lightning surge protection equipment, royalties for coal mined on properties leased by TECO Coal and from the sale of assets no longer in service.

AFUDC equity at Tampa Electric, which is included in Other income (expense), was $6.3 million, $2.6 million and $1.0 million in 2013, 2012 and 2011, respectively. AFUDC is expected to increase in 2014 due to the construction of a reclaimed water pipeline to the Polk Power Station and spending related to the Polk Units 2 – 5 conversion project (see the Liquidity, Capital Resources section).

Interest Expense

In 2013, interest expense was $166.9 million compared to $183.5 million in 2012 and $197.4 million in 2011. In 2013, interest expense decreased due to lower debt balances and lower interest rates on debt at TEC as a result of refinancing activities in 2012 (see Financing Activity section). Interest expense also declined due to an FPSC-approved lower interest rate paid on customer deposits at the utilities, effective in August 2012.

        Interest expense is expected to increase in 2014, primarily due to increased borrowing at Tampa Electric to support the construction of the Polk Power Station Units 2 – 5 conversion.

Income Taxes

The provision for income taxes decreased in 2013, primarily due to lower operating income. The provision for taxes was higher in 2012, primarily due to higher operating income and state income taxes. Income tax expense as a percentage of income from continuing operations before taxes was 35.5% in 2013, 35.9% in 2012 and 36.3% in 2011. We expect our 2014 annual effective tax rate to be approximately 37.0%.

The cash payments for federal income taxes, as required by the federal AMT rules, state income taxes, foreign income taxes and payments (refunds) related to prior years’ audits totaled $1.8 million, $7.2 million and $9.4 million in 2013, 2012 and 2011, respectively.

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Due to the NOL carryforward position resulting from the disposition of the generating assets formerly held by, our merchant power subsidiary, cash tax payments for income taxes are limited to approximately 10% of the AMT rate. We expect future cash tax payments to be limited to a similar level and various state taxes. As a result of bonus depreciation, enacted under economic stimulus legislation since 2008, and tax repair technical guidance and regulations released in 2013, we currently project to utilize these NOL carryforwards primarily in the 2015 through 2018 period. Beginning with 2018, we also expect to start using more than $213 million of AMT carry-forward to limit future cash tax payments for federal income taxes to the level of AMT. We currently project minimal cash tax payments over the next five years.

The utilization of the NOL and AMT carryforwards are dependent on the generation of sufficient taxable income in future periods.

For more information on our income taxes, including a reconciliation between the statutory federal income tax rate and the effective tax rate, see Note 4 to the TECO Energy Consolidated Financial Statements.

LIQUIDITY, CAPITAL RESOURCES

The table below sets forth the Dec. 31, 2013 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/Finance and TEC credit facilities.

Balances as of Dec. 31, 2013

(millions)	Consolidated		Tampa Electric Company		Unregulated Companies		Parent
Credit facilities	$	675.0	$	475.0	$	—	$	200.0
Drawn amounts/LCs		84.7		84.7		—		—
Available credit facilities		590.3		390.3		—		200.0
Cash and short-term investments		185.2		9.8		3.6		171.8
Total liquidity	$	775.5	$	400.1	$	3.6	$	371.8

In 2013, we met our cash needs primarily from internal sources. Cash from operations was $659 million. We paid dividends of $191 million in 2013, and capital expenditures were $532 million. We reduced long-term debt by $52 million, which represents Tampa Electric’s purchase in lieu of redemption of HCIDA Pollution Control Revenue Refunding Bonds. TEC supplemented its cash needs in 2013 with moderate use of its credit facility under which $85 million was drawn at year end.

In 2012, we also met our cash needs primarily from internal sources. Cash from operations was $757 million. We paid dividends of $190 million in 2012, and capital expenditures were $505 million. Other sources of cash included $194 million of net sale proceeds, primarily from the sale of our ownership interest in TECO Guatemala (see Discontinued Operations). We reduced long-term debt by $101 million, which included the retirement of $34 million of San José project debt with its sale, $9 million of TECO Energy parent debt and the net effect of TEC refinancing activities. There was no short-term debt outstanding at year-end 2012.

Cash from Operations

In 2013, consolidated cash flow from operations was $659 million. The lower cash from operations in 2013 was primarily the result of lower operating results from TECO Coal and the absence of operating cash flows from TECO Guatemala, which was sold at the end of 2012. The 2013 cash from operations reflects pension contributions of $40 million. In 2012, consolidated cash flow from operations was $757 million. Although the timing of recoveries, particularly fuel and purchased power, under FPSC-approved cost-recovery clauses can have a significant impact on cash from operations in any one year, in 2012 the net impact was only $9 million. We had anticipated a more significant impact as the 2012 FPSC-approved clause rates provided for refunds of previous over-recoveries; however, lower than expected actual fuel prices resulted in a net over-recovered balance at the end of 2012. The 2012 cash from operations reflects pension contributions of $37 million.

        We made minimal cash payments for state and federal income taxes in 2013 (see the Income Taxes section). Bonus depreciation, enacted under economic stimulus legislation annually since 2008, has significantly reduced federal taxable income at Tampa Electric and PGS. We file a consolidated tax return, and under our tax sharing agreements, each subsidiary’s tax payment is determined on a standalone basis. Significant NOL carryforwards are available at TECO Energy parent that can be used to offset taxable income in the consolidated return such that cash payments for federal income taxes are limited to approximately 10% of the AMT rate. During the period of bonus depreciation, taxable income has been reduced significantly by the bonus deductions, and as a result we have utilized our NOL carryforwards less than expected in recent years. TECO Energy parent cash flows have therefore been less than expected through this period, and our projections for the full utilization of the NOL carryforwards has been extended to 2018. Tampa Electric and PGS have realized higher cash flows in recent years as a result of reduced taxes from bonus depreciation, which has supported their capital spending programs. While 2014 will be the final year available for bonus depreciation deductions, we expect that Tampa Electric and PGS will continue to realize significant cash tax savings as a result of the IRS technical guidance on repair deduction for generation activities and Tangible Capitalization Regulations issued in 2013, and that TECO Energy parent will realize the cash benefit of the NOL carryforwards primarily in the 2015 through 2018 period.

We expect cash from operations to increase in 2014, driven by higher operating results primarily at Tampa Electric, net of somewhat lower net recoveries under various regulatory clauses. In November 2013, the FPSC approved fuel-adjustment and other recovery clause rates that provide for refunds to customers of estimated 2013 net over-recoveries of fuel and purchased power over 12 months beginning Jan. 1, 2014 (see the Regulation section).

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Cash from Investing Activities

Our investing activities in 2013 resulted in a net use of cash of $522 million, which reflects capital expenditures totaling $532 million.

We expect capital spending for the next several years to be above 2013 levels, primarily due to generating capacity additions at Tampa Electric (see the Capital Expenditures section).

Cash from Financing Activities

Our financing activities in 2013 resulted in a net use of cash of $152 million. Tampa Electric purchased in lieu of redemption $52 million of HCIDA Pollution Control Revenue Refunding Bonds (see the Financing Activity section) and borrowed $84 million under its credit facility. We paid $191 million in common stock dividends, and we received $7 million from exercises of stock options.

Financing Activities Related to the NMGC Acquisition

In 2014, we expect to finance the acquisition of NMGC with a mix of cash on hand at TECO Energy parent, the issuance of $350 to $400 million of TECO Energy common stock, and the issuance of $50 million of debt at the NMGC level and $200 million of debt at the NMGI level primarily to repay existing debt upon closing. We expect to issue the debt and issue the new shares close to the time of closing the transaction, which is expected in the third quarter of 2014; however the terms and conditions of the financing transactions are unknown at this time.

Credit Facility Related to NMGC

In connection with the pending acquisition of NMGC, on Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility (the “NMGC Credit Agreement”). TECO Energy has no rights or obligations to borrow under the NMGC Credit Agreement, which it has entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the acquisition. Pursuant to the terms of the NMGC Credit Agreement, upon such closing, TECO Energy will designate NMGC as the borrower under the NMGC Credit Agreement and TECO Energy’s obligations under the terms of the NMGC Credit Agreement will terminate (see Note 22 to the TECO Energy Consolidated Financial Statements).

TECO Finance Bridge Facility Related to NMGC

In June 2013, TECO Energy and TECO Finance entered into a $1.075 billion Senior Unsecured Bridge Credit Agreement (Bridge Facility). The Bridge facility is sized to cover the $950 million purchase price and provide a $125 million credit facility for the operations of NMGC (see Note 22 to the TECO Energy Consolidated Financial Statements).

Cash and Liquidity Outlook

In general, we target consolidated liquidity (unrestricted cash on hand plus undrawn credit facilities) of at least $500 million. At Dec. 31, 2013, our consolidated liquidity was $775 million, consisting of $400 million at TEC, $372 million at TECO Energy parent, and $4 million at the other companies.

We expect our sources of cash in 2014 to include cash from operations at levels above 2013, due in large part to higher net income from the regulated Florida operating companies, and long-term debt issuance of $250 - $300 million at TEC. We plan to use cash in 2014 to fund capital spending estimated at $720 million, to pay dividends to shareholders, and the repayment of $83 million of maturing Tampa Electric debt.

We expect to continue to make equity contributions to TEC in 2014 in order to support the utilities capital structure and financial integrity. TEC expects to fund its capital needs with a combination of internally generated cash and equity contributions from us, and we anticipate that these contributions will total $150 million in 2014.

Our goal is to reduce leverage at TECO Finance over time as we are able to utilize our NOL carryforwards and as the equity needs of Tampa Electric normalize after the peak capital spending expected over the next several years during the Polk combined cycle conversion project (see the Capital Expenditures section). Our long-term debt maturities for TECO Finance total $191 million in 2015, $250 million in 2016, $300 million in 2017 and $300 million in 2020.

        TEC expects to utilize cash from operations and equity contributions from TECO Energy to support its capital spending program, supplemented with incremental long-term debt and utilization of its credit facilities to maintain strong utility capital structures. Our credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). Although we expect the normal utilization of our credit facilities to be low, we estimate that we could fully utilize the total available capacity under our facilities in 2014 and remain within the covenant restrictions.

Our expected cash flow could be affected by variables discussed in the individual operating company sections, such as customer growth, weather and usage changes at our regulated businesses, and coal margins. In addition, actual fuel and other regulatory clause net recoveries will typically vary from those forecasted; however, the differences are generally recovered within the next calendar year. It is possible however, that unforeseen cash requirements and/or shortfalls, or higher capital spending requirements could cause us to fall short of our liquidity target (see the Risk Factors section).

As a result of our significant reduction of parent debt, and reduced business risk, we have improved our debt credit ratings in recent years (see Credit Ratings section). In the unlikely event TEC’s ratings were downgraded to below investment grade, counterparties to our derivative instruments could request immediate payment or full collateralization of net liability positions. If the credit risk-

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related contingent features underlying these derivative instruments were triggered as of Dec. 31, 2013, we could have been required to post additional collateral or settle existing positions with counterparties totaling $0.1 million. In addition, credit provisions in long-term gas transportation agreements of Tampa Electric and PGS would give the transportation providers the right to demand collateral, which we estimate to be approximately $63.7 million. None of our credit facilities or financing agreements have ratings downgrade covenants that would require immediate repayment or collateralization.

SHORT-TERM BORROWING

Credit Facilities

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

	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding(1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding(1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility(2)	$	325.0	$	6.0	$	0.7	$	325.0	$	—	$	1.5
1-year accounts receivable facility		150.0		78.0		—		150.0		—		—
TECO Energy/TECO Finance :
5-year facility(2)(3)		200.0		—		—		200.0		—		—
Total	$	675.0	$	84.0	$	0.7	$	675.0	$	—	$	1.5

(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.

These credit facilities require commitment fees ranging from 12.5 to 25.0 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 as Dec. 31, 2012.

At Dec. 31, 2013, TECO Finance had a $200 million bank credit facility in place guaranteed by TECO Energy with a maturity date in December 2018. TEC had a bank credit facility totaling $325 million, also maturing in December 2018. In addition, TEC had a $150 million accounts receivable securitized borrowing facility that was renewed in February 2014 with a maturity date of Feb. 13, 2015. The TECO Finance and TEC bank credit facilities both include sub-limits for letters of credit of $200 million. At Dec. 31, 2013, the TECO Finance credit facility was undrawn and no letters of credit were outstanding. At Dec. 31, 2013, the outstanding borrowings under the TEC credit facilities were $84 million and $0.7 million of letters of credit were outstanding.

The table below sets forth TECO Finance and TEC maximum, minimum, and average credit facility utilization in 2013.

2013 Credit Facility Utilization

(millions)	Maximum drawn amount		Minimum drawn amount		Average drawn amount		Average interest rate
TECO Finance	$	—	$	—	$	—		—
Tampa Electric Company	$	84.0	$	—	$	5.4		0.59	%

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Significant Financial Covenants

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 Dec. 31, 2013, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants. The table that follows lists the significant financial covenants and the performance relative to them at Dec. 31, 2013. Reference is made to the specific agreements and instruments for more details.

(millions, unless otherwise indicated)
Instrument	Financial Covenant(1)	Requirement/Restriction	Calculation at Dec. 31, 2013
Tampa Electric Company
Credit facility(2)	Debt/capital	Cannot exceed 65%	45.7%
Accounts receivable credit facility(2)	Debt/capital	Cannot exceed 65%	45.7%
6.25% senior notes	Debt/capital Limit on liens(3)	Cannot exceed 60% Cannot exceed $700	45.7% $0 liens outstanding
Insurance agreement relating to certain pollution bonds	Limit on liens(3)	Cannot exceed $483 (7.5% of net assets)	$0 liens outstanding
TECO Energy/TECO Finance
Credit facility(2)	Debt/capital	Cannot exceed 65%	56.2%
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 Consolidated 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 Tampa electric if any were outstanding.

(5) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by principal property or capital stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes. At Dec. 31, 2013 neither TECO Energy nor TECO Finance had secured debt outstanding.

Credit Ratings of Senior Unsecured Debt

	Standard & Poor’s (S&P)	Moody’s	Fitch
Tampa Electric Company	BBB+	A2	A-
TECO Energy/TECO Finance	BBB	Baa1	BBB

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

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

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

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Summary of Contractual Obligations

The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures. This table does not include contingent obligations, which are discussed in a subsequent table.

Contractual Cash Obligations at Dec. 31, 2013

(millions)	Payments Due by Period
	Total		2014		2015		2016		2017-2018		After 2018
Long-term debt (1)	$	2,923.9	$	83.3	$	274.5	$	333.3	$	604.2	$	1,628.6
Operating leases/rentals/capacity payments		93.8		19.8		18.8		17.2		24.6		13.4
Net purchase obligations/commitments (2) (3)		412.0		245.6		91.9		30.3		29.0		15.2
Interest payment obligations		1,581.1		155.0		143.3		126.7		209.3		946.8
Pension plan (4)		131.9		34.2		47.7		23.4		13.2		—
Total contractual obligations	$	5,142.7	$	537.9	$	558.7	$	540.4	$	901.7	$	2,604.0

(1) Includes debt at TECO Finance, Tampa Electric, and PGS (see Note 7 to the TECO Energy Consolidated Financial Statements for a list of long-term debt and the respective due dates).

(2) The table above excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually (see the Regulation section).

(3) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2013, these commitments include Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.

(4) The total includes the estimated minimum required contributions to the qualified pension plan as of the measurement date. Future contributions are included but they are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by stock market performance, and other factors (see Liquidity, Capital Resources section and Note 5 to the TECO Energy Consolidated Financial Statements).

The following table summarizes the letters of credit and guarantees outstanding that are not included in the Contractual Cash Obligations table above and not otherwise included in our Consolidated Financial Statements.

Contingent Obligations at Dec. 31, 2013

(millions)	Commitment Expiration
		Total(2)		2014		2015		2016		2017 - 2018		After 2018(1)
Letters of credit		$	0.7	$	—	$	—	$	—	$	—	$	0.7
Guarantees	Fuel purchase/energy management (2) Fuel sales and transportation Other		101.8		10.0		—		—		—		91.8
			5.5		0.8		0.7		—		—		4.0
			5.0		—		5.0		—		—		—
Total contingent obligations		$	113.0	$	10.8	$	5.7	$	—	$	—	$	96.5

(1) These 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.

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CAPITAL INVESTMENTS

Forecast
(millions)	Actual 2013		2014		2015		2016-2018		2014 - 2018 Total
Tampa Electric
Transmission	$	30	$	35	$	20	$	85	$	140
Distribution		115		115		110		355		580
Generation		155		140		125		390		655
New generation and transmission		55		200		245		95		540
Other		30		45		40		75		160
Other environmental		40		65		20		40		125
Tampa Electric total		425		600		560		1,040		2,200
Net cash effect of accruals, retentions and AFUDC		5		—		—		—		—
Tampa Electric net		430		600		560		1,040		2,200
Peoples Gas		80		100		100		295		495
Unregulated companies		20		20		25		100		145
Total	$	530	$	720	$	685	$	1,435	$	2,840

(1) Individual line items exclude AFUDC-debt and equity; however total AFUDC is a reconciling item in 2013.

TECO Energy’s 2013 capital expenditures of $530 million included $425 million at Tampa Electric, including AFUDC debt and equity. Tampa Electric’s capital expenditures in 2013 included $28 million for a reclaimed water pipeline to serve the Polk Power Station, approximately $40 million to improve the Big Bend Station solid fuel handling and flue gas desulphurization systems reliability, for equipment and facilities to meet modest customer growth, generating equipment maintenance, and environmental compliance. Capital expenditures for PGS were approximately $80 million, including approximately $28 million for maintenance of the existing system, $36 million to expand the system and support customer growth, and $13 million for replacement of cast iron and bare steel pipe. TECO Coal’s capital expenditures included $20 million primarily for normal mining equipment replacement, and the development of new mines to support continued production.

TECO Energy estimates capital spending to be $720 million for 2014 and approximately $2.1 billion during the 2015 to 2018 period. As described below, this forecast includes $540 million for Tampa Electric’s next increment of generation expansion, including transmission system improvements to support the increased plant output.

For 2014, Tampa Electric expects to spend $600 million. For the transmission and distribution systems, Tampa Electric expects to spend $150 million in 2014, including approximately $110 million for normal transmission and distribution system expansion and reliability, and approximately $40 million for transmission and distribution system storm hardening. Capital expenditures for the existing generating facilities of $140 million include approximately $20 million for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, approximately $100 million for generating unit outages in 2014 and advance purchases for 2015 unit outages, $10 million for a reclaimed water pipeline to eliminate ground water usage at the Polk Power Station, and $10 million for the conversion of distillate oil igniters to natural gas. In addition, Tampa Electric expects to spend $65 million for environmental compliance programs and improvements to environmental control equipment in 2014 including approximately $45 million to improve the Big Bend Station solid fuel handling system reliability.

In the 2015 to 2018 period, Tampa Electric expects to spend approximately $315 million annually to support normal system growth and reliability, environmental compliance and improvements to computer systems to serve customers. This level of ongoing capital expenditures reflects the costs for materials and contractors, long-term regulatory requirements for storm hardening, and an active program of transmission and distribution system upgrades which will occur over the forecast period. These programs and requirements include: approximately $20 million annually for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, average annual expenditures of almost $110 million to support generating unit availability and reliability; average annual expenditures of $15 million for environmental compliance; average annual expenditures of more than $30 million for general infrastructure and facilities; average annual expenditures of approximately $25 million for transmission and distribution system storm hardening; approximately $115 million annually for transmission and distribution system capacity improvements to meet expected customer growth and reliability.

Tampa Electric’s forecast for capital spending does not include amounts that may be spent on projects that would result in the generation of additional revenues. Spending on any projects would be justified by an economic analysis that demonstrates a net benefit.

Tampa Electric’s capital spending forecast includes amounts related to the conversion of the Polk Units 2 – 5 from peaking service to combined cycle with a January 2017 in-service date. The determination of need was approved by the FPSC in December 2012, the final site certification approval by the FDEP was received in the fourth quarter of 2013, and the final air emissions permits were received in January 2014. Construction commenced in January 2014. The capital expenditures for the conversion and the related transmission system improvements to support the additional generating capacity are included in the “New generation and transmission” line in the Capital Investments table above. The peak capital spending is forecast at $445 million for both the transmission system and plant conversions in the 2014 and 2015 periods.

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Capital expenditures for PGS are expected to be about $100 million in 2014 and $395 million during the 2015 to 2018 period. Included in these amounts is an average of approximately $50 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety, including approximately $12 million annually for the replacement of cast iron and bare steel pipe, which is recovered through a rider clause approved by the FPSC in 2012 (see the Regulation section).

At PGS, higher capital expenditures are focused on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are currently three to four times more expensive on a cost per MMBTU basis.

The unregulated companies expect to invest $20 million in 2014, primarily for normal mining equipment replacement at TECO Coal. The unregulated companies expect to spend $125 million during the 2015 – 2018 period, primarily for coal mine development to maintain production, compliance with new safety requirements under the MINER Act, and for normal coal mining equipment renewal and replacement at TECO Coal.

The capital expenditure forecast beyond 2014 does not include additional investment to develop the metallurgical coal reserves that TECO Coal announced in November 2011. Based on current market conditions, TECO Coal does not expect to make additional investments to develop these reserves until metallurgical coal prices improve to a level to support that investment. In 2012, TECO Coal obtained the necessary permit amendments from the state of Kentucky related to surface development activities to access these reserves, and further evaluated detailed mining plans and potential markets for this high-volatile metallurgical coal. TECO Coal completed utility relocation and preliminary surface work to bring these reserves into production. Based on previous estimates, subject to development of final plans, the cost to develop these reserves is estimated to be approximately $160 million over approximately a three year period.

If the U.S. Congress or the Florida Legislature enacted a national or Florida RPS, additional capital spending for renewable generating resources to meet the requirements of an RPS would likely be needed (see the Environmental Compliance section). Depending on the final federal or state rules, Tampa Electric may need to invest capital to develop additional sources of renewable power generation.

The forecast of capital expenditures shown above is based on our current estimates and assumptions for normal maintenance capital at the operating companies; capital expenditures to support normal system reliability and growth at Tampa Electric and PGS; the replacement of cast iron and bare steel pipe at PGS; the programs for transmission and distribution system storm hardening and transmission system reliability requirements; generating capacity expansion at Tampa Electric and incremental investments above normal maintenance capital to expand the PGS system and production capacity at TECO Coal. Actual capital expenditures could vary materially from these estimates due to changes in costs for materials or labor or changes in plans (see the Risk Factors section).

Financing Activity

Our year-end 2013 consolidated capital structure was 56% debt and 44% common equity. The debt-to-total-capital ratio has improved significantly over the past six years, primarily due to the repayment of more than $1.0 billion of parent and parent guaranteed debt, consisting of $779 million in 2007, a net $189 million in 2010, $64 million in 2011, and $9 million in 2012, as well as the increase in retained earnings. At Dec. 31, 2013, Tampa Electric’s year-end capital structure was 45% debt and 55% common equity.

In 2013 and 2012, we raised $6.7 million and $3.9 million, respectively, of equity, primarily through the exercise of stock options.

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

On Dec. 5, 2012, TECO Energy redeemed $8.8 million of 6.75% Notes due May 15, 2015. The redemption price was equal to $1,141.86 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $0.8 million of premiums were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Statements of Cash Flows for 2012.

On Oct. 1, 2012, Tampa Electric redeemed $147.1 million of HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, the $60.7 million of 2002 Bonds due Oct. 1, 2013 bore interest at 5.10% and the $86.4 million of 2002 Bonds due Oct. 1, 2023 bore interest at 5.50%.

On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022. The 2.60% Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2.60% Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2.60% Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and

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interest on the 2.60% Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, 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 June 15, 2022, TEC may at its option redeem the 2.60% Notes, in whole or in part, at 100% of the principal amount of the 2.60% Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042. The 4.10% Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 4.10% Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of 4.10% Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 4.10% Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 4.10% Notes, in whole or in part, at 100% of the principal amount of the 4.10% Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

On March 15, 2012, Tampa Electric purchased in lieu of redemption $86 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (the $86 million Bonds). On March 19, 2008, the HCIDA remarketed the $86 million Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The $86 million Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. Tampa Electric is responsible for payment of the interest and principal associated with the $86 million Bonds. Regularly scheduled principal and interest payments, when due, are insured by Ambac Assurance Corporation.

On Sept. 27, 2012, TECO Energy announced that its international power subsidiary, TECO Guatemala, entered into agreements to sell all of the equity interests in the Alborada and San José power stations and related facilities and operations in Guatemala. The sale of the Alborada Power Station closed on Sept. 27, 2012, for a selling price of $12.5 million. The sale of the San José Power Station and related facilities and operations in Guatemala closed on Dec. 19, 2012 for a price of $215.0 million. TECO Energy utilized $25.3 million of the proceeds to repay the San José Power Station project debt at closing (see Discontinued Operations section and Note 19 to the TECO Energy Consolidated Financial Statements).

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities, and the disclosure of contingencies. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the TECO Energy Consolidated Financial Statements for a description of our significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.

Deferred Income Taxes

We use the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, we estimate our current tax exposure and assess the temporary differences resulting from differing treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or the entire deferred tax asset will not be realized. If we determine that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.

At Dec. 31, 2013, we had a net deferred income tax liability of $343.7 million, attributable primarily to property-related items, AMT credit carry forwards and operating loss carry forwards. Based primarily on historical income levels and the company’s expectations for steady future earnings growth, management has determined that the deferred tax assets associated with operating losses and AMT credit carryforwards recorded at Dec. 31, 2013, will be realized in future periods.

        We believe that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: 1) realization of the deferred tax asset is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods; 2) a change in the estimated valuation reserves could have a material impact on reported assets and results of operations; and 3) administrative actions of the IRS or the U.S. Treasury or changes in law or regulation could change our deferred tax levels, including the potential for elimination or reduction of our ability to utilize the deferred tax assets.

The FASB has guidance that prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. See further discussion of uncertainty in income taxes and other tax items in Note 4 to the TECO Energy Consolidated Financial Statements.

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Employee Postretirement Benefits

TECO Energy sponsors a defined benefit pension plan (pension plan) that covers substantially all employees. In addition, the company has an unfunded non-qualified, non-contributory supplemental executive retirement benefit plan available to certain members of senior management. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to these plans. Key factors include assumptions about the expected rates of return on plan assets, salary increases and discount rates. These factors are determined by the company within certain guidelines and with the help of external consultants. The company considers market conditions, including changes in investment returns and interest rates, in making these assumptions.

The company believes that the accounting related to employee postretirement benefits is a critical accounting estimate for the following reasons: 1) a change in the estimated benefit obligation could have a material impact on reported assets, AOCI and results of operations; and 2) changes in assumptions could change the annual pension funding requirements, having a significant impact on the company’s annual cash requirements.

Pension plan assets (plan assets) are invested in a mix of equity and fixed-income securities. The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with the company’s portfolio, with provision for active management and expenses paid from the trust. The discount rate assumption used to determine the 2013 benefit expense and Dec. 31, 2013, benefit obligation was based on a cash flow matching technique developed by the company’s outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement dates to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate. The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. Holding all other assumptions constant, a 1% decrease in the assumed rate of return on plan assets would have increased 2013 after-tax pension cost by approximately $3.1 million. Likewise, a 1% decrease in the discount rate assumption would have increased 2013 after-tax pension cost approximately $2.8 million. For 2014, a 1% decrease in the discount rate assumption would result in an approximately $1.6 million after-tax increase in the expected pension cost. A 1% decrease in the assumed rate of return on plan assets would result in an approximately $3.5 million after-tax increase in expected pension cost.

Unrecognized actuarial gains and losses for the pension plan are being recognized over a period of approximately 12 years, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with applicable accounting guidance for pensions. The company’s policy is to fund the plan based on the required contribution determined by its actuaries within the guidelines set by the ERISA, as amended.

In July 2012, the president signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under MAP-21.

In addition, the company currently provides certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 who meet certain service requirements. In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, combined the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset by recording a corresponding charge and a regulatory tax asset in the first quarter of 2010 and recorded a true-up of the deferred tax asset in the fourth quarter of 2012. The company implemented an EGWP for its post-65 retiree prescription drug plan effective Jan. 1, 2013. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. As a result, the company no longer receives Medicare Part D subsidy payments beginning with the 2013 plan year.

The Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its postretirement benefit obligation. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under the applicable accounting guidance, include the assumed discount rate and the assumed rate of increases in future health care costs. Since 2009 the company has determined the discount rate for the OPEB using that individual plan’s projected benefit cash flow rather than using the same discount rate that was determined for the pension plan. In estimating the health care cost trend rate, the company considers its actual health care cost experience, future benefit structures, industry trends, and advice from its outside actuaries. The company assumes that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industry wide cost-containment initiatives.

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The assumed health care cost trend rate for medical costs was 7.50% in 2013 and decreases to 4.50% in 2025 and thereafter. A 1% increase in the health care trend rates would have produced a $0.2 million after-tax increase in the aggregate service and interest cost for 2013, and a $6.8 million increase in the accumulated postretirement benefit obligation as of Dec. 31, 2013.

The actuarial assumptions used in determining the company’s pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While the company believes that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect the company’s financial position or results of operations.

See the discussion of employee postretirement benefits in Note 5 to the TECO Energy Consolidated Financial Statements.

Evaluation of Assets for Impairment

In accordance with accounting guidance for long-lived assets, the company assesses whether there has been an impairment of its long-lived assets and certain intangibles held and used when such indicators exist. The company normally reviews all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis. However, in the case of a triggering event, such as a significant market disruption or sale of a business, the values of related long-lived assets are reviewed. We believe the accounting estimates related to asset impairments are critical estimates for the following reasons: 1) the estimates are highly susceptible to change, as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then current market conditions in such periods; 2) markets can experience significant uncertainties; 3) the estimates are based on the ongoing expectations of management regarding probable future uses and holding periods of assets; and 4) the impact of an impairment on reported assets and earnings could be material. The company’s assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Our expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.

See Note 20 to the TECO Energy Consolidated Financial Statements for discussion of the company’s treatment of impairment of long-lived assets for the year ended Dec. 31, 2013.

Regulatory Accounting

Tampa Electric’s and PGS’s retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. As a result, the regulated utilities qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.

As a result of regulatory treatment and corresponding accounting treatment, we expect that the impact on utility costs and required investment associated with future changes in environmental regulations would create regulatory assets. Current regulation in Florida allows utility companies to recover from customers prudently incurred costs (including, for required capital investments, depreciation and a return on invested capital) for compliance with new environmental regulations through the ECRC (see the Environmental Compliance and Regulation sections).

We periodically assess the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. We believe the application of regulatory accounting guidance is a critical accounting policy since a change in these assumptions may result in a material impact on reported assets and the results of operations (see the Regulation section and Notes 1 and 3 to the TECO Energy Consolidated Financial Statements).

RECENTLY ISSUED ACCOUNTING STANDARDS

Unrecognized Tax Benefits

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

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Comprehensive Income

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

INFLATION

The effects of general inflation on our results have not been significant for the past several years. The annual average rate of inflation, as measured by the CPI-U, as reported by the U.S. Department of Labor, was 1.5% in 2013 after a 1.7% increase in 2012, and a 3.0% increase in 2011. This is lower than the 2.4% average annual increase over the past ten years. This is the first time the CPI has gone up less than 2.0% for consecutive years since 1997-98.

The current economic outlook and the pace of economic recovery have caused the outlook for inflation in 2014 to be higher than in 2013, but lower than in 2011, when oil and commodity prices rose sharply. Reports published by the Federal Reserve Bank of Chicago and others indicate that CPI-U has been below desired levels and is expected to be less than 2.0% in 2014.

ENVIRONMENTAL COMPLIANCE

Environmental Matters

Our businesses have significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act, and material Clean Water Act implications and impacts by federal and state legislative initiatives. TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. Additionally, TECO Coal has considerations concerning wastewater management and environmental permitting.

Air Quality Control

Emission Reductions

Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC) and conversion of coal-fired units to natural-gas fired combined cycle; implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add BACT emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.

Tampa Electric, through voluntary negotiations in 1999 with the EPA, the U.S. Department of Justice and the FDEP, signed a Consent Decree and Consent Final Judgment, as settlement of federal and state litigation to dramatically decrease emissions from its power plants. Tampa Electric has fulfilled the obligations of the Consent Decree, and the court terminated the Consent Decree on Nov. 22, 2013. Termination of the Consent Final Judgment is in progress and is expected to be completed during the first half of 2014.

The emission reduction requirements of these agreements resulted in the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (Bayside Power Station), enhanced availability of flue-gas desulfurization systems (scrubbers) at Big Bend Station to help reduce SO_2, and installation of SCR systems for NO_x reduction on Big Bend Units 1 through 4. Cost recovery for the SCRs began for each unit in the year that the unit entered service through the ECRC (see the Regulation section).

As a result of the actions taken under the consent decree, emissions of all pollutant types have been significantly reduced. Since 1998, Tampa Electric has reduced annual SO₂, NO_x and PM emissions from its facilities by 164,000 tons (94%), 63,000 tons (91%) and 4,500 tons (87%), respectively.

Reductions in mercury emissions also have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% from 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of the SCRs at Big Bend Power Station, which have led to a system-wide reduction of mercury emissions of more than 90% from 1998 levels.

CAIR/CSAPR

As a result of all its completed emission reduction actions, Tampa Electric has achieved emission reduction levels called for in Phase I and Phase II of CAIR. In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO₂ and NO_x. The federal appeals court reinstated CAIR in December 2008 as an interim solution. In July 2011, the EPA issued the final CAIR replacement rule, called the CSAPR. The final CSAPR focused on reducing SO₂ and NO_x in 27 eastern states that contribute to ozone and/or fine particle pollution in other states. Compliance with CSAPR, which would be measured at the individual power plant level, would require the addition of scrubbers or SCRs on most coal-fired power plants. In addition, the rule utilized intrastate emissions allowance trading and limited interstate emissions allowance trading to achieve compliance. All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit removes SO₂ in the gasification process.

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The EPA has estimated that the implementation of CSAPR would 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 at TECO Coal.

On Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit granted the motion to stay the implementation of CSAPR in all aspects, which had been scheduled to take effect Jan. 1, 2012, and ordered the reinstatement of CAIR pending the outcome of the litigation. On Aug. 21, 2012, the court vacated the rule entirely and remanded it back to the EPA while leaving the CAIR in place. In January 2013, the Court of Appeals rejected the request for a rehearing. On June 24, 2013, the U.S. Supreme Court granted the United States’ and environmental group petitions asking the Court to review the D.C. Circuit’s decision. EPA has announced that it intends to propose a new rule to address Clean Air Act requirements to reduce the interstate transport of ozone by October 2014. The rule would replace parts of CSAPR, which the U.S. Court of Appeals for the District of Columbia struck down in 2012. EPA acknowledges that the proposal could be influenced by the outcome of the CSAPR appeal to the U.S. Supreme Court.

Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT)

The EPA published proposed rules under National Emission Standards for HAPS on May 3, 2011, pursuant to a court order. These rules are expected to reduce mercury, acid gases, organics, and certain non-mercury metals emissions and require MACT. The final Utility MACT rules, now called Mercury Air Toxics Standards (MATS), were published in December 2011 with implementation called for in early 2015 with extensions to early 2016 or 2017 under certain specific criteria. A potential outcome of the MATS rule is the retirement of smaller, older coal-fired power plants that do not already have emissions controls installed.

All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the new standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of this rule and expects that it will be in compliance with MATS with nominal additional capital investment.

The retirement of coal-fired generating units as a result of the implementation of this rule could reduce demand for sales at TECO Coal.

Carbon Reductions and GHG

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system wide emissions of CO₂ by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO₂ to remain near 1990 levels until the addition of the next base load unit, which is scheduled to be in service in January 2017 (see the Tampa Electric and Capital Expenditures sections). Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Station coal-fired units resulted in an annual decrease in CO₂ emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 30% and 15%, respectively.

Tampa Electric’s power plants currently emit approximately 16 million tons of CO₂ per year. Assuming a projected long-term average annual load growth of more than 1.0%, Tampa Electric could emit approximately 17 million tons of CO₂ (an increase of approximately 6%) by 2020 if natural gas-fired peaking and combined-cycle generation additions are used to meet customer demand.

In 2010, the EPA issued its Final Rule on the mandatory reporting of GHGs, requiring facilities that emit 25,000 metric tons or more of CO₂, or its equivalent, per year to begin collecting GHG data under a new reporting system on Jan. 1, 2010, with the first annual report due Sept. 28, 2011. Tampa Electric complied with the mandatory reporting requirement, in large part through the methods and procedures already utilized and continues to submit annual reports as required. The rule also required natural gas distribution, underground coal mining facilities, and electric transmission and distribution companies, including PGS, TECO Coal and Tampa Electric, that emit 25,000 metric tons or more of CO_2, or its equivalent, per year to begin collecting GHG data under a new reporting system on Jan. 1, 2011, with the first annual report due Sept. 28, 2012. Tampa Electric complied with the reporting requirement and continues to submit annual reports as required.

        In December 2009, the EPA published the final Endangerment Finding in the Federal Register. Although the finding was technically made in the context of GHG emissions from new motor vehicles and did not, in itself, impose any requirements on industry or other entities, EPA claims that the finding triggered GHG regulation of a variety of sources under the Clean Air Act (CAA). Related to utility sources, the EPA’s “tailoring rule,” which addresses the GHG emission threshold triggers that would require permitting review of new and/or major modifications to existing stationary sources of GHG emissions, became effective Jan. 2, 2011. While this rule does not have an immediate impact on Tampa Electric’s ongoing operations, GHG permitting was recently completed for Tampa Electric’s next base load unit, the Polk Unit 2 – 5 conversion to combined cycle.

In June 2013, President Barack Obama announced his “Climate Action Plan” a broad package of mostly administrative initiatives aimed at reducing GHG emissions by approximately 17 percent below 2005 levels by 2020. EPA regulation of GHG emissions from new and existing power plants are the plan’s primary elements. These regulations were anticipated long before the president’s announcement, however the president provided additional details on both timing and substance. With respect to new power plants, pursuant to the directive, EPA released a re-proposed rule in September 2013 and is taking comments on the proposal until March 10, 2014. The president also directed 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. Because both rules will be subjected to litigation, legal challenges could also have material impact on both the timing and substance of EPA’s new climate rules.

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Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. 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 cannot predict whether the FPSC would grant such recovery. Tampa Electric’s current solid-fuel energy generation was about 55% of its total system output in 2013, compared to being approximately 84% of its output in 2001. This is due to the conversion of the coal-fired Gannon Power Station into the natural gas-fired Bayside Power Station. However, solid fuel-fired facilities remain a significant component of Tampa Electric’s diverse generation fleet and additional solid fuel units could be considered in the future.

In the case of TECO Coal, there are not yet federal limits on GHG emissions for this sector, and it is unclear if future requirements for GHG emissions reductions would directly impact it as a carbon-based fuel provider or the end users of its products. In either case, these requirements could make the use of coal more expensive or less desirable, which could impact TECO Coal’s margins and profitability.

Water Supply and Quality

The EPA’s final Clean Water Act Section 316(b) rule took effect in 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Tampa Electric uses water from Tampa Bay at its Bayside and Big Bend facilities as cooling water. Both plants use mesh screens to reduce the adverse impacts to aquatic organisms, and Big Bend units 3 and 4 use proprietary fine-mesh screens, BACT, to further reduce impacts to aquatic organisms. Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule. In 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions. Among other things, the court rejected the EPA’s use of “cost-benefit” analysis and suggested some ways to incorporate cost considerations. The Supreme Court agreed to review the Second Circuit’s decision and heard arguments in December 2008. The EPA decided to rewrite the rule, and proposed a new rule in the summer of 2013. After several delays, the final rule is scheduled for April 2014. The full impact of the new regulations will depend on subsequent legal proceedings, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies.

On Dec. 6, 2010, the EPA published its final rule, setting numeric nutrient criteria for Florida’s lakes and flowing waters. The rule, as published, is being challenged in the courts by numerous parties, including the state of Florida. The rule sets numeric limits for nitrogen and phosphorous in lakes and streams and for nitrate plus nitrite in springs. The EPA promulgated the rule pursuant to the terms of a consent decree approved by the court in Florida Wildlife Federation v. Jackson, 08-0324 (N.D. Fla.), in which environmentalists sued the EPA for allegedly violating a duty under the Federal Water Pollution Control Act (Clean Water Act or Act) to set the numeric criteria. In response to comments raising numerous implementation concerns, the EPA decided to delay the effective date of the criteria until 15 months after publication. The EPA announced that, in the interim, it would undertake a series of implementation steps in Florida, including an “education and outreach rollout,” training meetings, and the development of guidance materials to coincide with the expected comment period on proposed site-specific alternative criteria. On Nov. 30, 2012, the EPA approved the FDEP rule in its entirety. The EPA proposed additional criteria in December 2012, including a re-proposal of streams criteria that were previously invalidated by the court. In January 2014, the EPA consent decree was revised allowing only the FDEP criteria to be implemented in Florida. Streams criteria may still directly affect Polk Power Station’s cooling reservoir discharge to surface water, which may require the station to reduce the amount of nutrients in the cooling reservoir water before discharge.

After the completion of a study into wastewater discharges by the electric utility industry in 2009, the EPA announced its intent to revise the existing steam electric effluent limit guidelines (ELGs) that place technology-based limits on wastewater discharges. The rulemaking will focus on wastewater discharges from scrubbers, fly ash and bottom ash sluicing processes, leachate from ponds and landfills containing CCRs, IGCC processes, and flue gas mercury controls. The EPA is evaluating a suite of technology options which include treatment processes for wastewater discharges as well as the conversion to dry handling of fly ash and bottom ash to allow for zero discharge of transport water. Final impacts will vary depending on the mandated technology, the volume of wastewater to be treated and the pollutant limits. Tightened limits are anticipated for mercury, selenium, trace metals, and chlorides. New guidelines will likely add stricter limits to future NPDES permits in 2014-2019 (based on the five-year permit cycle).

Section 404 of the Clean Water Act and Coal Surface Mine Permits

Since 2008, the issuance of permits by the USACE under Section 404 of the Clean Water Act required for surface mining activities in the Central and Northern Appalachian mining regions has been challenged in the courts by various environmental groups.

        On April 1, 2010, the EPA issued new guidance on environmental permitting requirements for 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 July 2011, the EPA made this guidance final without modification. 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.

This guidance was challenged in the courts by a number of coal mining industry-related organizations, states and municipalities relating to the stringency of the standards as well as the focus on the coal industry and the Appalachian region in particular. In July 2012, the U. S. 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 permits have been issued by USACE.

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Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Coal Combustion Residuals Recycling and Disposal

The combustion of coal at two of Tampa Electric’s power-generating facilities, the Big Bend and Polk Power stations, produces ash and other by-products, collectively known as CCRs. The CCRs produced at Big Bend include fly ash, FGD gypsum, boiler slag, bottom ash and economizer ash. The CCRs produced at the Polk Power Station include gasifier slag and sulfuric acid. Overall, over 97% of all CCRs produced at these facilities were marketed to customers for beneficial use in commercial and industrial products. The remaining 3% were either disposed of onsite or shipped offsite to nearby industrial waste landfills in Central Florida.

In response to a coal ash pond failure at another utility in December 2008, the EPA proposed new regulations for the management and disposal of CCRs. These proposed rules include two potential designations of CCRs. One designation would categorize CCRs destined for disposal as hazardous wastes. This is the most significant for TEC, because hazardous waste landfills are currently prohibited in Florida by state law, so CCRs destined for disposal would have to be shipped out of state as hazardous waste at significantly increased costs. 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 Tampa Electric’s existing, lined ash ponds. However, this latter proposal would place additional management requirements on these existing disposal units, which would eventually reach the end of their useful life and need to be replaced. The EPA’s current schedule would result in a final proposed rule in 2014, although expected litigation would likely delay the rule’s effective date.

Renewable Energy

Renewables are a component of Tampa Electric’s environmental portfolio. Tampa Electric’s renewable energy program offers to sell renewable energy as an option to customers and utilizes energy generated in the state from renewable sources (e.g. biomass and solar). To date, more than 62 million kWh of renewable energy have been produced by Tampa Electric and other renewable energy generating sources within Florida to support participating customer requirements.

Tampa Electric has installed over 100 kW of solar panels to generate electricity from the sun at six community sites including two schools, Tampa Electric’s Manatee Viewing Center, the Museum of Science and Industry, Tampa’s Lowry Park Zoo and the Florida Aquarium. Tampa Electric’s largest solar panel array, rated at 43.8 kW, is located at Tampa Electric’s Manatee Viewing Center in Apollo Beach, Florida. The electricity the photovoltaic array generates, which flows to Tampa Electric’s grid, could offset the carbon dioxide emissions produced by seven typical-size cars in a year. The company continues to evaluate opportunities for additional solar panel installations.

Conservation

        Energy conservation is becoming increasingly important in a period of volatile energy prices and in the GHG emissions reduction debate. In December 2009, the FPSC established new aggressive demand-side-management (DSM) goals for 2010-2019 for all investor-owned electric utilities. For Tampa Electric, the summer and winter demand goals are 138 and 109 MWs, respectively, and the annual energy goal is 360 gigawatt-hours. Even though these goals are set as a 10-year program, a review of the goals is required every five years. Tampa Electric’s programs are scheduled to be reviewed by the FPSC in 2014.

During 2013, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial programs that enabled the company to meet its required DSM goals, reduce weather-sensitive peak demand and conserve energy. This strategy continues to allow Tampa Electric to delay construction of future generation facilities. Since their inception, the company’s conservation programs have reduced the summer peak demand by 319 MW and the winter peak demand by 719 MW. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. In addition, PGS offers programs that enable customers to reduce their energy consumption with the costs also recovered through a clause on the customer’s bill.

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REGULATION

Tampa Electric’s and PGS’s retail operations are regulated by the FPSC, which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices, and other matters.

In general, the FPSC’s pricing objective is to set rates at a level that provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.

For both Tampa Electric and PGS, the costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include O&M expense, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric and natural gas distribution services (rate base). The rate of return on rate base, which is intended to approximate the individual company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero-cost rate and an allowed ROE. Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, PGS, the FPSC or other parties.

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services, and accounting practices.

Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section).

Tampa Electric - Base Rates

In 2011, 2012 and 2013 prior to Nov. 1, the rates and allowed ROE in effect for Tampa Electric had been established in 2009 and in a series of subsequent decisions in 2009 and 2010. The allowed ROE during this period was a range of 10.25% to 12.25%, with a midpoint of 11.25%.

As a result of growth in rate base from required infrastructure added to serve customers, increasing pressure on O&M expense, and an economic recovery that was slower than expected compared to the assumptions in Tampa Electric’s last base rate proceeding in 2009, on April 5, 2013, Tampa Electric filed its petition with the FPSC for an increase in base rates and miscellaneous service charges in the amount of $134.8 million. In the petition, Tampa Electric requested an ROE level of 11.25% and a capital structure identical to that approved in 2009, with 54% equity.

After extensive testimony by Tampa Electric and discovery by five intervening parties and the FPSC Staff, on Sept. 6, 2013, Tampa Electric and all of the intervening parties reached a Stipulation and Settlement Agreement resolving all of the issues in the proceeding.

On Sept. 11, 2013, the FPSC approved the Settlement that authorized base rate increases implemented at four different dates.

1. Nov. 1, 2013: $57.5 million increase

2. Nov. 1, 2014: Additional $7.5 million increase ($65 million versus current rates)

3. Nov. 1, 2015: Additional $5 million increase ($70 million versus current rates)

4. Jan. 1, 2017: Implementation of a Generation Base Rate Adjustment representing a $110 million additional increase on Jan. 1, 2017, or on the in-service date of the Polk 2-5 conversion, whichever is later.

The Settlement authorized an ROE of 10.25% and equity ratio of 54%, with a provision that ROE becomes 10.50% if at any time during the agreement the six month average 30-year US Treasury Bond yield increases 75 basis points. Base rates will not change if the ROE trigger were to take effect; however, for purposes of cost recovery clauses, AFUDC and surveillance reporting, there would be an adjustment to reflect the 10.50%.

As part of the settlement, Tampa Electric discontinued its annual $8 million storm damage expense accrual at Nov. 1, 2013 and the company will utilize a 15-year amortization period for all software retroactive to Jan. 1, 2013. The company will not be able to file for new base rates to be effective sooner than Jan. 1, 2018, subject to a bilateral opportunity for Tampa Electric or Interveners to initiate a rate proceeding if actual reported ROE falls below a floor of 9.25% or above a ceiling of 11.25%, subject to the 25 basis point incremental ROE if triggered. Lastly, the company is required to file a depreciation study no fewer than 60 days but no more than one year before filing its next base rate request.

The Settlement also contained various changes with respect to rate design. The company will implement a new Commercial and Industrial Service Rider (CISR) and an Economic Development Rate. The new Economic Development Rate will be implemented on a pilot basis for a three-year period and limited by the maximum amount of economic development expenditures as specified in Commission rules, which is approximately $3 million. The current lock-in period for interruptible credits will extend from three to six years and the Standby Generator credit will be adjusted from $4.00 to $4.75.

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FERC Audit

On Nov. 6, 2012, Tampa Electric received notification from the FERC that its accounting practices and financial reporting processes would be audited, along with compliance with the FERC’s records retention requirements. This was considered a routine audit by the FERC staff, though it had been approximately 20 years since Tampa Electric last had a FERC accounting audit.

No material issues have been identified as a result of the audit, and Tampa Electric expects to have an exit audit conference with the FERC staff in 2014, and thereafter to receive a letter from the FERC describing the results of the completed audit.

Tampa Electric Cost-Recovery Clauses

In November 2013, the FPSC approved Tampa Electric’s rates for the various cost-recovery clauses for the period January 2014 through December 2014. Tampa Electric’s fuel filing reflected continued historically low natural gas prices as well as good unit performance more than offset by a lower projected recovery of 2013 fuel costs, which resulted in Tampa Electric seeking a $2.40 increase in its fuel charges for 2014 for a residential customer using 1,000 kWh per month. As of Jan. 1, 2014, the total bill for a residential customer using 1,000 kWh is $109.61, compared to the November 2013 bill of $108.26, which includes the base rate increase discussed above, an increase of $1.35.

Utility Competition – Electric

Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high quality service to retail customers.

Unlike the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including other IOUs, municipal and other utilities, as well as co-generators or other unregulated power generators with uncontracted excess capacity. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a longer term basis. Competition in these markets is primarily based on having available energy to sell to the wholesale market and the price. In Florida, available energy for the wholesale market is affected by the state’s PPSA, which sets the state’s electric energy and environmental policy and governs the building of new generation involving steam capacity of 75 MW or more, that requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. The effect of the PPSA has been to limit the number of unregulated generating units with excess capacity for sale in the wholesale power markets in Florida.

FPSC rules promote cost-competitiveness in the building of new steam generating capacity by requiring IOUs, such as Tampa Electric, to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 MW. The rules, which allow independent power producers and others to bid to supply the new generating capacity, provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids, and provide more stringent standards for the IOUs to recover cost overruns in the event the self-build option is deemed the most cost-effective.

Tampa Electric is not a major participant in the wholesale market because it uses lower cost coal-fired generation to serve its retail customers rather than the wholesale market. Over the past three years, gross revenues from wholesale sales, which include fuel that is a pass-through cost, have averaged approximately 2% of Tampa Electric’s total revenue.

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, or by third-party developers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Tampa Electric offers rebate programs of up to $1.5 million annually to encourage development of solar installations and third-party developers offer attractive financing and leasing arrangements to encourage project development. In Florida, third parties that are not subject to regulation by the FPSC are not permitted to make direct sales of electricity to end use customers. The allowance of direct third party sales would take action by the Florida legislature, which is not expected in its 2014 session.

PGS Rates

PGS’s rates and allowed ROE range of 9.75% to 11.75%, with a midpoint of 10.75%, and an equity ratio of 54.7%, which was established in 2009, are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by PGS, FPSC or other interested parties.

As a result of the unprecedented cold winter weather in 2010, in the second quarter of 2010, PGS projected it would earn above the top of its ROE cap of 11.75% in 2010. PGS recorded a $9.2 million pretax total provision related to the 2010 earnings above the top of the range. In December 2010, PGS and the Office of Public Counsel entered into a stipulation and settlement agreement requesting FPSC approval that $3.0 million pretax of the provision to be refunded to customers in the form of a credit on customers’ bills in 2011, and the remainder be applied to accumulated depreciation reserves. On Jan. 25, 2011 the FPSC approved the stipulation.

PGS Cost-Recovery Clauses

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the PGA clause. This clause is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually during an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage to projected charges for prior periods. In November 2013, the FPSC approved PGS’ request for its PGA cap factor of $0.9185 per therm effective January 2014

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through December 2014. In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates the programs are cost-effective for its ratepayers.

In 2012, the FPSC approved a Cast Iron/Bare Steel Pipe Replacement Rider to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. Utilities nationwide have been encouraged by the U.S. Department of Transportation to replace this older infrastructure as a safety measure. The FPSC approved PGS’ request to accelerate the replacement program of approximately 5%, or 500 miles, of the PGS system at a cost of approximately $80 million over a 10-year period.

Utility Competition – Gas

Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. PGS has taken actions to retain and expand its natural gas distribution business, including managing costs and providing high quality service to customers.

In Florida, gas service is unbundled for all non-residential customers. PGS has a “NaturalChoice” program, offering unbundled transportation service to all eligible customers and allowing non-residential customers and residential customers using more than 1,999 therms annually to purchase commodity gas from a third party but continue to pay PGS for the transportation. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 20,500 transportation-only customers as of Dec. 31, 2013, out of approximately 35,000 eligible customers.

Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby by-passing PGS facilities, or by other utilities seeking to expand existing distribution systems to new customers previously unserved by another utility. In response to this competition, PGS has developed various programs, including the provision of transportation services at discounted rates.

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ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Risk Management Infrastructure

We are subject to various types of market risk in the course of daily operations, as discussed below. We have adopted an enterprise wide approach to the management and control of market and credit risk. Middle Office risk management functions, including credit risk management and risk control, are independent of each transacting entity (Front Office).

Our Risk Management Policy (Policy) governs all energy transacting activity at the TECO Energy group of companies. The policy is approved by our board of directors and administered by a Risk Authorizing Committee (RAC) that is comprised of senior management. Within the bounds of the Policy, the RAC approves specific hedging strategies, new transaction types or products, limits, and transacting authorities. Transaction activity is reported daily and measured against limits. For all commodity risk management activities, derivative transaction volumes are limited to the anticipated volume for customer sales or supplier procurement activities.

The RAC also administers the policy with respect to interest rate risk exposures. Under the policy, the RAC operates and oversees transaction activity. Interest rate derivative transaction activity is directly correlated to borrowing activities.

Risk Management Objectives

The Front Office is responsible for reducing and mitigating the market risk exposures that arise from the ownership of physical assets and contractual obligations, such as debt instruments and firm customer sales contracts. The primary objectives of the risk management organization, the Middle Office, are to quantify, measure, and monitor the market risk exposures arising from the activities of the Front Office and the ownership of physical assets. In addition, the Middle Office is responsible for enforcing the limits and procedures established under the approved risk management policies. Based on the policies approved by the company’s board of directors and the procedures established by the RAC, from time to time, our companies enter into futures, forwards, swaps and option contracts to limit the exposure to items such as:

• Price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS;

• Interest rate fluctuations on debt at TECO Energy and its affiliates; and

• Price fluctuations for physical purchases of fuel at TECO Coal.

Our companies use derivatives only to reduce normal operating and market risks, not for speculative purposes. Our primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. For unregulated operations, the companies use derivative instruments primarily to mitigate the price uncertainty related to commodity inputs, such as diesel fuel.

Derivatives and Hedge Accounting

Accounting standards for derivative instruments and hedging activities require us 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 components of OCI or net income, depending on the designation of those instruments.

Designation of a hedging relationship requires management to make assumptions about the future probability of the timing and amount of the hedged transaction and the future effectiveness of the derivative instrument in offsetting the change in fair value or cash flows of the hedged item or transaction. The determination of fair value is dependent upon certain assumptions and judgments, as described more fully below (see Note 16 to the TECO Energy Consolidated Financial Statements).

Fair Value Measurements

The company has adopted the accounting standards for fair value measurement. These standards define fair value, establish a framework for measuring fair value under GAAP, and expand disclosures about financial assets and liabilities carried at fair value. The majority of the company’s financial assets and liabilities are in the form of natural gas, heating oil or interest rate derivatives classified as cash flow hedges. This adoption did not have a material impact on our results of operations, liquidity or capital.

        Most 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 the provisions of accounting standards for regulated activities, 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.

Heating oil and 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 we used to determine fair value are described in Note 17 to the TECO Energy Consolidated Financial Statements.

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Credit Risk

We have a rigorous process for the establishment of new trading counterparties. This process includes an evaluation of each counterparty’s financial statements, with particular attention paid to liquidity and capital resources; establishment of counterparty specific credit limits; optimization of credit terms; and execution of standardized enabling agreements. Our Credit Guidelines require transactions with counterparties below investment grade to be collateralized.

Contracts with different legal entities affiliated with the same counterparty are consolidated for credit purposes and managed as appropriate, considering the legal structure and any netting agreements in place. Credit exposures are calculated, compared to limits and reported to management on a daily basis. The Credit Guidelines are administered and monitored within the Middle Office, independent of the Front Office.

We have implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. Net liability positions are generally not adjusted as we use our derivative transactions as hedges and we have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward-looking data such as credit default swaps when available and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

Certain of our derivative instruments contain provisions that require our 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 our 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 aggregate fair value of all derivative instruments with credit-risk-related contingent features were in asset positions on Dec. 31, 2013.

Interest Rate Risk

We are exposed to changes in interest rates primarily as a result of our borrowing activities. We may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt. As of Dec. 31, 2013 and 2012, a hypothetical 10% increase in the consolidated group’s weighted-average interest rate on its variable rate debt during the subsequent year would not result in a material impact on pretax earnings. This is driven by the low amounts of variable rate debt at TECO Energy and at our subsidiaries. A hypothetical 10% decrease in interest rates would increase the fair market value of our long-term debt by approximately 2.8% at Dec. 31, 2013, and 2.7% at Dec. 31, 2012 (see the Financing Activity section and Notes 6 and 7 to the TECO Energy Consolidated Financial Statements ). These amounts were determined based on the variable rate obligations existing on the indicated dates at TECO Energy and its subsidiaries. The above sensitivities assume no changes to our financial structure and could be affected by changes in our credit ratings, changes in general economic conditions or other external factors (see the Risk Factors section).

Commodity Risk

We and our affiliates face varying degrees of exposure to commodity risks including coal, natural gas, fuel oil and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. Management uses different risk measurement and monitoring tools based on the degree of exposure of each operating company to commodity risks.

Regulated Utilities

Historically, Tampa Electric’s fuel costs used for generation were affected primarily by the price of coal and, to a lesser degree, the cost of natural gas and fuel oil. With the repowering of the Bayside Power Station, the use of natural gas, with its more volatile pricing, has increased substantially. PGS has exposure related to the price of purchased gas and pipeline capacity.

Currently, Tampa Electric’s and PGS’s commodity price risks are largely mitigated by the fact that increases in the price of fuel and purchased power are recovered through FPSC-approved cost-recovery clauses, with no anticipated effect on earnings. However, increasing fuel cost-recovery has the potential to affect total energy usage and the relative attractiveness of electricity and natural gas to consumers. To moderate the impact of fuel price changes on customers, both Tampa Electric and PGS manage commodity price risk by entering into long-term fuel supply agreements, prudently operating plant facilities to optimize cost, and entering into derivative transactions designated as cash flow hedges of anticipated purchases of wholesale natural gas. At Dec. 31, 2013 and 2012, a change in commodity prices would not have had a material impact on earnings for Tampa Electric or PGS, but could have had an impact on the timing of the cash recovery of the cost of fuel (see the Tampa Electric and Regulation sections).

TECO Coal

TECO Coal is subject to significant commodity risk. TECO Coal does not speculate using derivative instruments. However, all derivative instruments may not receive hedge accounting treatment due to the strict requirements and narrow applicability of the accounting rules to dynamic transactions.

TECO Coal is exposed to commodity price risk through coal sales as a part of its daily operations. Where possible and economical, TECO Coal enters into fixed-price sales transactions to mitigate variability in coal prices. TECO Coal is also exposed to variability in operating costs as a result of periodic purchases of diesel oil in its operations. At Dec. 31, 2013, TECO Coal had derivative instruments in place to reduce the price variability for its anticipated 2014 diesel oil purchases for nearly all coal production volumes sold under contracts that did not include a fuel price component. Accordingly, a change in the average annual price for diesel oil is not expected to significantly change TECO Coal’s cost of production.

72

Changes in Fair Value of Derivatives (millions)

Net fair value of derivatives as of Dec. 31, 2012	$	(15.0	)
Additions and net changes in unrealized fair value of derivatives		7.0
Changes in valuation techniques and assumptions		—
Realized net settlement of derivatives		17.7
Net fair value of derivatives as of Dec. 31, 2013	$	9.7

Roll-Forward of Derivative Net Assets (Liabilities) (millions)

Total derivative net liabilities as of Dec. 31, 2012	$	(15.0	)
Change in fair value of net derivative assets:
Recorded as regulatory assets and liabilities or other comprehensive income		7.0
Recorded in earnings		—
Realized at settlement of derivatives		17.7
Net option premium payments		—
Net purchase (sale) of existing contracts		—
Net fair value of derivatives as of Dec. 31, 2013	$	9.7

Maturity and Source of Energy Derivative Contracts Net Assets (Liabilities) at Dec. 31, 2013

(millions)	Current		Non-current		Total Fair Value
Source of fair value
Actively quoted prices	$	—	$	—	$	—
Other external price sources (1)		9.6		0.1		9.7
Model prices (2)		—		—		—
Total	$	9.6	$	0.1	$	9.7

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

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

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

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

TECO ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page No.
Report of Independent Registered Certified Public Accounting Firm		75
Consolidated Balance Sheets, Dec. 31, 2013 and 2012		76-77
Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011		78
Consolidated Statements of Comprehensive Income for the years ended Dec. 31, 2013, 2012 and 2011		79
Consolidated Statements of Cash Flows for the years ended Dec. 31, 2013, 2012 and 2011		80
Consolidated Statements of Capital for the years ended Dec. 31, 2013, 2012 and 2011		81
Notes to Consolidated Financial Statements		82-123
Management’s Report on Internal Control Over Financial Reporting		159
Financial Statement Schedule II – Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2013, 2012 and 2011		163
Signatures		165

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.

74

Report of Independent Registered Certified Public Accounting Firm

To the Board of Directors and Shareholders of TECO Energy, Inc.:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TECO Energy, Inc and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

February 28, 2014

75

TECO ENERGY, INC.

Consolidated Balance Sheets

Assets (millions)	Dec. 31, 2013			Dec. 31, 2012
Current assets
Cash and cash equivalents	$	185.2		$	200.5
Receivables, less allowance for uncollectibles of $4.7 and $4.2 at Dec. 31, 2013 and 2012, respectively		287.2			282.7
Inventories, at average cost
Fuel		118.7			123.6
Materials and supplies		85.9			82.1
Derivative assets		9.7			0.0
Regulatory assets		34.3			70.3
Deferred income taxes		100.3			63.3
Prepayments and other current assets		34.9			33.9
Income tax receivables		1.5			0.4
Total current assets		857.7			856.8
Property, plant and equipment
Utility plant in service
Electric		6,934.0			6,655.8
Gas		1,308.3			1,228.3
Construction work in progress		386.7			336.1
Other property		448.3			443.8
Property, plant and equipment, at original costs		9,077.3			8,664.0
Accumulated depreciation		(2,907.2	)		(2,695.5	)
Total property, plant and equipment, net		6,170.1			5,968.5
Other assets
Regulatory assets		293.1			382.6
Derivative assets		0.3			0.2
Deferred charges and other assets		126.8			126.8
Total other assets		420.2			509.6
Total assets	$	7,448.0		$	7,334.9

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

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TECO ENERGY, INC.

Consolidated Balance Sheets – continued

Liabilities and Capital (millions)	Dec. 31, 2013			Dec. 31, 2012
Current liabilities
Long-term debt due within one year	$	83.3		$	0.0
Notes payable		84.0			0.0
Accounts payable		261.7			232.8
Customer deposits		164.5			162.9
Regulatory liabilities		85.8			105.6
Derivative liabilities		0.1			14.6
Interest accrued		31.9			33.2
Taxes accrued		34.6			32.1
Other		19.5			19.9
Total current liabilities		765.4			601.1
Other liabilities
Deferred income taxes		444.0			277.9
Investment tax credits		9.4			9.7
Regulatory liabilities		631.4			631.4
Derivative liabilities		0.2			0.6
Deferred credits and other liabilities		426.1			549.7
Long-term debt, less amount due within one year		2,837.8			2,972.7
Total other liabilities		4,348.9			4,442.0
Commitments and Contingencies (see Note 12)
Capital
Common equity (400.0 million shares authorized; par value $1; 217.3 million and 216.6 million shares outstanding at Dec. 31, 2013 and 2012, respectively)		217.3			216.6
Additional paid in capital		1,581.3			1,564.5
Retained earnings		548.3			541.7
Accumulated other comprehensive loss		(13.2	)		(31.0	)
Total TECO Energy capital		2,333.7			2,291.8
Total liabilities and capital	$	7,448.0		$	7,334.9

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

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TECO ENERGY, INC.

Consolidated Statements of Income

(millions, except per share amounts) For the years ended Dec. 31,		2013			2012			2011
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $108.5 in 2013, $111.5 in 2012 and $109.3 in 2011)		$	2,342.5		$	2,377.4		$	2,469.8
Unregulated			508.8			619.2			740.1
Total revenues			2,851.3			2,996.6			3,209.9
Expenses
Regulated operations and maintenance
Fuel			680.2			694.7			731.4
Purchased power			64.7			105.3			125.9
Cost of natural gas sold			142.2			155.7			210.4
Other			524.4			462.5			436.9
Operation and maintenance other expense
Mining related costs			419.0			461.1			574.1
Other			12.5			7.9			7.1
Depreciation and amortization			329.5			330.6			317.2
Taxes, other than income			215.1			222.3			223.7
Total expenses			2,387.6			2,440.1			2,626.7
Income from operations			463.7			556.5			583.2
Other income (expense)
Allowance for other funds used during construction			6.3			2.6			1.0
Other income			3.6			9.4			6.7
Loss on debt extinguishment			0.0			(1.2	)		0.0
Total other income			9.9			10.8			7.7
Interest charges
Interest expense			170.5			185.0			198.0
Allowance for borrowed funds used during construction			(3.6	)		(1.5	)		(0.6	)
Total interest charges			166.9			183.5			197.4
Income from continuing operations before provision for income taxes			306.7			383.8			393.5
Provision for income taxes			108.9			137.8			142.7
Net income from continuing operations			197.8			246.0			250.8
Discontinued operations
Income (loss) from discontinued operations			(0.2	)		(10.6	)		33.3
Provision for income taxes			(0.1	)		22.4			11.2
Income (loss) from discontinued operations, net			(0.1	)		(33.0	)		22.1
Less: Income from discontinued operations attributable to noncontrolling interest			0.0			0.3			0.3
Income (loss) from discontinued operations attributable to TECO Energy, net			(0.1	)		(33.3	)		21.8
Net income attributable to TECO Energy		$	197.7		$	212.7		$	272.6
Average common shares outstanding	– Basic		215.0			214.3			213.6
	– Diluted		215.5			215.0			215.1
Earnings per share from continuing operations	– Basic	$	0.92		$	1.14		$	1.17
	– Diluted	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy	– Basic	$	0.00		($	0.15	)	$	0.10
	– Diluted	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy	– Basic	$	0.92		$	0.99		$	1.27
	– Diluted	$	0.92		$	0.99		$	1.27
Dividends paid per common share outstanding		$	0.88		$	0.88		$	0.85

Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

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

78

TECO ENERGY, INC.

Consolidated Statements of Comprehensive Income

(millions) For the years ended Dec. 31,	2013		2012			2011
Net income attributable to TECO Energy	$	197.7	$	212.7		$	272.6
Other comprehensive income (loss), net of tax
Net unrealized gains (losses) on cash flow hedges		1.4		(4.2	)		(0.8	)
Amortization of unrecognized benefit costs and other		14.8		(4.8	)		(4.6	)
Recognized benefit costs due to settlement		1.6		0.0			0.6
Other comprehensive income (loss), net of tax		17.8		(9.0	)		(4.8	)
Comprehensive income attributable to TECO Energy	$	215.5	$	203.7		$	267.8

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

79

TECO ENERGY, INC.

Consolidated Statements of Cash Flows

(millions) For the years ended Dec. 31,	2013			2012			2011
Cash flows from operating activities
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		329.5			337.7			324.6
Deferred income taxes		110.4			136.9			146.0
Investment tax credits		(0.3	)		(0.3	)		(0.4	)
Allowance for other funds used during construction		(6.3	)		(2.6	)		(1.0	)
Non-cash stock compensation		13.5			12.0			9.1
(Gain) loss on sales of business/assets, pretax		(1.6	)		18.5			(0.5	)
Deferred recovery clauses		(6.2	)		(8.9	)		(9.0	)
Asset impairment, pretax		0.0			17.2			0.0
Receivables, less allowance for uncollectibles		(4.5	)		37.7			5.7
Inventories		1.1			(2.4	)		23.5
Prepayments and other current assets		(2.2	)		(2.0	)		(2.8	)
Taxes accrued		1.4			12.1			(5.7	)
Interest accrued		(1.3	)		(5.9	)		0.3
Accounts payable		35.9			(1.3	)		(42.6	)
Other		(8.5	)		(4.7	)		34.3
Cash flows from operating activities		658.6			756.7			754.1
Cash flows from investing activities
Capital expenditures		(532.4	)		(505.1	)		(454.1	)
Allowance for other funds used during construction		6.3			2.6			1.0
Net proceeds from sales of business/assets		4.3			194.4			3.5
Restricted cash		0.0			8.9			0.0
Other investing activities		0.0			0.0			14.4
Cash flows used in investing activities		(521.8	)		(299.2	)		(435.2	)
Cash flows from financing activities
Dividends		(191.2	)		(190.4	)		(183.2	)
Proceeds from the sale of common stock		6.7			3.9			7.0
Proceeds from long-term debt issuance		0.0			538.1			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(51.6	)		(650.4	)		(153.6	)
Change in short-term debt		84.0			0.0			(12.0	)
Other financing activities		0.0			(2.2	)		(0.6	)
Cash flows used in financing activities		(152.1	)		(301.0	)		(342.4	)
Net (decrease) increase in cash and cash equivalents		(15.3	)		156.5			(23.5	)
Cash and cash equivalents at beginning of the year		200.5			44.0			67.5
Cash and cash equivalents at end of the year	$	185.2		$	200.5		$	44.0
Supplemental disclosure of cash flow information
Cash paid during the year for:
Interest	$	161.0		$	188.4		$	191.6
Income taxes paid	$	1.8		$	7.2		$	9.4

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

80

TECO ENERGY, INC.

Consolidated Statements of Capital

(millions)	Shares (1)		Common Stock		Additional Paid in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Capital
Balance, Dec. 31, 2010		214.9	$	214.9	$	1,542.0		$	430.0		($	17.2	)	$	0.9		$	2,170.6
Net income									272.6						0.3			272.9
Other comprehensive loss, after tax												(4.8	)					(4.8	)
Common stock issued		0.9		0.9		0.1												1.0
Cash dividends declared									(183.2	)								(183.2	)
Stock compensation expense						9.1												9.1
Noncontrolling - dividends															(0.6	)		(0.6	)
Tax benefits - stock compensation						2.2												2.2
Balance, Dec. 31, 2011		215.8	$	215.8	$	1,553.4		$	519.4		($	22.0	)	$	0.6		$	2,267.2
Net income									212.7						0.3			213.0
Other comprehensive loss, after tax												(9.0	)					(9.0	)
Common stock issued		0.8		0.8		(3.7	)											(2.9	)
Cash dividends declared									(190.4	)								(190.4	)
Stock compensation expense						12.0												12.0
Noncontrolling - dividends															(0.3	)		(0.3	)
Tax benefits - stock compensation						2.8												2.8
Noncontrolling - sale of business															(0.6	)		(0.6	)
Balance, Dec. 31, 2012		216.6	$	216.6	$	1,564.5		$	541.7		($	31.0	)	$	0.0		$	2,291.8
Net income									197.7									197.7
Other comprehensive income, after tax												17.8						17.8
Common stock issued		0.7		0.7		5.2												5.9
Cash dividends declared									(191.2	)								(191.2	)
Stock compensation expense						13.5												13.5
Restricted stock - dividends						1.0			0.1									1.1
Tax short fall - stock compensation						(2.9	)											(2.9	)
Balance, Dec. 31, 2013		217.3	$	217.3	$	1,581.3		$	548.3		($	13.2	)	$	0.0		$	2,333.7

(1) TECO Energy had a maximum of 400.0 million shares of $1 par value common stock authorized as of Dec. 31, 2013, 2012, 2011 and 2010.

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

81

TECO ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

The significant accounting policies for both utility and diversified operations are as follows:

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiaries do not have majority ownership or exercise control.

For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).

Use of Estimates

The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.

Restricted Cash

Restricted cash of $8.7 million related to cash held in escrow for the 2003 sale of HPP, was released from escrow in 2012 upon maturity of debt financing that was held by the purchaser of HPP. There was no restricted cash at Dec. 31, 2013.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Planned Major Maintenance

Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.

Tampa Electric and PGS expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

82

Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:

Asset	Estimated Useful Lives
Building and improvements	5 - 40 years
Office equipment and furniture	3 - 30 years
Vehicles, mining and other equipment	2 - 15 years
Coal processing facilities	7 - 20 years
Computer software	2 - 15 years

Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $316.5 million, $309.3 million and $306.6 million, respectively.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis.

Fuel Inventory (millions)	Dec. 31, 2013		Dec. 31, 2012
TEC	$	93.7	$	89.1
TECO Coal		25.0		34.5
Total	$	118.7	$	123.6

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).

Deferred Income Taxes

TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Revenue Recognition

TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer.

Revenues for energy marketing operations at TECO Energy Source are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2013, 2012 and 2011 were $23.1 million, $13.8 million and $2.5 million, respectively.

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Shipping and Handling

TECO Coal includes the costs to ship product to customers in “Operation & maintenance other expense - Mining related costs” on the Consolidated Statements of Income which for the years ended Dec. 31, 2013, 2012 and 2011 were $8.2 million, $9.0 million and $16.6 million, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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

Revenues and Cost Recovery

Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.

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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of mining development costs amortized on a per ton basis and offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2013 and 2012 ranged from 3.51% to 4.86% and 2.60% to 4.00%, respectively.

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Stock-Based Compensation

TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.

Receivables and Allowance for Uncollectible Accounts

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on Tampa Electric’s and PGS’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. TECO Coal’s receivables consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.

Reclassifications

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

2. New Accounting Pronouncements

Unrecognized Tax Benefits

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

Comprehensive Income

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

Offsetting Assets and Liabilities

In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. The company has adopted this guidance as required. It had no effect on the company’s results of operations, financial position or cash flows.

3. Regulatory

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

Base Rates-Tampa Electric

Tampa Electric’s results for the first ten months of 2013, and all of 2012 and 2011, reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

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

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

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

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

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Storm Damage Cost Recovery

Prior to the above mentioned stipulation and settlement agreement, 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. Tampa Electric’s storm reserve was $56.1 million and $50.4 million as of Dec. 31, 2013 and 2012, respectively. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to the level as of Oct. 31, 2013.

Regulatory Assets and Liabilities

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

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

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

Regulatory Assets and Liabilities
(millions)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.4	$	67.2
Other:
Cost-recovery clauses		6.1		42.9
Postretirement benefit asset		182.7		276.1
Deferred bond refinancing costs (2)		8.0		9.2
Environmental remediation		51.4		46.9
Competitive rate adjustment		4.1		4.1
Other		7.7		6.5
Total other regulatory assets		260.0		385.7
Total regulatory assets		327.4		452.9
Less: Current portion		34.3		70.3
Long-term regulatory assets	$	293.1	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	9.8	$	14.6
Other:
Cost-recovery clauses		54.5		73.9
Transmission and delivery storm reserve		56.1		50.4
Deferred gain on property sales (3)		2.0		3.4
Provision for stipulation and other		0.8		1.0
Accumulated reserve - cost of removal		594.0		593.7
Total other regulatory liabilities		707.4		722.4
Total regulatory liabilities		717.2		737.0
Less: Current portion		85.8		105.6
Long-term regulatory liabilities	$	631.4	$	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
(millions)	Dec. 31, 2013		Dec. 31, 2012
Clause recoverable (1)	$	10.2	$	47.0
Components of rate base (2)		185.6		279.1
Regulatory tax assets (3)		67.4		67.2
Capital structure and other (3)		64.2		59.6
Total	$	327.4	$	452.9

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

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

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

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4. Income Taxes

In 2013, 2012 and 2011, TECO Energy recorded net tax provisions of $108.8 million, $160.2 million and $153.9 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes paid for income taxes as required for the alternative minimum tax, state income taxes, foreign income taxes and prior year audits in 2013, 2012 and 2011 were $1.8 million, $7.2 million and $9.4 million, respectively.

Income tax expense consists of the following:

Income Tax Expense (Benefit)
(millions) For the year ended Dec. 31,	2013			2012			2011
Continuing Operations
Current income taxes
Federal	$	2.2		$	15.7		$	0.0
State		(3.5	)		1.1			0.9
Deferred income taxes
Federal		98.6			102.9			124.0
State		11.9			18.4			18.2
Amortization of investment tax credits		(0.3	)		(0.3	)		(0.4	)
Income tax expense from continuing operations	$	108.9		$	137.8		$	142.7
Discontinued Operations
Current income taxes
Federal	$	0.0		$	0.0		$	0.0
Foreign		0.0			6.8			7.4
State		0.0			0.0			0.0
Deferred income taxes
Federal		(0.1	)		14.9			4.4
Foreign		0.0			0.0			(0.3	)
State		0.0			0.7			(0.3	)
Income tax expense from discontinued operations		(0.1	)		22.4			11.2
Total income tax expense	$	108.8		$	160.2		$	153.9

During 2013, TECO Energy increased its net operating loss carryforward. Total current income tax expense for the years ended Dec. 31, 2012 and 2011 was reduced by $13.6 million and $32.1 million, respectively, to reflect the benefits of operating loss carryforwards.

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The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:

Effective Income Tax Rate
(millions) For the year ended Dec. 31,	2013			2012			2011
Income tax expense at the federal statutory rate of 35%	$	107.3		$	134.3		$	137.7
Increase (decrease) due to:
State income tax, net of federal income tax		5.5			12.7			12.4
Equity portion of AFUDC		(2.2	)		(0.9	)		(0.4	)
Valuation allowance		0.0			1.1			0.0
Depletion		(3.7	)		(8.5	)		(9.1	)
Other		2.0			(0.9	)		2.1
Total income tax expense from continuing operations	$	108.9		$	137.8		$	142.7
Income tax expense as a percent of income from continuing operations, before income taxes		35.5	%		35.9	%		36.3	%

For the three years presented, the overall effective tax rate on continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes offset by depletion.

As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2013 will be realized in future periods.

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The major components of the company’s deferred tax assets and liabilities recognized are as follows:

Deferred Income Taxes
(millions)
As of Dec. 31,	2013			2012
Deferred tax liabilities (1)
Property related	$	1,164.2		$	1,023.3
Deferred fuel		1.6			11.3
Pension		52.8			43.0
Total deferred tax liabilities		1,218.6			1,077.6
Deferred tax assets (1)
Alternative minimum tax credit carryforward		213.0			211.8
Loss and credit carryforwards (2)		479.8			473.2
Other postretirement benefits		68.9			68.0
Other		113.2			113.0
Total deferred tax assets		874.9			866.0
Valuation allowance		0.0			(3.0	)
Total deferred tax assets, net of valuation allowance		874.9			863.0
Total deferred tax liability, net		343.7			214.6
Less: Current portion of deferred tax asset		(100.3	)		(63.3	)
Long-term portion of deferred tax liability, net	$	444.0		$	277.9

(1) Certain property related assets and liabilities have been netted.

(2) As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2013 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.

At Dec. 31, 2013, the company had cumulative unused federal and state (Florida) NOLs for income tax purposes of $1,321.9 million and $392.6 million, respectively, expiring at various times between 2025 and 2028. In addition, the company has unused general business credits of $3.9 million expiring between 2026 and 2032. Due to the sale of the company’s remaining Guatemalan operations, unused foreign tax credits of $38.5 million have been reclassed to net operating loss. During 2013, the company’s available alternative minimum tax credit carryforward for tax purposes increased from $211.8 million to $213.0 million, reflecting the future AMT payable for the amendment of prior years’ federal income tax returns to claim a deduction for foreign tax paid. The alternative minimum tax credit may be used indefinitely to reduce federal income taxes.

The company’s consolidated balance sheet reflects loss carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through a reduction in income taxes payable.

The company establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. A state capital loss carryforward valuation allowance of $3.0 million was recorded as of Dec. 31, 2012. For the year ended Dec. 31, 2013, the company recorded a full valuation allowance release of $3.0 million due to the expiration of the state capital loss carryforward.

The company accounts for uncertain tax positions in accordance with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

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A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Unrecognized Tax Benefits
(millions)	2013			2012
Balance at Jan. 1,	$	2.9		$	4.1
Decreases due to tax positions related to prior years		0.0			0.0
Decreases due to settlements with taxing authorities		0.0			0.0
Decreases due to expiration of statute of limitations		(2.9	)		0.0
Dispositions		0.0			(1.2	)
Balance at Dec. 31,	$	0.0		$	2.9

The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense – Other” in the Consolidated Statements of Income. In 2013, 2012 and 2011, the company recognized $(0.9) million, $0.3 million and $0.2 million, respectively, of pretax charges (benefits) for interest only. Additionally, the company had $0.0 million of interest accrued at Dec. 31, 2013 and $0.9 million of interest accrued at Dec. 31, 2012. No amounts have been recorded for penalties. As a result of the 2012 sale of TCAE, interest and penalties recorded on TCAE’s books for an uncertain tax position have been removed from the company’s unrecognized tax benefits (see Note 19).

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 the year 2010 and forward. The federal income tax return for calendar year 2013 is part of the IRS’s Compliance Assurance Program. As a result, the IRS audit of such return is expected to be completed in 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 taxing authorities in major state jurisdictions include 2010 and forward. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

5. Employee Postretirement Benefits

Pension Benefits

TECO Energy has a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In July 2012, the President signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under MAP-21.

The qualified pension plan’s actuarial value of assets, including credit balance, was 96.7% of the Pension Protection Act funded target as of Jan. 1, 2013 and is estimated at 98.2% of the Pension Protection Act funded target as of Jan. 1, 2014.

Amounts disclosed for pension benefits also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

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The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2012. TEC is amortizing the regulatory asset over the remaining average service life of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. Prior to this, the company received subsidy payments under Medicare Part D for its post-65 retiree prescription drug plan.

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Obligations and Funded Status

TECO Energy recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC. The results of operations are not impacted. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in the Consolidated Balance Sheets for 2013 and 2012.

Obligations and Funded Status	Pension Benefits						Other Benefits
(millions)	2013			2012			2013			2012
Change in benefit obligation
Net benefit obligation at beginning of year	$	715.0		$	646.4		$	230.3		$	216.5
Service cost		18.2			17.0			2.5			2.4
Interest cost		28.9			30.1			9.3			10.1
Plan participants’ contributions		0.0			0.0			2.9			3.7
Plan amendments		0.0			0.0			0.0			(5.2	)
Actuarial loss (gain)		(50.4	)		54.7			(22.1	)		16.3
Gross benefits paid		(43.1	)		(33.2	)		(15.0	)		(14.5	)
Settlements		(2.6	)		0.0			0.0			0.0
Federal subsidy on benefits paid		n/a			n/a			0.2			1.0
Net benefit obligation at end of year	$	666.0		$	715.0		$	208.1		$	230.3
Change in plan assets
Fair value of plan assets at beginning of year	$	529.1		$	467.6		$	0.0		$	0.0
Actual return on plan assets		63.7			57.9			0.0			0.0
Employer contributions		45.9			36.8			11.9			9.8
Plan participants’ contributions		0.0			0.0			2.9			3.7
Settlements		(2.6	)		0.0			0.0			0.0
Net benefits paid		(43.1	)		(33.2	)		(14.8	)		(13.5	)
Fair value of plan assets at end of year	$	593.0		$	529.1		$	0.0		$	0.0
Funded status
Fair value of plan assets (1)	$	593.0		$	529.1		$	0.0		$	0.0
Less: Benefit obligation (PBO/APBO)		666.0			715.0			208.1			230.3
Funded status at end of year		(73.0	)		(185.9	)		(208.1	)		(230.3	)
Unrecognized net actuarial loss		173.1			270.3			19.7			42.7
Unrecognized prior service (benefit) cost		(0.4	)		(0.7	)		(0.7	)		(1.0	)
Net amount required to be recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)
Amounts recognized in balance sheet
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(3.3	)		(5.3	)		(13.3	)		(13.1	)
Deferred credits and other liabilities		(69.7	)		(180.6	)		(194.8	)		(217.2	)
Accumulated other comprehensive loss (income), pretax		33.1			53.1			(24.2	)		(17.9	)
Net amount recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

Amounts recognized in accumulated other comprehensive income

	Pension Benefits				Other Benefits
(millions)	2013		2012		2013			2012
Net actuarial loss (gain)	$	32.7	$	52.7	$	(23.8	)	$	(17.2	)
Prior service cost (credit)		0.4		0.4		(0.4	)		(0.7	)
Amount recognized	$	33.1	$	53.1	$	(24.2	)	$	(17.9	)

The accumulated benefit obligation for all defined benefit pension plans was $624.1 million at Dec. 31, 2013 and $664.7 million at Dec. 31, 2012. The projected benefit obligation for the other postretirement benefits plan was $208.1 million at Dec. 31, 2013 and $230.3 million at Dec. 31, 2012.

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Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2013			2012			2013			2012
Discount rate		5.118	%		4.196	%		5.096	%		4.180	%
Rate of compensation increase - weighted		3.73	%		3.76	%		3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			7.25	%		7.50	%
Ultimate rate		n/a			n/a			4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			2025			2025

A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:

(millions)	1% Increase		1% Decrease
Effect on postretirement benefit obligation	$	6.8	$	(6.1	)

The discount rate assumption used to determine the Dec. 31, 2013 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

	Pension Benefits									Other Benefits
Net periodic benefit cost
(millions)	2013			2012			2011			2013			2012			2011
Service cost	$	18.2		$	17.0		$	16.0		$	2.4		$	2.4		$	2.1
Interest cost		28.9			30.1			30.9			9.3			10.1			11.1
Expected return on plan assets		(38.4	)		(37.1	)		(38.4	)		0.0			0.0			0.0
Amortization of:
Actuarial loss		20.5			15.3			11.3			1.0			0.1			0.1
Prior service (benefit) cost		(0.4	)		(0.4	)		(0.4	)		(0.3	)		0.8			0.8
Transition obligation		0.0			0.0			0.0			0.0			1.8			2.3
Settlement loss		1.0			0.0			0.9			0.0			0.0			0.0
Net periodic benefit cost	$	29.8		$	24.9		$	20.3		$	12.4		$	15.2		$	16.4
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and regulatory assets
(millions)	2013			2012			2011			2013			2012			2011
Prior service cost	$	0.0		$	0.0		$	0.0		$	0.0		$	(5.2	)	$	0.0
Net loss (gain)		(75.7	)		34.0			43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)		(21.5	)		(15.3	)	$	(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost		0.4			0.4			0.4			0.3			(0.8	)		(0.8	)
Transition obligation		0.0			0.0			0.0			0.0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets	$	(96.8	)	$	19.1		$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(67.0	)	$	44.0		$	51.8		$	(3.9	)	$	23.6		$	5.7

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $2.5 million and $0.1 million, respectively. The estimated prior service credit for the other postretirement benefit plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.2 million.

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In addition, the estimated net loss and prior service credit for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $10.5 million and $0.5 million, respectively. There will be no remaining net loss for the other postretirement benefit plan that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Discount rate		4.196	%		4.797	%		5.300	%		4.180	%		4.744	%		5.250	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.75	%		n/a			n/a			n/a
Rate of compensation increase		3.76	%		3.83	%		3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Initial rate		n/a			n/a			n/a			7.50	%		7.75	%		8.00	%
Ultimate rate		n/a			n/a			n/a			4.50	%		4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			n/a			2025			2025			2023

The discount rate assumption used to determine the 2013 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2013, TECO Energy’s pension plan experienced actual asset returns of approximately 12%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:

(millions)	1% Increase		1% Decrease
Effect on periodic cost	$	0.3	$	(0.3	)

Pension Plan Assets

Pension plan assets (plan assets) are primarily invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target Allocation	Actual Allocation, End of Year
Asset Category		2013			2012
Equity securities	48%-54%		54	%		55	%
Fixed income securities	46%-52%		46	%		45	%
Total	100%		100	%		100	%

The company reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company expects to take additional steps to more closely match plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.

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If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and Dec. 31, 2012.

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2013
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	44.7		$	0.0		$	0.0	$	44.7
Accounts payable		(40.8	)		0.0			0.0		(40.8	)
Cash equivalents
Short term investment funds (STIFs)		7.9			0.0			0.0		7.9
Treasury bills (T bills)		0.0			0.3			0.0		0.3
Repurchase agreement		0.0			8.8			0.0		8.8
Commercial paper		0.0			0.4			0.0		0.4
Money markets		0.0			1.5			0.0		1.5
Total cash equivalents		7.9			11.0			0.0		18.9
Equity securities
Common stocks		91.6			0.0			0.0		91.6
American depository receipts (ADRs)		3.0			0.0			0.0		3.0
Real estate investment trusts (REITs)		1.7			0.0			0.0		1.7
Preferred stock		0.0			0.8			0.0		0.8
Mutual funds		172.6			0.0			0.0		172.6
Commingled fund		0.0			50.0			0.0		50.0
Total equity securities		268.9			50.8			0.0		319.7
Fixed income securities
Municipal bonds		0.0			7.3			0.0		7.3
Government bonds		0.0			35.7			0.0		35.7
Corporate bonds		0.0			19.6			0.0		19.6
Asset backed securities (ABS)		0.0			0.4			0.0		0.4
Mortgage-backed securities (MBS), net short sales		0.0			6.7			0.0		6.7
Collateralized mortgage obligations (CMOs)		0.0			2.3			0.0		2.3
Mutual fund		0.0			85.1			0.0		85.1
Commingled fund		0.0			94.1			0.0		94.1
Total fixed income securities		0.0			251.2			0.0		251.2
Derivatives
Short futures		0.0			0.2			0.0		0.2
Swaps		0.0			(0.9	)		0.0		(0.9	)
Purchased options (swaptions)		0.0			0.2			0.0		0.2
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.9	)		0.0		(0.9	)
Miscellaneous		0.0			0.2			0.0		0.2
Total	$	280.7		$	312.3		$	0.0	$	593.0

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Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2012
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	64.8		$	0.0		$	0.0	$	64.8
Accounts payable		(72.8	)		0.0			0.0		(72.8	)
Cash equivalents
STIFs		9.0			0.0			0.0		9.0
T bills		0.0			0.6			0.0		0.6
Repurchase agreements		0.0			23.1			0.0		23.1
CDs		0.0			1.1			0.0		1.1
Commercial paper		0.0			0.9			0.0		0.9
Money markets		0.0			0.6			0.0		0.6
Total cash equivalents		9.0			26.3			0.0		35.3
Equity securities
Common stocks		125.3			0.0			0.0		125.3
ADRs		6.2			0.0			0.0		6.2
REITs		2.0			0.0			0.0		2.0
Preferred stocks		0.0			0.8			0.0		0.8
Equity mutual funds		153.4			0.0			0.0		153.4
Total equity securities		286.9			0.8			0.0		287.7
Fixed income securities
Municipal bonds		0.0			8.0			0.0		8.0
Government bonds		0.0			53.0			0.0		53.0
Corporate bonds		0.0			19.8			0.0		19.8
ABS		0.0			0.5			0.0		0.5
MBS		0.0			17.6			0.0		17.6
CMBS		0.0			0.3			0.0		0.3
CMOs		0.0			2.5			0.0		2.5
Fixed income mutual fund		0.0			63.7			0.0		63.7
Fixed income commingled fund		0.0			49.4			0.0		49.4
Total fixed income securities		0.0			214.8			0.0		214.8
Derivatives
Swaps		0.0			(0.5	)		0.0		(0.5	)
Purchased options (swaptions)		0.0			0.1			0.0		0.1
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.8	)		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.1
Total	$	287.9		$	241.2		$	0.0	$	529.1

• The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.

• The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.

• The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.

• The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.

• T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.

• The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.

• The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.

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• The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.

• The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

Other Postretirement Benefit Plan Assets

There are no assets associated with the company’s other postretirement benefits plan.

Contributions

The company’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $42.0 million and $35.5 million of contributions to this plan in 2013 and 2012, respectively, which met the minimum funding requirements for both 2013 and 2012. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2014 to be $47.5 million and expects to make contributions from 2015 to 2018 in the range of $4.0 to $48.0 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.

The SERP is funded annually to meet the benefit obligations. The company made contributions of $2.6 million and $1.3 million to this plan in 2013 and 2012, respectively. In 2014, the company expects to make a contribution of about $3.3 million to this plan.

The other postretirement benefits are funded annually to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2014, the company expects to make a contribution of about $13.3 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments
(including projected service and net of employee contributions)
(millions)	Pension Benefits		Other Postretirement Benefits
2014	$	53.5	$	13.3
2015		50.9		13.9
2016		55.3		14.6
2017		55.9		15.2
2018		58.3		15.7
2019-2023		298.6		81.9

Defined Contribution Plan

The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective April 2013, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31, 2013, 2012 and 2011, the company and its subsidiaries recognized expense totaling $11.3 million, $7.0 million and $9.0 million, respectively, related to the matching contributions made to this plan.

Black Lung Liability

TECO Coal is required by federal and state statutes to provide benefits to terminated, retired or (under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal is self-insured for black lung related claims. Annual expense is recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. At Dec. 31, 2013 and 2012, TECO Coal had an actuarially-determined black lung liability of $24.5 million and $27.1 million, respectively. TECO Coal recognized expense related to the black lung liability of $2.2 million, $1.8 million, and $1.7 million for 2013, 2012 and 2011, respectively.

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6. Short-Term Debt

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

Credit Facilities
	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	6.0	$	0.7	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		78.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	84.0	$	0.7	$	675.0	$	0.0	$	1.5

(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 Dec. 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 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 Dec. 31, 2012.

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., Inc. as Program Agent. The amendment extends the maturity date to Feb. 13, 2015 and makes certain other technical changes. Please refer to Note 24 for additional information.

Amendments of TECO Energy/TECO Finance Credit Facility

On Dec. 17, 2013, TECO Energy amended and restated its $200 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility). The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues with TECO Energy as Guarantor and its wholly-owned subsidiary, TECO Finance, as Borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (ix) makes other technical changes.

The Fourth Amended and Restated Credit Agreement includes the changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. The Amendment was entered into to accommodate the acquisition of NMGI, as described in Note 22 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closes, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changing the definition of Permitted Liens as defined in the TECO Credit Facility to permit the acquisition of a significant subsidiary that carries secured debt and making other changes matching the corresponding covenant in the Bridge Facility, as described in Note 22 herein.

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the

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Borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

7. Long-Term Debt

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. At Dec. 31, 2012, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,442.2 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.

TECO Finance is a 100% owned subsidiary of TECO Energy. TECO Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no other subsidiaries of TECO Energy guarantee TECO Finance’s securities.

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2014 through 2018 and thereafter are as follows:

Long-Term Debt Maturities
As of Dec. 31, 2013 (millions)	2014		2015		2016		2017		2018		Thereafter		Total Long-Term Debt
TECO Finance	$	0.0	$	191.2	$	250.0	$	300.0	$	0.0	$	300.0	$	1,041.2
Tampa Electric		83.3		83.3		83.4		0.0		254.2		1,146.7		1,650.9
PGS		0.0		0.0		0.0		0.0		50.0		181.7		231.7
Total long-term debt maturities	$	83.3	$	274.5	$	333.4	$	300.0	$	304.2	$	1,628.4	$	2,923.8

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

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

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

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

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

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Dec. 31, 2013 to provide an opportunity to evaluate refinancing alternatives.

Redemption of TECO Energy, Inc. 6.75% Notes due 2015

On Dec. 5, 2012, TECO Energy redeemed $8.8 million of 6.75% Notes due May 15, 2015. The redemption price was equal to $1,141.86 per $1,000.00 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $1.2 million of premiums were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Statements of Cash Flows for the twelve months ended Dec. 31, 2012.

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Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002

On Oct. 1, 2012, TEC redeemed $147.1 million of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, $60.7 million of the 2002 Bonds due Oct. 1, 2013 bore interest at 5.1% and $86.4 million of the 2002 Bonds due Oct. 1, 2023 bore interest at 5.5%.

Issuance of Tampa Electric Company 2.60% Notes due 2022

On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022 (the 2022 Notes). The 2022 Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2022 Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the 2022 Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, 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 June 15, 2022, TEC may at its option redeem the 2022 Notes, in whole or in part, at 100% of the principal amount of the 2022 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of Tampa Electric Company 4.10% Notes due 2042

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the 2042 Notes). The 2042 Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 2042 Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2042 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 2042 Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 2042 Notes, in whole or in part, at 100% of the principal amount of the 2042 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Redemption of TECO Guatemala San José Project Notes

On Dec. 19, 2012, in conjunction with the closing on the sale of its equity interests in the San José Power Station, TECO Energy utilized $25.3 million of the sale proceeds to repay the San José project notes.

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At Dec. 31, 2013 and 2012, TECO Energy had the following long-term debt outstanding:

Long-Term Debt
(millions) Dec. 31,		Due	2013			2012
TECO Finance	Notes (1)(2)(3): 6.75% (effective rate of 6.9%)	2015	$	191.2		$	191.2
	4.0% (effective rate of 4.2%)	2016		250.0			250.0
	6.572% (effective rate of 7.3%)	2017		300.0			300.0
	5.15% (effective rate of 5.3%)	2020		300.0			300.0
Total long-term debt of TECO Finance				1,041.2			1,041.2
Tampa Electric	Installment contracts payable (4):
	5.65% Refunding bonds (effective rate of 5.9%)	2018		54.2			54.2
	Variable rate bonds repurchased in 2008 (5)	2020		0.0			0.0
	5.15% Refunding bonds repurchased in 2013 (effective rate of 5.4% for 2012) (6)	2025		0.0			51.6
	1.5% Term rate bonds repurchased in 2011 (7)	2030		0.0			0.0
	5.0% Refunding bonds repurchased in 2012 (8)	2034		0.0			0.0
	Notes (1): 6.25% (effective rate of 6.3%) (2)	2014-2016		250.0			250.0
	6.1% (effective rate of 6.0%)	2018		200.0			200.0
	5.4% (effective rate of 5.4%)	2021		231.7			231.7
	2.6% (effective rate of 2.7%)	2022		225.0			225.0
	6.55% (effective rate of 6.6%)	2036		250.0			250.0
	6.15% (effective rate of 6.2%)	2037		190.0			190.0
	4.1% (effective rate of 4.2%)	2042		250.0			250.0
Total long-term debt of Tampa Electric				1,650.9			1,702.5
PGS	Notes (1): 6.1% (effective rate of 7.0%)	2018		50.0			50.0
	5.4% (effective rate of 5.4%)	2021		46.7			46.7
	2.6% (effective rate of 2.7%)	2022		25.0			25.0
	6.15% (effective rate of 6.2%)	2037		60.0			60.0
	4.1% (effective rate of 4.2%)	2042		50.0			50.0
Total long-term debt of PGS				231.7			231.7
Total long-term debt of TECO Energy				2,923.8			2,975.4
Unamortized debt discount, net				(2.7	)		(2.7	)
Total carrying amount of long-term debt				2,921.1			2,972.7
Less amount due within one year				83.3			0.0
Total long-term debt			$	2,837.8		$	2,972.7

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(1) These securities are subject to redemption in whole or in part, at any time, at the option of the company.

(2) These long-term debt agreements contain various restrictive financial covenants.

(3) Guaranteed by TECO Energy.

(4) Tax-exempt securities.

(5) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.

(6) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.

(7) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.

(8) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

8. Preferred Stock

Preferred stock of TECO Energy – $1 par

10 million shares authorized, none outstanding.

Preference stock (subordinated preferred stock) of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – $100 par

1.5 million shares authorized, none outstanding.

9. Common Stock

Stock-Based Compensation

On May 5, 2010, the shareholders approved the 2010 Equity Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors.

The 2010 Plan amended the 2004 Plan to reduce the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), remove the cap on shares available for stock grant, place various limitations on the terms of awards granted under the 2010 Plan, remove the ability to make awards to consultants of the company and reapprove the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code.

The types of awards that can be granted under the 2010 Plan include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest between 0% and 150% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant.

The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.

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The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.

Assumptions	2013			2012			2011
Assumptions applicable to performance-based restricted stock
Risk-free interest rate		0.41	%		0.38	%		0.96	%
Expected lives (in years)		3			3			3
Expected stock volatility		19.04	%		20.99	%		34.61	%
Dividend yield		4.83	%		4.78	%		4.48	%

In 2013, 2012 and 2011, 0.7 million, 1.0 million and 0.8 million shares of restricted stock were granted, respectively, with weighted-average fair values per share of $17.21, $15.96 and $18.44 , respectively. The total fair market value of awards vesting during 2013, 2012 and 2011 was $3.5 million, $14.3 million and $13.4 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2013, there was $15.5 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted-average period of two years.

The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.

(millions)	2013		2012		2011
Compensation costs (1)	$	13.5	$	12.0	$	9.1
Income tax benefits (1)		5.2		4.6		3.5
Excess tax benefits (2)		0.0		2.6		1.7

(1) Reflected on the Consolidated Statements of Income.

(2) Reflected as financing activities on the Consolidated Statements of Cash Flows.

The aggregate intrinsic value of stock options exercised was $2.4 million, $0.3 million and $1.5 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively. Cash received from option exercises under all share-based payment arrangements was $6.7 million, $1.1 million and $5.0 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively. The income tax benefit realized from stock option exercises was $0.8 million, $0.1 million and $0.6 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively.

A summary of non-vested shares of restricted stock is shown as follows:

Nonvested Restricted Stock
	Time-Based Restricted					Performance-Based
	Stock (1)					Restricted Stock (1)
	Number of Shares (thousands)			Weighted - Avg. Grant Date Fair Value (per share)		Number of Shares (thousands)			Weighted- Avg. Grant Date Fair Value (per share)
Nonvested balance at Dec. 31, 2012		592		$	18.04		1,490		$	17.13
Granted		237			17.92		496			16.87
Vested		(187	)		16.91		(434	)		17.20
Forfeited		(4	)		17.99		(47	)		16.82
Nonvested balance at Dec. 31, 2013		638		$	18.33		1,505		$	17.04

(1) The weighted-average remaining contractual term of restricted stock is two years.

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Stock option transactions are summarized as follows:

Stock Options
	Number of Shares (thousands)			Weighted-Avg. Option Price (per share)		Weighted-Avg. Remaining Contractual Term (years)	Aggregate Intrinsic Value (millions)
Outstanding balance at Dec. 31, 2012		2,087		$	15.05
Granted		0			0.00
Exercised		(507	)		13.22
Cancelled		(13	)		18.87
Outstanding balance at Dec. 31, 2013 (1)		1,567		$	15.62	2	$	2.6
Exercisable at Dec. 31, 2013 (1)		1,567		$	15.62	2	$	2.6
Available for future grant at Dec. 31, 2013		2,725

(1) Option prices range from $12.01 to $19.01 per share.

As of Dec. 31, 2013, the options outstanding and exercisable are summarized below:

Range of Option Prices (per share)	Option Shares (thousands)		Weighted-Avg. Option Price (per share)		Weighted-Avg. Remaining Contractual Life
$12.01 - $13.56		331	$	13.10	1 Years
$16.21 - $19.01		1,236	$	16.29	2 Years
Total		1,567	$	15.62	2 Years

Dividend Reinvestment Plan

In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2013, 2012 and 2011, resulting in no increase in equity.

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10. Other Comprehensive Income

TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

Other Comprehensive Income
(millions)	Gross			Tax			Net
2013
Unrealized gain (loss) on cash flow hedges	$	1.0		$	(0.4	)	$	0.6
Reclassification from AOCI to net income		1.3			(0.5	)		0.8
Gain (Loss) on cash flow hedges		2.3			(0.9	)		1.4
Amortization of unrecognized benefit costs and other		23.6			(8.8	)		14.8
Recognized benefit costs due to settlement		2.6			(1.0	)		1.6
Total other comprehensive income (loss)	$	28.5		$	(10.7	)	$	17.8
2012
Unrealized (loss) gain on cash flow hedges	$	(7.4	)	$	2.8		$	(4.6	)
Reclassification from AOCI to net income		0.6			(0.2	)		0.4
(Loss) Gain on cash flow hedges		(6.8	)		2.6			(4.2	)
Amortization of unrecognized benefit costs and other (1)		(4.8	)		0.0			(4.8	)
Total other comprehensive (loss) income	$	(11.6	)	$	2.6		$	(9.0	)
2011
Unrealized gain (loss) on cash flow hedges	$	1.8		$	(0.6	)	$	1.2
Reclassification from AOCI to net income		(3.1	)		1.1			(2.0	)
(Loss) Gain on cash flow hedges		(1.3	)		0.5			(0.8	)
Amortization of unrecognized benefit costs and other		(7.9	)		3.3			(4.6	)
Recognized benefit costs due to settlement		0.9			(0.3	)		0.6
Total other comprehensive (loss) income	$	(8.3	)	$	3.5		$	(4.8	)

Accumulated Other Comprehensive Loss
(millions) As of Dec. 31,	2013			2012
Unrecognized pension losses and prior service credits (2)	$	(20.5	)	$	(32.9	)
Unrecognized other benefit gains, prior service costs and transition obligations (3)		15.1			11.1
Net unrealized losses from cash flow hedges (4)		(7.8	)		(9.2	)
Total accumulated other comprehensive loss	$	(13.2	)	$	(31.0	)

(1) Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.

(2) Net of tax benefit of $12.6 million and $20.1 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax expense of $9.1 million and $6.7 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

(4) Net of tax benefit of $4.9 million and $5.8 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

11. Earnings Per Share

In accordance with accounting standards for the calculation of EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method.

The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.

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(millions, except per share amounts)	2013			2012			2011 (1)
Basic earnings per share
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Amount allocated to nonvested participating shareholders		(0.6	)		(0.8	)		(1.3	)
Income before discontinued operations available to common shareholders - Basic	$	197.2		$	245.2		$	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
Amount allocated to nonvested participating shareholders		0.0			0.1			(0.1	)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic	($	0.1	)	($	33.2	)	$	21.7
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Amount allocated to nonvested participating shareholders		(0.6	)		(0.7	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	197.1		$	212.0		$	271.2
Average common shares outstanding - Basic		215.0			214.3			213.6
Earnings per share from continuing operations available to common shareholders - Basic	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.92		$	0.99		$	1.27
Diluted earnings per share
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Amount allocated to nonvested participating shareholders		(0.6	)		(0.8	)		(1.3	)
Income before discontinued operations available to common shareholders - Diluted	$	197.2		$	245.2		$	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
Amount allocated to nonvested participating shareholders		0.0			0.1			(0.1	)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	($	0.1	)	($	33.2	)	$	21.7
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Amount allocated to nonvested participating shareholders		(0.6	)		(0.7	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	197.1		$	212.0		$	271.2
Unadjusted average common shares outstanding - Diluted		215.0			214.3			213.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.7			1.5
Average common shares outstanding - Diluted		215.5			215.0			215.1
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.92		$	0.99		$	1.27
Anti-dilutive shares		0.0			0.4			1.7

(1) All prior periods presented reflect the classification of TECO Guatemala as discontinued operations (see Note 19).

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12. 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. In December 2010, two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim against PGS. The Court’s order is now final and not appealable. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

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

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

Environmental Protection Agency Section 114 Letter

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

Environmental Protection Agency Administrative Order

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

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Long-Term Commitments

TECO Energy has commitments under long-term leases, primarily for building space, capacity payments, office equipment and heavy equipment. Total rental expense for these leases, included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense – Mining related costs” and “Operation & maintenance other expense – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011, totaled $7.6 million, $8.1 million and $10.2 million, respectively. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:

Future Minimum Lease and Capacity Payments
(millions)	Capacity Payments		Operating Leases		Total
Year ended Dec. 31:
2014	$	14.8	$	5.0	$	19.8
2015		14.9		3.9		18.8
2016		14.6		2.6		17.2
2017		9.9		2.4		12.3
2018		10.1		2.2		12.3
Thereafter		0.0		13.4		13.4
Total future minimum payments	$	64.3	$	29.5	$	93.8

Guarantees and Letters of Credit

TECO Energy accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:

• Initial recognition and initial measurement of a liability, and/or

• Disclosure of specific details of the guarantee.

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

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

Guarantees-TECO Energy
(millions)					After (1)				Liabilities Recognized
Guarantees for the Benefit of:	2014		2015-2018		2018		Total		at Dec. 31, 2013
TECO Coal
Fuel purchase related (2)	$	0.8	$	0.7	$	4.0	$	5.5	$	1.5
Other subsidiaries
Guaranty under sale agreement (3)		0.0		5.0		0.0		5.0		5.0
Fuel sales and transportation (2)		10.0		0.0		91.8		101.8		0.1
Total	$	10.8	$	5.7	$	95.8	$	112.3	$	6.6
Letters of Credit-Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2014		2015-2018		2018		Total		at Dec. 31, 2013
Tampa Electric (2)	$	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 Dec. 31, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement. See Note 19 for additional information.

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Financial Covenants

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 Dec. 31, 2013, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants.

13. Related Parties

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million, $1.3 million and $1.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively, to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2013, 2012 and 2011. No material balances were payable as of Dec. 31, 2013 or 2012.

14. Segment Information

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

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Segment Information
(millions)	Tampa Electric		PGS		TECO Coal			TECO Guatemala			Other & Eliminations			TECO Energy
2013
Revenues - external	$	1,949.6	$	392.7	$	496.2		$	0.0		$	12.8		$	2,851.3
Sales to affiliates		0.9		0.8		0.0			0.0			(1.7	)		0.0
Total revenues		1,950.5		393.5		496.2			0.0			11.1			2,851.3
Depreciation and amortization		238.8		51.5		37.7			0.0			1.5			329.5
Total interest charges (1)		91.8		13.5		5.5			0.0			56.1			166.9
Internally allocated interest (1)		0.0		0.0		6.4			0.0			(6.4	)		0.0
Provision for income taxes		116.9		21.9		(3.6	)		0.0			(26.3	)		108.9
Net income from continuing operations		190.9		34.7		9.0			0.0			(36.8	)		197.8
Discontinued operations attributable to TECO, net of tax		0.0		0.0		0.0			0.0			(0.1	)		(0.1	)
Net income attributable to TECO Energy		190.9		34.7		9.0			0.0			(36.9	)		197.7
Total assets		6,126.9		1,021.2		316.3	(3)		0.0			(16.4	)		7,448.0
Capital expenditures		428.6		79.0		22.4			0.0			2.4			532.4
2012
Revenues - external	$	1,980.7	$	396.6	$	608.9		$	0.0		$	10.4		$	2,996.6
Sales to affiliates		0.6		2.3		0.0			0.0			(2.9	)		0.0
Total revenues		1,981.3		398.9		608.9			0.0			7.5			2,996.6
Depreciation and amortization		237.6		50.6		41.0			0.0			1.4			330.6
Total interest charges (1)		109.8		16.0		7.1			0.0			50.6			183.5
Internally allocated interest (1)		0.0		0.0		6.8			0.0			(6.8	)		0.0
Provision for income taxes		120.2		21.5		15.7			0.0			(19.6	)		137.8
Net income from continuing operations		193.1		34.1		50.2			0.0			(31.4	)		246.0
Discontinued operations attributable to TECO, net of tax		0.0		0.0		0.0			(29.3	)		(4.0	)		(33.3	)
Net income attributable to TECO Energy		193.1		34.1		50.2			(29.3	)		(35.4	)		212.7
Total assets		6,042.3		1,009.9		356.6	(3)		164.9			(238.8	)		7,334.9
Capital expenditures		361.7		97.3		36.3			8.6			1.2			505.1
2011
Revenues - external	$	2,019.3	$	450.5	$	733.0		$	0.0		$	7.1		$	3,209.9
Sales to affiliates		1.3		3.0		0.0			0.0			(4.3	)		0.0
Total revenues		2,020.6		453.5		733.0			0.0			2.8			3,209.9
Depreciation and amortization		222.1		48.4		45.3			0.0			1.4			317.2
Total interest charges (1)		121.8		17.7		6.9			0.0			51.0			197.4
Internally allocated interest (1)		0.0		0.0		6.7			0.0			(6.7	)		0.0
Provision for income taxes		124.8		20.6		15.4			0.0			(18.1	)		142.7
Net income from continuing operations		202.7		32.6		51.5			0.0			(36.0	)		250.8
Discontinued operations attributable to TECO, net of tax (2)		0.0		0.0		0.0			22.4			(0.6	)		21.8
Net income attributable to TECO Energy		202.7		32.6		51.5			22.4			(36.6	)		272.6
Goodwill		0.0		0.0		0.0			55.4			0.0			55.4
Total assets		5,925.9		932.0		385.2	(3)		304.1			(240.0	)		7,307.2
Capital expenditures		314.9		71.9		56.6			7.2			3.5			454.1

(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 2013 and 2012 were at a pretax rate of 6.00%, and for 2011 were at a pretax rate of 6.25%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. See Note 19.

(3) The carrying value of mineral rights as of Dec. 31, 2013, 2012 and 2011 was $12.1 million, $13.4 million and $15.0 million, respectively.

Tampa Electric provides retail electric utility services to almost 700,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for almost 350,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

TECO Coal, through its wholly-owned subsidiaries, owns mineral rights and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia.

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15. Asset Retirement Obligations

TECO Energy accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

TECO Energy has recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2013 and 2012, these obligations totaled $23.8 million and $23.6 million, respectively.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31, 2013 and 2012, these obligations totaled $4.8 million and $5.0 million, respectively.

For the years ended Dec. 31, 2013, 2012 and 2011, TECO Energy recognized $1.4 million annually of accretion expense associated with AROs in “Depreciation and amortization” on the Consolidated Statements of Income. For the year ended Dec. 31, 2013, $1.4 million of liabilities settled resulted primarily from reclamation costs related to mine closures. For the year ended Dec. 31, 2012, $29.1 million of liabilities settled resulted primarily from asbestos abatement and other dismantling at the generating stations at Tampa Electric.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:
	Dec. 31,
(millions)	2013			2012
Beginning balance	$	28.6		$	53.8
Additional liabilities		0.1			0.7
Liabilities settled		(1.4	)		(29.1	)
Accretion expense		1.4			1.4
Revisions to estimated cash flows		(0.3	)		0.0
Other (1)		0.2			1.8
Ending balance	$	28.6		$	28.6

(1) Accretion recorded as a deferred regulatory asset.

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16. 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. 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 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 (see Note 17). 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).

The 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 Dec. 31, 2013, all of the company’s physical contracts qualify for the NPNS exception.

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

Total Derivatives
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.7	$	0.0
Long-term assets		0.3		0.2
Total assets	$	10.0	$	0.2
Current liabilities	$	0.1	$	14.6
Long-term liabilities		0.2		0.6
Total liabilities	$	0.3	$	15.2

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

Offsetting of Derivative Assets and Liabilities (millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Dec. 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

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

Diesel Fuel Derivatives
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	0.2	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.2	$	0.0
Current liabilities	$	0.1	$	0.5
Long-term liabilities		0.0		0.4
Total liabilities	$	0.1	$	0.9

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

Natural Gas Derivatives (1)
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.5	$	0.0
Long-term assets		0.3		0.2
Total assets	$	9.8	$	0.2
Current liabilities	$	0.0	$	14.1
Long-term liabilities		0.2		0.2
Total liabilities	$	0.2	$	14.3

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

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at Dec. 31, 2013 is a net loss of $7.8 million after tax and accumulated amortization. This compares to a net loss of $9.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

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

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

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

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

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

Based on the fair value of the instruments at Dec. 31, 2013, net pretax gains of $9.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31:

	Amount of Gain/(Loss) on Derivatives Recognized in			Location of Gain/(Loss) Reclassified From AOCI	Gain/(Loss) Reclassified From
(millions)	OCI			Into Income	AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)		Effective Portion (1)
2013
Interest rate contracts:	$	0.0		Interest expense	($	0.9	)
Commodity contracts:
Diesel fuel derivatives		0.6		Mining related costs		0.1
Total	$	0.6			($	0.8	)
2012
Interest rate contracts:	($	4.9	)	Interest expense	($	0.8	)
Commodity contracts:
Diesel fuel derivatives		0.3		Mining related costs		0.4
Total	($	4.6	)		($	0.4	)
2011
Interest rate contracts:	$	0.0		Interest expense	($	0.7	)
Commodity contracts:
Diesel fuel derivatives		1.2		Mining related costs		2.7
Total	$	1.2			$	2.0

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

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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 years ended Dec. 31, 2013, 2012 and 2011, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the years ended Dec. 31:

(millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income (1)
2013
Interest rate swaps	$	0.0		$	0.0		($	0.9	)
Diesel fuel derivatives		0.1			0.6			0.1
Total	$	0.1		$	0.6		($	0.8	)
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.8	)
Diesel fuel derivatives		(0.9	)		0.3			0.4
Total	($	0.9	)	($	4.6	)	($	0.4	)
2011
Interest rate swaps	$	0.0		$	0.0		($	0.7	)
Diesel fuel derivatives		(0.3	)		1.2			2.7
Total	($	0.3	)	$	1.2		$	2.0

(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, 2015 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		2.0		0.0		36.9
2015		0.0		0.0		0.0		7.6
Total		0.0		2.0		0.0		44.5

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 Dec. 31, 2013, 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 Dec. 31, 2013, 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

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credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.

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

Contingent Features
(millions)	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	0.1	)	($	0.1	)	$	0.0

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

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

Natural gas and diesel fuel swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 16).

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 Dec. 31, 2013, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were asset positions. There were no Level 3 assets or liabilities during the 2013 or 2012 fiscal years.

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18. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.1 million, $75.8 million and $81.2 million, under these PPAs for the three years ended Dec. 31, 2013, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $46.6 million and $34.4 million for the two years ended Dec. 31, 2012 and 2011, respectively. This PPA expired on Dec. 31, 2012.

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

19. Discontinued Operations

On Aug. 7, 2012, TECO Energy received an offer from Renewable Energy Investments Guatemala Limited (REIN), a wholly-owned subsidiary of Sur Eléctrica Holding Limited (SUR), to purchase the independent power projects in Guatemala and certain affiliated Guatemala companies. SUR and REIN are international business companies organized under the laws of the Commonwealth of the Bahamas. On Sept. 27, 2012, an indirect wholly-owned subsidiary of TECO Energy, Inc., TECO Guatemala Holdings II, LLC (TGH), entered into an equity purchase agreement with SUR, and two equity purchase agreements with REIN (the three equity purchase agreements are collectively referred to herein as the “PAs”). Pursuant to the PA with SUR, TGH agreed to sell all of its ownership interests in TPS Guatemala One, Ltd. (TPS GO) for $12.5 million, and pursuant to the PAs with REIN, it agreed to sell all of its ownership interests in (i) TPS San José International, Inc. (TPS SJI) for $213.5 million and (ii) TECO Guatemala Services, Ltd. (TGS) for $1.5 million (TPS GO, TPS SJI and TGS are collectively referred to herein as the Disposal Group). The companies in the Disposal Group are the ultimate parent companies of TCAE, CGESJ, TEMSA, and TPS Operaciones de Guatemala, Limitada (TPSO), the owner of certain local real estate assets and the employer of the local employees. The total purchase price for the Disposal Group under the PAs was $227.5 million.

The sale of TPS GO, which owns 96.06% of TCAE, closed on Sept. 27, 2012. An affiliate of the party that controlled the remaining interest in TCAE (the “noncontrolling interest holder”) held certain contractual rights with respect to TEMSA and CGESJ, including a right of first offer. The noncontrolling interest holder was also granted the opportunity to purchase TGS since the operations of TPSO are integral to the operations of TEMSA and CGESJ. The noncontrolling interest holder exercised the right of first offer for TPS SJI and elected to purchase TGS by executing PAs similar to the PAs with REIN on Oct. 17, 2012 and Oct. 26, 2012, respectively. The sales of TPS SJI and TGS to the noncontrolling interest holder closed on Dec. 19, 2012.

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As a result of the PAs, the TECO Guatemala segment is accounted for as a discontinued operation at Dec. 31, 2013. The following table provides selected components of discontinued operations:

Components of income from discontinued operations attributable to TECO Energy	Twelve months ended Dec. 31,
(millions)	2013			2012			2011
Revenues	$	0.0		$	114.2		$	133.5
(Loss) income from operations		(0.2	)		27.7			33.7
Loss on assets sold, including transaction costs		0.0			(38.3	)		(0.4	)
Income (loss) from discontinued operations		(0.2	)		(10.6	)		33.3
Provision (benefit) for income taxes		(0.1	)		22.4			11.2
Income (loss) from discontinued operations, net		(0.1	)		(33.0	)		22.1
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.3			0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8

The provision for income taxes line item includes an after-tax charge of $22.9 million in 2012 associated with foreign tax credits. The 2012 charge is a result of the sales of the Disposal Group which eliminate future foreign source income that would be required to utilize these credits.

The PAs contain customary representations, warranties and covenants. The PAs also contain indemnification provisions subject to specified limitations as to time and amount, including an indemnification provision related to an uncertain tax position related to TCAE.

On Dec. 19, 2013, the ICSID tribunal hearing TGH’s arbitration claim against the Republic of Guatemala under DR-CAFTA issued an award in the case. The ICSID tribunal unanimously found in favor of TGH and awarded damages of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the prime rate plus 2%. In addition, the tribunal ruled that Guatemala must reimburse TGH for approximately $7.5 million of the costs it incurred in pursuing the arbitration.

The ICSID tribunal found that Guatemala breached its treaty obligation to grant TGH fair and equitable treatment under the terms of the DR-CAFTA, thereby causing damages to TGH for which it is entitled to compensation. In sum, the tribunal found that Guatemala’s repudiation of fundamental regulatory principles applying to the tariff review process was arbitrary and breached elementary standards of due process in administrative matters.

Each party has 120 days from the date of the award to seek annulment of the decision. Pending the outcome of a potential annulment filing, results in 2013 do not reflect any benefit of this decision.

20. Goodwill and Asset Impairments

Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill with an indefinite life is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. The goodwill formerly on the company’s balance sheet related to the TECO Guatemala segment and arose from the purchase of multiple entities as a result of the company’s investments in the Alborada (held by TPS GO) and San José (held by TPS SJI) power plants. Since these reporting units were one level below the operating segment level, discrete cash flow information was available, and management regularly reviewed their operating results separately, these were the reporting unit level at which potential impairment was tested.

Prior to the sales in 2012 (see Note 19), goodwill balances for the TPS GO and TPS SJI reporting units were written down to their implied fair value calculated using the offers from SUR and REIN. Although these were binding quoted prices, the fair value measurements were considered Level 2 measurements since the market was not active as defined by accounting standards (i.e. transactions for these assets were too infrequent to provide pricing information on an ongoing basis). Prior to receiving the offers from REIN and SUR, the fair values of TPS GO’s and TPS SJI’s goodwill amounts were calculated using the discounted cash flows appropriate for the business model of each reporting unit. Discounted cash flows were formerly the best estimates of fair value of the reporting units, since neither a sale nor a similar transaction was readily observed in the marketplace for many years due to an inactive market.

The changes in the carrying amount of goodwill for the year ended Dec. 31, 2012 are represented in the following table:

(millions)	TPS GO			TPS SJI			Total
Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4
Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)
Goodwill written off upon sale, pretax		0.0			(40.2	)		(40.2	)
Balance as of Dec. 31, 2012	$	0.0		$	0.0		$	0.0

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The Impairment losses, pretax and Goodwill written off upon sale, pretax amounts from the table above are recorded in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012.

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.

Prior to the sale of TGS, the company recorded a long-lived asset pretax impairment charge of $2.0 million. This amount is recorded in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012. The fair value was calculated using the offer from REIN. Although it was a binding quoted price, the fair value measurement was considered a Level 2 measurement since the market was not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis).

Additionally, in both 2012 and 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in each fourth quarter on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that are recoverable; therefore, no impairment charge was deemed necessary. Additionally, the company performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable.

21. Dispositions

Sale of San José and Alborada

On Sept. 27, 2012, TECO Guatemala entered into an agreement to sell all of the equity interests in the Alborada and San José power stations and their related facilities and operations in Guatemala for a total purchase price of $227.5 million in cash. The TECO Guatemala segment was accounted for as discontinued operations beginning in the third quarter of 2012. For more information regarding the sale, see Note 19.

While TECO Energy and its subsidiaries will no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala in October 2010 under the DR – CAFTA. For more information on the claim, see Note 19.

Net proceeds from the sale of all Guatemalan operations, after estimated transaction-related costs and the $25.3 million repayment of the San José power station project debt, were approximately $197.0 million. The sale resulted in an after-tax book loss and an after-tax charge associated with foreign tax credits of $28.6 million and $22.9 million, respectively.

22. Pending Acquisition of New Mexico Gas Company

Stock Purchase Agreement

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

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

As previously reported, the company must obtain regulatory approvals from the NMPRC prior to consummating the pending acquisition of NMGC. On Jan. 10, 2014 a meeting was held with the joint applicants, hearing examiner, the NMPRC staff, and intervenors to establish an updated schedule. Based on this schedule, Staff and intervenor testimony is expected to occur on Feb. 28, with hearings to follow on March 24 – 28. The date for a final decision is yet to be determined. The company has indicated that the closing is likely to occur in the third quarter of 2014.

The SPA contains customary representations and warranties of the parties, and covenants to, among other things, cooperate on seeking necessary regulatory approvals and access to information. NMGI also agreed to conduct its business and the business of its subsidiary, NMGC, in the ordinary course until the acquisition is consummated and has agreed to cooperate with the company’s efforts to obtain permanent financing. The acquisition is not subject to any financing condition and the company has entered into a

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credit agreement to provide bridge financing, as described in the section titled TECO Finance Bridge Facility below. The parties have agreed to indemnify each other for breaches of representations, warranties and covenants. Subject to certain exceptions, CES’s aggregate liability with respect to such indemnification obligations is capped at $30 million (subject to a $9.25 million deductible), which will be placed initially into an escrow account at closing to be available to fund indemnification claims.

The SPA contains certain termination rights for CES and the company, including, among others, the right to terminate if the acquisition is not completed by May 25, 2014 (subject to up to a four month extension under certain circumstances related to obtaining required regulatory approvals which, if not obtained, would permit each party to terminate the SPA without paying a termination fee).

TECO Finance Bridge Facility

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

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

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

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

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

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

TECO Energy Credit Agreement to be Assigned to and Assumed by NMGC

In connection with the pending Acquisition, on Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility, pursuant to which it is the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy has no rights or obligations to borrow under the NMGC Credit Agreement, which it has entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, upon such closing, TECO Energy will designate NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder and Release Agreement duly executed by TECO Energy and NMGC, whereupon and upon the satisfaction of the other conditions precedent set forth in the NMGC Credit Agreement, (i) NMGC shall automatically become the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy shall cease to be a party to the NMGC Credit Agreement and shall have no further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) will allow NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, will allow NMGC to borrow funds at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) will allow NMGC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) will allow NMGC to request the lenders to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility.

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23. Quarterly Data (unaudited)

Financial data by quarter is as follows:

(millions, except per share amounts) Quarter ended	Dec. 31		Sept. 30		June 30		March 31
2013
Revenues	$	688.4	$	765.9	$	735.9	$	661.1
Income from operations		99.6		140.5		119.5		104.1
Net income from continuing operations		42.1		62.9		51.6		41.2
Net income attributable to TECO Energy		42.0		62.8		51.4		41.5
EPS - Basic
From continuing operations	$	0.20	$	0.29	$	0.24	$	0.19
Attributable to TECO Energy		0.20		0.29		0.24		0.19
EPS - Diluted
From continuing operations	$	0.20	$	0.29	$	0.24	$	0.19
Attributable to TECO Energy		0.20		0.29		0.24		0.19
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220
Quarter ended	Dec. 31		Sept. 30		June 30		March 31
2012
Revenues (1)	$	688.4	$	858.6	$	752.5	$	697.1
Income from operations (1)		109.5		183.1		149.1		114.8
Net income from continuing operations (1)		45.6		90.2		65.6		44.6
Net income attributable to TECO Energy		45.1		44.0		73.1		50.5
EPS - Basic
From continuing operations (1)	$	0.21	$	0.42	$	0.30	$	0.21
Attributable to TECO Energy		0.21		0.20		0.34		0.24
EPS - Diluted
From continuing operations (1)	$	0.21	$	0.42	$	0.30	$	0.20
Attributable to TECO Energy		0.21		0.20		0.34		0.23
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220

(1) Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

24. Subsequent Events

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.

123

TAMPA ELECTRIC COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page No.
Report of Independent Registered Certified Public Accounting Firm		125
Consolidated Balance Sheets, Dec. 31, 2013 and 2012		126-127
Consolidated Statements of Income and Comprehensive Income for the years ended Dec. 31, 2013, 2012 and 2011		128
Consolidated Statements of Cash Flows for the years ended Dec. 31, 2013, 2012 and 2011		129
Consolidated Statements of Retained Earnings for the years ended Dec. 31, 2013, 2012 and 2011		130
Consolidated Statements of Capitalization, Dec. 31, 2013 and 2012		130-132
Notes to Consolidated Financial Statements		133-158
Management’s Report on Internal Control Over Financial Reporting		159
Financial Statement Schedule II – Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2013, 2012 and 2011		164
Signatures		166

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.

124

Report of Independent Registered Certified Public Accounting Firm

To the Board of Directors and Shareholder of Tampa Electric Company:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

February 28, 2014

125

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets

Assets (millions)	Dec. 31, 2013			Dec. 31, 2012
Property, plant and equipment
Utility plant in service
Electric	$	6,934.0		$	6,654.5
Gas		1,249.5			1,171.9
Construction work in progress		385.3			335.0
Utility plant in service, at original costs		8,568.8			8,161.4
Accumulated depreciation		(2,562.6	)		(2,373.6	)
		6,006.2			5,787.8
Other property		8.3			7.3
Total property, plant and equipment, net		6,014.5			5,795.1
Current assets
Cash and cash equivalents		9.8			45.2
Receivables, less allowance for uncollectibles of $2.0 and $1.5 at Dec. 31, 2013 and 2012, respectively		227.6			213.8
Inventories, at average cost
Fuel		93.7			89.1
Materials and supplies		76.8			72.4
Regulatory assets		34.3			70.3
Derivative assets		9.5			0.0
Taxes receivable		54.9			22.1
Deferred income taxes		29.4			20.0
Prepayments and other current assets		12.5			11.5
Total current assets		548.5			544.4
Deferred debits
Unamortized debt expense		14.8			16.1
Regulatory assets		293.1			382.6
Derivative assets		0.3			0.2
Other		4.6			6.2
Total deferred debits		312.8			405.1
Total assets	$	6,875.8		$	6,744.6

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

126

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets - continued

Liabilities and Capital (millions)	Dec. 31, 2013			Dec. 31, 2012
Capitalization
Common stock	$	2,030.4		$	1,970.4
Accumulated other comprehensive loss		(7.8	)		(8.7	)
Retained earnings		308.1			304.6
Total capital		2,330.7			2,266.3
Long-term debt, less amount due within one year		1,797.5			1,932.6
Total capital		4,128.2			4,198.9
Current liabilities
Long-term debt due within one year		83.3			0.0
Notes payable		84.0			0.0
Accounts payable		226.0			188.6
Customer deposits		164.5			163.0
Regulatory liabilities		85.8			105.6
Derivative liabilities		0.0			14.1
Interest accrued		16.4			17.3
Taxes accrued		12.2			13.7
Other		12.0			11.8
Total current liabilities		684.2			514.1
Deferred credits
Deferred income taxes		1,114.3			980.9
Investment tax credits		9.4			9.7
Derivative liabilities		0.2			0.2
Regulatory liabilities		631.4			631.4
Other		308.1			409.4
Total deferred credits		2,063.4			2,031.6
Commitments and Contingencies (see Note 10)
Total liabilities and capital	$	6,875.8		$	6,744.6

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

127

TAMPA ELECTRIC COMPANY

Consolidated Statements of Income and Comprehensive Income

(millions) For the years ended Dec. 31,	2013			2012			2011
Revenues
Electric (includes franchise fees and gross receipts taxes of $88.0 in 2013, $91.1 in 2012 and $85.6 in 2011)	$	1,950.1		$	1,981.0		$	2,020.1
Gas (includes franchise fees and gross receipts taxes of $20.5 in 2013, $20.4 in 2012 and $23.7 in 2011)		392.7			397.0			450.5
Total revenues		2,342.8			2,378.0			2,470.6
Expenses
Regulated operations & maintenance
Fuel		680.2			694.7			731.4
Purchased power		64.7			105.3			125.9
Cost of natural gas sold		142.6			155.8			210.4
Other		523.6			462.0			436.4
Depreciation and amortization		290.3			288.2			270.5
Taxes, other than income		183.1			184.0			179.7
Total expenses		1,884.5			1,890.0			1,954.3
Income from operations		458.3			488.0			516.3
Other income
Allowance for other funds used during construction		6.3			2.6			1.0
Other income, net		5.1			4.1			2.9
Total other income		11.4			6.7			3.9
Interest charges
Interest on long-term debt		105.0			119.6			128.6
Other interest		3.9			7.7			11.5
Allowance for borrowed funds used during construction		(3.6	)		(1.5	)		(0.6	)
Total interest charges		105.3			125.8			139.5
Income before provision for income taxes		364.4			368.9			380.7
Provision for income taxes		138.8			141.7			145.4
Net income		225.6			227.2			235.3
Other comprehensive income, net of tax
Net unrealized (loss) gain on cash flow hedges		0.9			(4.1	)		0.7
Total other comprehensive (loss) income, net of tax		0.9			(4.1	)		0.7
Comprehensive income	$	226.5		$	223.1		$	236.0

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

128

TAMPA ELECTRIC COMPANY

Consolidated Statements of Cash Flows

(millions) For the years ended Dec. 31,	2013			2012			2011
Cash flows from operating activities
Net income	$	225.6		$	227.2		$	235.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		290.3			288.2			270.5
Deferred income taxes		118.4			155.9			173.6
Investment tax credits, net		(0.3	)		(0.3	)		(0.4	)
Allowance for other funds used during construction		(6.3	)		(2.6	)		(1.0	)
Deferred recovery clauses		(6.2	)		(8.9	)		(9.0	)
Receivables, less allowance for uncollectibles		(13.8	)		1.6			47.8
Inventories		(9.0	)		4.1			12.6
Prepayments		(1.0	)		(1.0	)		(0.5	)
Taxes accrued		(34.3	)		(5.7	)		7.9
Interest accrued		(0.9	)		(8.3	)		1.0
Accounts payable		34.8			12.4			(42.2	)
Gain on sale of assets, pretax		0.0			(0.2	)		(0.3	)
Other		(1.8	)		5.2			29.4
Cash flows from operating activities		595.5			667.6			724.7
Cash flows from investing activities
Capital expenditures		(507.6	)		(459.0	)		(386.8	)
Allowance for other funds used during construction		6.3			2.6			1.0
Net proceeds from sale of assets		0.1			0.3			2.8
Cash flows used in investing activities		(501.2	)		(456.1	)		(383.0	)
Cash flows from financing activities
Common stock		60.0			118.0			0.0
Proceeds from long-term debt issuance		0.0			538.1			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(51.6	)		(608.0	)		(78.8	)
Net increase (decrease) in short-term debt		84.0			0.0			(12.0	)
Dividends		(222.1	)		(228.3	)		(240.7	)
Cash flows used in financing activities		(129.7	)		(180.2	)		(331.5	)
Net increase (decrease) in cash and cash equivalents		(35.4	)		31.3			10.2
Cash and cash equivalents at beginning of the year		45.2			13.9			3.7
Cash and cash equivalents at end of the year	$	9.8		$	45.2		$	13.9
Supplemental disclosure of cash flow information
Cash paid (received) during the year for:
Interest	$	102.4		$	128.1		$	129.0
Income taxes	$	56.4		$	(9.7	)	$	(31.1	)

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

129

TAMPA ELECTRIC COMPANY

Consolidated Statements of Retained Earnings

(millions) For the years ended Dec. 31,	2013		2012		2011
Balance, beginning of year	$	304.6	$	305.7	$	311.1
Add: Net income		225.6		227.2		235.3
		530.2		532.9		546.4
Deduct: Cash dividends on capital stock - common		222.1		228.3		240.7
Balance, end of year	$	308.1	$	304.6	$	305.7

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

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization

			Capital Stock Outstanding				Cash Dividends
	Current		Dec. 31,				Paid (1)
(millions, except share amounts)	Redemption Price		Shares		Amount		Per Share		Amount
Common stock - without par value
25 million shares authorized
2013 (3)(4)		N/A		10	$	2,030.4		(2)	$	222.1
2012 (3)(4)		N/A		10	$	1,970.4		(2)	$	228.3
Preferred stock - $100 par value
1.5 million shares authorized, none outstanding.
Preferred stock - no par
2.5 million shares authorized, none outstanding.
Preference stock - no par
2.5 million shares authorized, none outstanding.

(1) Quarterly dividends paid on Feb. 28, May 28, Aug. 28 and Nov. 27 during 2013.

Quarterly dividends paid on Feb. 28, May 29, Aug. 28 and Nov. 28 during 2012.

(2) Not meaningful.

(3) No issue expense.

(4) TECO Energy made equity contributions to TEC of $60.0 million in 2013 and $118.0 million in 2012.

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

130

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization – continued

At Dec. 31, 2013 and 2012, TEC had the following long-term debt outstanding:

Long-Term Debt (millions) Dec. 31,		Due	2013			2012
Tampa Electric	Installment contracts payable (1):
	5.65% Refunding bonds (effective rate of 5.9%)	2018	$	54.2		$	54.2
	Variable rate bonds repurchased in 2008 (2)	2020		0.0			0.0
	5.15% Refunding bonds repurchased in 2013 (effective rate of 5.4% for 2012) (3)	2025		0.0			51.6
	1.5% Term rate bonds repurchased in 2011 (4)	2030		0.0			0.0
	5.0% Refunding bonds repurchased in 2012 (5)	2034		0.0			0.0
	Notes (6): 6.25% (effective rate of 6.3%) (7)	2014-2016		250.0			250.0
	6.1% (effective rate of 6.0%)	2018		200.0			200.0
	5.4% (effective rate of 5.4%)	2021		231.7			231.7
	2.6% (effective rate of 2.7%)	2022		225.0			225.0
	6.55% (effective rate of 6.6%)	2036		250.0			250.0
	6.15% (effective rate of 6.2%)	2037		190.0			190.0
	4.1% (effective rate of 4.2%)	2042		250.0			250.0
Total long-term debt of Tampa Electric				1,650.9			1,702.5
PGS	Notes (6): 6.1% (effective rate of 7.0%)	2018		50.0			50.0
	5.4% (effective rate of 5.4%)	2021		46.7			46.7
	2.6% (effective rate of 2.7%)	2022		25.0			25.0
	6.15% (effective rate of 6.2%)	2037		60.0			60.0
	4.1% (effective rate of 4.2%)	2042		50.0			50.0
Total long-term debt of PGS				231.7			231.7
Total long-term debt of Tampa Electric Company				1,882.6			1,934.2
Unamortized debt discount, net				(1.8	)		(1.6	)
Total carrying amount of long-term debt				1,880.8			1,932.6
Less amount due within one year				83.3			0.0
Total long-term debt			$	1,797.5		$	1,932.6

(1) Tax-exempt securities.

(2) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.

(3) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.

(4) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.

(5) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

(6) These securities are subject to redemption in whole or in part, at any time, at the option of the company.

(7) These long-term debt agreements contain various restrictive covenants.

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

131

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization – continued

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. At Dec. 31, 2012, total long-term debt had a carrying amount of $1,932.6 million and an estimated fair market value of $2,271.9 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.

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Gross maturities and annual sinking fund requirements of long-term debt for the years 2014 through 2018 and thereafter are as follows:

Long-Term Debt Maturities
As of Dec. 31, 2013 (millions)	2014		2015		2016		2017		2018		Thereafter		Total Long-Term Debt
Tampa Electric	$	83.3	$	83.3	$	83.4	$	0.0	$	254.2	$	1,146.7	$	1,650.9
PGS		0.0		0.0		0.0		0.0		50.0		181.7		231.7
Total long-term debt maturities	$	83.3	$	83.3	$	83.4	$	0.0	$	304.2	$	1,328.4	$	1,882.6

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

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

The significant accounting policies are as follows:

Basis of Accounting

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with GAAP in all material respects.

The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance.

TEC’s retail and wholesale businesses are regulated by the FPSC and related FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Principles of Consolidation

TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.

For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).

Planned Major Maintenance

Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $284.2 million, $275.1 million and $263.7 million, respectively.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 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, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows.

133

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

Revenue Recognition

TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TEC is 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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.

Reclassifications

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

134

2. New Accounting Pronouncements

Comprehensive Income

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

Offsetting Assets and Liabilities

In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. TEC has adopted this guidance as required. It had no effect on TEC’s results of operations, financial position or cash flows.

3. Regulatory

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

Base Rates-Tampa Electric

Tampa Electric’s results for the first ten months of 2013, and all of 2012 and 2011, reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

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

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

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

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

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Storm Damage Cost Recovery

Prior to the above mentioned stipulation and settlement agreement, 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

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were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Tampa Electric’s storm reserve was $56.1 million and $50.4 million as of Dec. 31, 2013 and 2012, respectively. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to the level as of Oct. 31, 2013.

Regulatory Assets and Liabilities

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

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

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

Regulatory Assets and Liabilities
(millions)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.4	$	67.2
Other:
Cost-recovery clauses		6.1		42.9
Postretirement benefit asset		182.7		276.1
Deferred bond refinancing costs (2)		8.0		9.2
Environmental remediation		51.4		46.9
Competitive rate adjustment		4.1		4.1
Other		7.7		6.5
Total other regulatory assets		260.0		385.7
Total regulatory assets		327.4		452.9
Less: Current portion		34.3		70.3
Long-term regulatory assets	$	293.1	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	9.8	$	14.6
Other:
Cost-recovery clauses		54.5		73.9
Transmission and delivery storm reserve		56.1		50.4
Deferred gain on property sales (3)		2.0		3.4
Provision for stipulation and other		0.8		1.0
Accumulated reserve - cost of removal		594.0		593.7
Total other regulatory liabilities		707.4		722.4
Total regulatory liabilities		717.2		737.0
Less: Current portion		85.8		105.6
Long-term regulatory liabilities	$	631.4	$	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.

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

Regulatory assets
(millions)	Dec. 31, 2013		Dec. 31, 2012
Clause recoverable (1)	$	10.2	$	47.0
Components of rate base (2)		185.6		279.1
Regulatory tax assets (3)		67.4		67.2
Capital structure and other (3)		64.2		59.6
Total	$	327.4	$	452.9

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

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

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

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. For the three years presented, TEC’s effective tax rate differs from the statutory rate principally due to state income taxes, domestic production deduction and AFUDC equity benefit. The decrease in the 2013 effective tax rate compared to 2012 is principally due to equity portion of AFUDC.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)
(millions) For the year ending Dec. 31,	2013			2012			2011
Current income taxes
Federal	$	19.4		$	(19.5	)	$	(30.7	)
State		1.3			5.6			2.9
Deferred income taxes
Federal		99.8			141.2			155.6
State		18.6			14.7			18.0
Amortization of investment tax credits		(0.3	)		(0.3	)		(0.4	)
Total income tax expense	$	138.8		$	141.7		$	145.4

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:

Effective Income Tax Rate
(millions) For the years ended Dec. 31,	2013			2012			2011
Income tax expense at the federal statutory rate of 35%	$	127.5		$	129.1		$	133.2
Increase (decrease) due to
State income tax, net of federal income tax		13.0			13.2			13.6
Equity portion of AFUDC		(2.2	)		(0.9	)		(0.4	)
Domestic production deduction		(0.6	)		(0.4	)		(1.5	)
Other		1.1			0.7			0.5
Total income tax expense on consolidated statements of income	$	138.8		$	141.7		$	145.4
Income tax expense as a percent of income from continuing operations, before income taxes		38.1	%		38.4	%		38.2	%

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Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

Deferred Income Taxes
(millions) As of Dec. 31,	2013			2012
Deferred tax liabilities (1)
Property related	$	1,166.4		$	1,016.2
Deferred fuel		1.6			11.3
Pension and postretirement benefits		70.5			106.6
Pension		43.2			36.7
Other		0.0			22.2
Total deferred tax liabilities		1,281.7			1,193.0
Deferred tax assets (1)
Medical benefits		50.9			49.0
Insurance reserves		29.1			31.1
Investment tax credits		5.3			5.5
Hedging activities		4.9			5.5
Pension and postretirement benefits		70.5			106.6
Unbilled revenue		12.1			14.8
Capitalized energy conservation assistance costs		19.6			19.6
Other		4.4			0.0
Total deferred tax assets		196.8			232.1
Total deferred tax liability, net		1,084.9			960.9
Less: Current portion of deferred tax asset		(29.4	)		(20.0	)
Long-term portion of deferred tax liability, net	$	1,114.3		$	980.9

(1) Certain property related assets and liabilities have been netted.

TEC accounts for uncertain tax positions as required by FASB accounting guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, TEC may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

As of Dec. 31, 2013 and 2012, TEC did not have a liability for unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2014. As of Dec. 31, 2013, TEC does not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

The IRS concluded its examination of federal income tax returns for the year 2012 in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and onward. The federal income tax return for calendar year 2013 is part of the IRS’s Compliance Assurance Program. As a result, the IRS audit of such return is expected to be completed in 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 onward. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

5. Employee Postretirement Benefits

Pension Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy, including a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

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WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In July 2012, the President signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under MAP-21.

The qualified pension plan’s actuarial value of assets, including credit balance, was 96.7% of the Pension Protection Act funded target as of Jan. 1, 2013 and is estimated at 98.2% of the Pension Protection Act funded target as of Jan. 1, 2014.

Amounts disclosed for pension benefits also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. This amount was trued up in 2012. TEC is amortizing the regulatory asset over the remaining average service life of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. Prior to this, the company received subsidy payments under Medicare Part D for its post-65 retiree prescription drug plan.

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Obligations and Funded Status

TEC recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in TECO Energy’s Consolidated Balance Sheets for 2013 and 2012.

TECO Energy	Pension Benefits						Other Benefits
Obligations and Funded Status
(millions)	2013			2012			2013			2012
Change in benefit obligation
Net benefit obligation at beginning of year	$	715.0		$	646.4		$	230.3		$	216.5
Service cost		18.2			17.0			2.5			2.4
Interest cost		28.9			30.1			9.3			10.1
Plan participants’ contributions		0.0			0.0			2.9			3.7
Plan amendments		0.0			0.0			0.0			(5.2	)
Actuarial loss (gain)		(50.4	)		54.7			(22.1	)		16.3
Gross benefits paid		(43.1	)		(33.2	)		(15.0	)		(14.5	)
Settlements		(2.6	)		0.0			0.0			0.0
Federal subsidy on benefits paid		n/a			n/a			0.2			1.0
Net benefit obligation at end of year	$	666.0		$	715.0		$	208.1		$	230.3
Change in plan assets
Fair value of plan assets at beginning of year	$	529.1		$	467.6		$	0.0		$	0.0
Actual return on plan assets		63.7			57.9			0.0			0.0
Employer contributions		45.9			36.8			11.9			9.8
Plan participants’ contributions		0.0			0.0			2.9			3.7
Settlements		(2.6	)		0.0			0.0			0.0
Gross benefits paid		(43.1	)		(33.2	)		(14.8	)		(13.5	)
Fair value of plan assets at end of year	$	593.0		$	529.1		$	0.0		$	0.0
Funded status
Fair value of plan assets (1)	$	593.0		$	529.1		$	0.0		$	0.0
Less: Benefit obligation (PBO/APBO)		666.0			715.0			208.1			230.3
Funded status at end of year		(73.0	)		(185.9	)		(208.1	)		(230.3	)
Unrecognized net actuarial loss		173.1			270.3			19.7			42.7
Unrecognized prior service (benefit) cost		(0.4	)		(0.7	)		(0.7	)		(1.0	)
Unrecognized net transition obligation		0.0			0.0			0.0			0.0
Net amount required to be recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)
Amounts recognized in balance sheet
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(3.3	)		(5.3	)		(13.3	)		(13.1	)
Deferred credits and other liabilities		(69.7	)		(180.6	)		(194.8	)		(217.2	)
Accumulated other comprehensive loss (income), pretax		33.1			53.1			(24.2	)		(17.9	)
Net amount recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

Tampa Electric Company	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2013			2012			2013			2012
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(0.9	)		(0.9	)		(10.8	)		(10.6	)
Deferred credits and other liabilities		(50.1	)		(139.8	)		(158.3	)		(174.2	)
	$	88.6		$	75.8		$	(125.9	)	$	(125.2	)

The accumulated benefit obligation for TECO Energy Consolidated defined benefit pension plans was $624.1 million at Dec. 31, 2013 and $664.7 million at Dec. 31, 2012. The projected benefit obligation for the other postretirement benefits plan was $208.1 million at Dec. 31, 2013 and $230.3 million at Dec. 31, 2012.

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Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2013			2012			2013			2012
Discount rate		5.118	%		4.196	%		5.096	%		4.180	%
Rate of compensation increase-weighted average		3.73	%		3.76	%		3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			7.25	%		7.50	%
Ultimate rate		n/a			n/a			4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			2025			2025

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:

(millions)	1% Increase		1% Decrease
Effect on postretirement benefit obligation	$	5.6	$	(5.0	)

The discount rate assumption used to determine the Dec. 31, 2013 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

Components of TECO Energy Consolidated Net Periodic Benefit Cost

	Pension Benefits									Other Benefits
(millions)	2013			2012			2011			2013			2012		2011
Service cost	$	18.2		$	17.0		$	16.0		$	2.4		$	2.4	$	2.1
Interest cost		28.9			30.1			30.9			9.3			10.1		11.1
Expected return on plan assets		(38.4	)		(37.1	)		(38.4	)		0.0			0.0		0.0
Amortization of:
Actuarial loss		20.5			15.3			11.3			1.0			0.1		0.1
Prior service (benefit) cost		(0.4	)		(0.4	)		(0.4	)		(0.3	)		0.8		0.8
Transition obligation		0.0			0.0			0.0			0.0			1.8		2.3
Settlement loss		1.0			0.0			0.9			0.0			0.0		0.0
Net periodic benefit cost	$	29.8		$	24.9		$	20.3		$	12.4		$	15.2	$	16.4

Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets

(millions)	2013			2012			2011			2013			2012			2011
Prior service cost	$	0.0		$	0.0		$	0.0		$	0.0		$	(5.2	)	$	0.0
Net loss (gain)		(75.7	)		34.0			43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)		(21.5	)		(15.3	)		(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost		0.4			0.4			0.4			0.3			(0.8	)		(0.8	)
Transition obligation		0.0			0.0			0.0			0.0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets	$	(96.8	)	$	19.1		$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total Recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets	$	(67.0	)	$	44.0		$	51.8		$	(3.9	)	$	23.6		$	5.7

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TEC’s portion of the net periodic benefit costs for pension benefits was $21.7 million, $18.3 million and $13.1 million for 2013, 2012 and 2011, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $10.0 million, $12.4 million and $10.0 million for 2013, 2012 and 2011, respectively.

The estimated net loss and prior service credit for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year are $10.5 million and $0.5 million, respectively. There will be no remaining net loss for the other postretirement benefit plan that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Discount rate		4.196	%		4.797	%		5.30	%		4.180	%		4.744	%		5.25	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.75	%		n/a			n/a			n/a
Rate of compensation increase		3.76	%		3.83	%		3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			n/a			7.50	%		7.75	%		8.00	%
Ultimate rate		n/a			n/a			n/a			4.50	%		4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			n/a			2025			2025			2023

The discount rate assumption used to determine the 2013 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2013, TECO Energy’s pension plan experienced actual asset returns of approximately 12%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:

(millions)	1% Increase		1% Decrease
Effect on periodic cost	$	0.2	$	(0.2	)

Pension Plan Assets

Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target Allocation	Actual Allocation, End of Year
Asset Category		2013			2012
Equity securities	48%-54%		54	%		55	%
Fixed income securities	46%-52%		46	%		45	%
Total	100%		100	%		100	%

TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy, Inc. expects to take additional steps to more closely match plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.

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If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and 2012.

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2013
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	44.7		$	0.0		$	0.0	$	44.7
Accounts payable		(40.8	)		0.0			0.0		(40.8	)
Cash equivalents
STIFs		7.9			0.0			0.0		7.9
T bills		0.0			0.3			0.0		0.3
Repurchase agreements		0.0			8.8			0.0		8.8
Commercial paper		0.0			0.4			0.0		0.4
Money markets		0.0			1.5			0.0		1.5
Total cash equivalents		7.9			11.0			0.0		18.9
Equity securities
Common stocks		91.6			0.0			0.0		91.6
ADRs		3.0			0.0			0.0		3.0
REITs		1.7			0.0			0.0		1.7
Preferred stock		0.0			0.8			0.0		0.8
Mutual funds		172.6			0.0			0.0		172.6
Commingled fund		0.0			50.0			0.0		50.0
Total equity securities		268.9			50.8			0.0		319.7
Fixed income securities
Municipal bonds		0.0			7.3			0.0		7.3
Government bonds		0.0			35.7			0.0		35.7
Corporate bonds		0.0			19.6			0.0		19.6
ABS		0.0			0.4			0.0		0.4
MBS, net short sales		0.0			6.7			0.0		6.7
CMOs		0.0			2.3			0.0		2.3
Mutual funds		0.0			85.1			0.0		85.1
Commingled fund		0.0			94.1			0.0		94.1
Total fixed income securities		0.0			251.2			0.0		251.2
Derivatives
Short futures		0.0			0.2			0.0		0.2
Swaps		0.0			(0.9	)		0.0		(0.9	)
Purchased options (swaptions)		0.0			0.2			0.0		0.2
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.9	)		0.0		(0.9	)
Miscellaneous		0.0			0.2			0.0		0.2
Total	$	280.7		$	312.3		$	0.0	$	593.0

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Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2012
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	64.8		$	0.0		$	0.0	$	64.8
Accounts payable		(72.8	)		0.0			0.0		(72.8	)
Cash equivalents
STIFs		9.0			0.0			0.0		9.0
T bills		0.0			0.6			0.0		0.6
Repurchase agreements		0.0			23.1			0.0		23.1
CDs		0.0			1.1			0.0		1.1
Commercial paper		0.0			0.9			0.0		0.9
Money markets		0.0			0.6			0.0		0.6
Total cash equivalents		9.0			26.3			0.0		35.3
Equity securities
Common stocks		125.3			0.0			0.0		125.3
ADRs		6.2			0.0			0.0		6.2
REITs		2.0			0.0			0.0		2.0
Preferred stocks		0.0			0.8			0.0		0.8
Equity mutual funds		153.4			0.0			0.0		153.4
Total equity securities		286.9			0.8			0.0		287.7
Fixed income securities
Municipal bonds		0.0			8.0			0.0		8.0
Government bonds		0.0			53.0			0.0		53.0
Corporate bonds		0.0			19.8			0.0		19.8
ABS		0.0			0.5			0.0		0.5
MBS		0.0			17.6			0.0		17.6
CMBS		0.0			0.3			0.0		0.3
CMOs		0.0			2.5			0.0		2.5
Fixed income mutual fund		0.0			63.7			0.0		63.7
Fixed income commingled fund		0.0			49.4			0.0		49.4
Total fixed income securities		0.0			214.8			0.0		214.8
Derivatives
Swaps		0.0			(0.5	)		0.0		(0.5	)
Purchased options (swaptions)		0.0			0.1			0.0		0.1
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.8	)		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.1
Total	$	287.9		$	241.2		$	0.0	$	529.1

• The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.

• The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.

• The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.

• The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.

• T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.

• The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.

• The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of

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government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.

• The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.

• The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s other postretirement benefits plan.

Contributions

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy made $42.0 million of contributions to this plan in 2013 and $35.5 million in 2012, which met the minimum funding requirements for both 2013 and 2012. TEC’s portion of the contribution in 2013 was $33.5 million and in 2012 was $27.9 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TECO Energy estimates its contribution in 2014 to be $47.5 million, with TEC’s portion being $38.4 million. TECO Energy estimates it will make annual contributions from 2015 to 2018 ranging from $4.0 to $48.0 million per year based on current assumptions, with TEC’s portion to range from $3 million to $39 million. These amounts are in excess of the minimum funding required under ERISA guidelines.

The SERP is funded annually to meet the benefit obligations. TECO Energy made contributions of $2.6 million and $1.3 million to this plan in 2013 and 2012, respectively. TEC’s portion of the contributions in 2013 and 2012 were $1.0 million and $0.6 million, respectively. In 2014, TECO Energy expects to make a contribution of about $3.3 million to this plan. TEC’s portion of the expected contribution is about $0.9 million.

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2014, TECO Energy expects to make a contribution of about $13.3 million. TEC’s portion of the expected contribution is $10.8 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments - TECO Energy
(including projected service and net of employee contributions)			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2014	$	53.5	$	13.3
2015		50.9		13.9
2016		55.3		14.6
2017		55.9		15.2
2018		58.3		15.7
2019-2023		298.6		81.9

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Employer matching contributions

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are 60% of eligible participant contributions with additional incentive match of up to 40% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended Dec. 31, 2013, 2012 and 2011, TECO Energy and its subsidiaries recognized expense totaling $11.3 million, $7.0 million and $9.0 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled $9.1 million, $6.0 million and $5.8 million for 2013, 2012 and 2011, respectively.

6. Short-Term Debt

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

Credit Facilities
	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	6.0	$	0.7	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		78.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	84.0	$	0.7	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

At Dec. 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 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 Dec. 31, 2012.

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., Inc. as Program Agent. The amendment extends the maturity date to Feb. 13, 2015 and makes certain other technical changes. Please refer to Note 16 for additional information.

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

7. Long-Term Debt

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

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

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

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

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

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

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Dec. 31, 2013 to provide an opportunity to evaluate refinancing alternatives.

Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002

On Oct. 1, 2012, TEC redeemed $147.1 million of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (the 2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, $60.7 million of the 2002 Bonds due Oct. 1, 2013 bore interest at 5.1% and $86.4 million of the 2002 Bonds due Oct. 1, 2023 bore interest at 5.5%.

Issuance of Tampa Electric Company 2.60% Notes due 2022

On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022 (the 2022 Notes). The 2022 Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2022 Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the 2022 Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, 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 June 15, 2022, TEC may at its option redeem the 2022 Notes, in whole or in part, at 100% of the principal amount of the 2022 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of Tampa Electric Company 4.10% Notes due 2042

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the 2042 Notes). The 2042 Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 2042 Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2042 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 2042 Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 2042 Notes, in whole or in part, at 100% of the principal amount of the 2042 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

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8. Other Comprehensive Income

TEC reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income
(millions)	Gross			Tax			Net
2013
Unrealized gain (loss) on cash flow hedges	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		1.4			(0.5	)		0.9
Gain (Loss) on cash flow hedges		1.4			(0.5	)		0.9
Total other comprehensive income (loss)	$	1.4		($	0.5	)	$	0.9
2012
Unrealized (loss) gain on cash flow hedges	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		1.4			(0.6	)		0.8
(Loss) Gain on cash flow hedges		(6.6	)		2.5			(4.1	)
Total other comprehensive (loss) income	($	6.6	)	$	2.5		($	4.1	)
2011
Unrealized gain (loss) on cash flow hedges	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		1.2			(0.5	)		0.7
Gain (Loss) on cash flow hedges		1.2			(0.5	)		0.7
Total other comprehensive income (loss)	$	1.2		($	0.5	)	$	0.7

Accumulated Other Comprehensive Loss
(millions) As of Dec. 31,	2013			2012
Net unrealized losses from cash flow hedges (1)	($	7.8	)	($	8.7	)
Total accumulated other comprehensive loss	($	7.8	)	($	8.7	)

(1) Net of tax benefit of $4.9 million and $5.5 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

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9. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on 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. In December 2010, two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim against PGS. The Court’s order is now final and not appealable. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

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

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

Environmental Protection Agency Section 114 Letter

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Long-Term Commitments

TEC has commitments under long-term leases, primarily for building space, capacity payments, office equipment and heavy equipment. Total rental expense for these leases, included in “Regulated operations & maintenance – Other” on the

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Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011, totaled $2.3 million, $2.2 million and $2.2 million, respectively. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:

Future Minimum Lease and Capacity Payments
(millions)	Capacity Payments		Operating Leases		Total
Year ended Dec. 31:
2014	$	14.8	$	2.3	$	17.1
2015		14.9		2.3		17.2
2016		14.6		2.2		16.8
2017		9.9		2.2		12.1
2018		10.1		2.2		12.3
Thereafter		0.0		13.4		13.4
Total future minimum payments	$	64.3	$	24.6	$	88.9

Guarantees and Letters of Credit

TEC accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:

• Initial recognition and initial measurement of a liability, and/or

• Disclosure of specific details of the guarantee.

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

At Dec. 31, 2013, TEC was not obligated under guarantees, but had $0.7 million of letters of credit outstanding.

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After (1) 2018		Total		Liabilities Recognized at Dec. 31, 2013
Tampa Electric (2)
Letters of credit	$	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 Dec. 31, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2013, TEC was in compliance with all required financial covenants.

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10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:
(millions)	2013		2012		2011
Natural gas sales, net	$	18.3	$	11.7	$	0.0
Administrative and general, net	$	27.2	$	23.4	$	17.5

Amounts due from or to affiliates at Dec. 31,
(millions)	2013		2012
Accounts receivable (1)	$	1.3	$	4.7
Accounts payable (1)		9.8		7.9
Taxes receivable		54.9		22.1
Taxes payable		0.4		3.2

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

TEC had certain transactions, in the ordinary course of business, with entities in which directors of TEC had interests. TEC paid legal fees of $1.7 million, $1.2 million and $1.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively, to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee.

11. Segment Information

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 700,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for almost 350,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

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	Tampa				Other &
(millions)	Electric		PGS		Eliminations			TEC
2013
Revenues - external	$	1,950.1	$	392.7	$	0.0		$	2,342.8
Sales to affiliates		0.4		0.8		(1.2	)		0.0
Total revenues		1,950.5		393.5		(1.2	)		2,342.8
Depreciation and amortization		238.8		51.5		0.0			290.3
Total interest charges		91.8		13.5		0.0			105.3
Provision for income taxes		116.9		21.9		0.0			138.8
Net income		190.9		34.7		0.0			225.6
Total assets		5,895.4		989.3		(8.9	)		6,875.8
Capital expenditures		428.6		79.0		0.0			507.6
2012
Revenues - external	$	1,980.9	$	397.1	$	0.0		$	2,378.0
Sales to affiliates		0.4		1.8		(2.2	)		0.0
Total revenues		1,981.3		398.9		(2.2	)		2,378.0
Depreciation and amortization		237.6		50.6		0.0			288.2
Total interest charges		109.8		16.0		0.0			125.8
Provision for income taxes		120.2		21.5		0.0			141.7
Net income		193.1		34.1		0.0			227.2
Total assets		5,760.4		970.9		13.3			6,744.6
Capital expenditures		361.7		97.3		0.0			459.0
2011
Revenues - external	$	2,020.1	$	450.5	$	0.0		$	2,470.6
Sales to affiliates		0.5		3.0		(3.5	)		0.0
Total revenues		2,020.6		453.5		(3.5	)		2,470.6
Depreciation and amortization		222.1		48.4		0.0			270.5
Total interest charges		121.8		17.7		0.0			139.5
Provision for income taxes		124.8		20.6		0.0			145.4
Net income		202.7		32.6		0.0			235.3
Total assets		5,678.0		888.4		(10.0	)		6,556.4
Capital expenditures		314.9		71.9		0.0			386.8

12. Asset Retirement Obligations

TEC accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

For the year ended Dec. 31, 2012, $27.6 million of liabilities settled resulted primarily from asbestos abatement and other dismantling at the generating stations at Tampa Electric.

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Reconciliation of beginning and ending carrying amount of asset retirement obligations:
	Dec. 31,
(millions)	2013			2012
Beginning balance	$	5.0		$	30.8
Additional liabilities		0.1			0.0
Liabilities settled		(0.2	)		(27.6	)
Revisions to estimated cash flows		(0.3	)		0.0
Other (1)		0.2			1.8
Ending balance	$	4.8		$	5.0

(1) Accretion recorded as a deferred regulatory asset.

13. 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 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 (see Note 14). 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 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).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Dec. 31, 2013, all of TEC’s physical contracts qualify for the NPNS exception.

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

Natural Gas Derivatives (1)
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.5	$	0.0
Long-term assets		0.3		0.2
Total assets	$	9.8	$	0.2
Current liabilities	$	0.0	$	14.1
Long-term liabilities		0.2		0.2
Total liabilities	$	0.2	$	14.3

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

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

Offsetting of Derivative Assets and Liabilities (millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Dec. 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

The ending balance in AOCI related to previously settled interest rate swaps at Dec. 31, 2013 is a net loss of $7.8 million after tax and accumulated amortization. This compares to a net loss of $8.7 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

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

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

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

Based on the fair value of the instruments at Dec. 31, 2013, net pretax losses of $9.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

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The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31, 2013, 2012 and 2011:

(millions)	Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
For the years ended Dec. 31:		2013			2012			2011
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)
Interest rate contracts:	Interest expense	($	0.9	)	($	0.8	)	($	0.7	)
Total		($	0.9	)	($	0.8	)	($	0.7	)

(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 years ended Dec. 31, 2013, 2012 and 2011, all hedges were effective.

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

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2014		0.0		36.9
2015		0.0		7.6
Total		0.0		44.5

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

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Dec. 31, 2013, 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 Dec. 31, 2013, 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 Dec. 31, 2013 were asset positions.

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14. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

Natural gas swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 13).

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 Dec. 31, 2013, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions. There were no Level 3 assets or liabilities during the 2013 or 2012 fiscal years.

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15. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.1 million, $75.8 million and $81.2 million, under these PPAs for the three years ended Dec. 31, 2013, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $46.6 million and $34.4 million for the two years ended Dec. 31, 2012 and 2011, respectively. This PPA expired on Dec. 31, 2012.

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

16. Subsequent Events

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.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

Item 9A. CONTROLS AND PROCEDURES.

TECO Energy, Inc.

Conclusions Regarding Effectiveness 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 (Exchange Act)) as of the end of the period covered by this annual report, Dec. 31, 2013 (Evaluation Date). Based on such evaluation, TECO Energy’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of TECO Energy, Inc.’s internal control over financial reporting as of Dec. 31, 2013 based on the 1992 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that TECO Energy, Inc.’s internal control over financial reporting was effective as of Dec. 31, 2013.

TECO Energy’s internal control over financial reporting as of Dec. 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered certified public accounting firm, as stated in their report which is on page 75 of this report.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting.

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 controls 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

Conclusions Regarding Effectiveness 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 Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this annual report, Dec. 31, 2013 (Evaluation Date). Based on such evaluation, TEC’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TEC’s disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting.

TEC’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of TEC’s internal control over financial reporting as of Dec. 31, 2013 based on the 1992 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that TEC’s internal control over financial reporting was effective as of Dec. 31, 2013.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting.

There was no change in Tampa Electric Company’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 Tampa Electric Company’s internal controls that occurred during Tampa Electric Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Item 9B. OTHER INFORMATION.

None.

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

(a) The information required by Item 10 with respect to the directors of the registrant is included under the caption “Election of Directors” in TECO Energy’s definitive proxy statement for its Annual Meeting of Shareholders to be held on April 30, 2014 (Proxy Statement) and is incorporated herein by reference.

(b) The information required by Item 10 concerning executive officers of the registrant is included under the caption “Executive Officers of the Registrant” on page 24 of this report.

(c) The information required by Item 10 concerning Section 16(a) Beneficial Ownership Reporting Compliance is included under that caption in the Proxy Statement and is incorporated herein by reference.

(d) Information regarding TECO Energy’s Audit Committee, including the committee’s financial experts, is included under the caption “Committees of the Board” in the Proxy Statement, and is incorporated herein by reference.

(e) TECO Energy has adopted a code of ethics applicable to all of its employees, officers and directors. The text of the Code of Ethics and Business Conduct is available in the Corporate Governance section of the Investors page of the company’s website at www.tecoenergy.com. Any amendments to or waivers of the Code of Ethics and Business Conduct for the benefit of any executive officer or director will also be posted on the website.

Item 11. EXECUTIVE COMPENSATION.

The information required by Item 11 is included in the Proxy Statement beginning with the caption “Compensation Committee Report” and ending with “Post-Termination Benefits Table” just above the caption “Ratification of Appointment of Independent Auditor” and is incorporated herein by reference.

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The information required by Item 12 is included under the captions “Equity Compensation Plan Information” and “Share Ownership” in the Proxy Statement, and is incorporated herein by reference.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

The information required by Item 13 is included under the captions “Certain Relationships and Related Person Transactions” and “Director Independence” in the Proxy Statement, and is incorporated herein by reference.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required by Item 14 for TECO Energy is included under the caption “Item 2 – Ratification of Appointment of Independent Auditor” in the Proxy Statement and is incorporated herein by reference.

TEC incurred $0.8 million, $0.8 million and $0.7 million in audit-related fees rendered by PricewaterhouseCoopers for each of the years 2013, 2012 and 2011, respectively, including $0.3 million related to Sarbanes-Oxley in each of those three years. No other fees for services rendered by PricewaterhouseCoopers were incurred by TEC in those years.

161

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a) Certain Documents Filed as Part of this Form 10-K

1. Financial Statements

TECO Energy, Inc. Financial Statements – See index on page 74

Tampa Electric Company Financial Statements – See index on page 124

2. Financial Statement Schedules

TECO Energy, Inc. Schedule II – page 163

Tampa Electric Company Schedule II – page 164

3. Exhibits – See index beginning on page 168

(b) The exhibits filed as part of this Form 10-K are listed on the Exhibit Index immediately preceding such Exhibits. The Exhibit Index is incorporated herein by reference.

(c) The financial statement schedules filed as part of this Form 10-K are listed in paragraph (a)(2) above, and follow immediately.

162

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TECO ENERGY, INC.

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended Dec. 31, 2013, 2012 and 2011

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions (1)		Period
Allowance for Uncollectible Accounts:
2013	$	4.2	$	3.3	$	0.0	$	2.8	$	4.7
2012	$	2.6	$	4.8	$	0.0	$	3.2	$	4.2
2011	$	4.5	$	3.8	$	0.0	$	5.7	$	2.6

(1) Write-off of individual bad debt accounts

163

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended Dec. 31, 2013, 2012 and 2011

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions (1)		Period
Allowance for Uncollectible Accounts:
2013	$	1.5	$	3.3	$	0.0	$	2.8	$	2.0
2012	$	1.3	$	3.4	$	0.0	$	3.2	$	1.5
2011	$	3.2	$	3.8	$	0.0	$	5.7	$	1.3

(1) Write-off of individual bad debt accounts

164

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.
Dated: February 28, 2014	By:	/s/ JOHN B. RAMIL
		JOHN B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2014:

Signature	Title
/s/ JOHN B. RAMIL	President, Chief Executive Officer and Director
JOHN B. RAMIL	(Principal Executive Officer)
/s/ SANDRA W. CALLAHAN	Senior Vice President-Finance and Accounting and Chief
SANDRA W. CALLAHAN	Financial Officer (Chief Accounting Officer)
	(Principal Financial and Principal Accounting Officer)

Signature	Title	Signature	Title
/s/ JAMES L. FERMAN, JR.	Director	/s/ LORETTA A. PENN	Director
JAMES L. FERMAN, JR.		LORETTA A. PENN
/s/ EVELYN V. FOLLIT	Director	/s/ TOM L. RANKIN	Director
EVELYN V. FOLLIT		TOM L. RANKIN
/s/ SHERRILL W. HUDSON	Chairman of the	/s/ WILLIAM D. ROCKFORD	Director
SHERRILL W. HUDSON	Board and Director	WILLIAM D. ROCKFORD
/s/ JOSEPH P. LACHER	Director	/s/ PAUL L. WHITING	Director
JOSEPH P. LACHER		PAUL L. WHITING

165

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

	TAMPA ELECTRIC COMPANY
Dated: February 28, 2014	By:	/s/ JOHN B. RAMIL
		JOHN B. RAMIL
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2014:

Signature	Title
/s/ JOHN B. RAMIL	Chief Executive Officer and Director
JOHN B. RAMIL	(Principal Executive Officer)
/s/ SANDRA W. CALLAHAN	Vice President-Finance and Accounting and Chief
SANDRA W. CALLAHAN	Financial Officer (Chief Accounting Officer)
	(Principal Financial and Principal Accounting Officer)

Signature	Title	Signature	Title
/s/ JAMES L. FERMAN, JR.	Director	/s/ LORETTA A. PENN	Director
JAMES L. FERMAN, JR.		LORETTA A. PENN
/s/ EVELYN V. FOLLIT	Director	/s/ TOM L. RANKIN	Director
EVELYN V. FOLLIT		TOM L. RANKIN
/s/ SHERRILL W. HUDSON	Chairman of the Board	/s/ WILLIAM D. ROCKFORD	Director
SHERRILL W. HUDSON	and Director	WILLIAM D. ROCKFORD
/s/ JOSEPH P. LACHER	Director	/s/ PAUL L. WHITING	Director
JOSEPH P. LACHER		PAUL L. WHITING

166

Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report or proxy material has been sent to Tampa Electric Company’s security holders because all of its equity securities are held by TECO Energy, Inc.

167

INDEX TO EXHIBITS

Exhibit No.	Description
2.1	Equity Purchase Agreement dated as of September 27, 2012 between TECO Guatemala Holdings II, LLC and Sur Eléctrica Holding Limited (Exhibit 10.1, Form 10-Q, for the quarter ended Sep. 30, 2012 of TECO Energy, Inc. and Tampa Electric Company).	*
2.2	Equity Purchase Agreement dated as of September 27, 2012 between TECO Guatemala Holdings II, LLC and Renewable Energy Investments Guatemala Limited (Exhibit 10.2, Form 10-Q, for the quarter ended Sep. 30, 2012 of TECO Energy, Inc. and Tampa Electric Company).	*
2.3	Equity Purchase Agreement dated as of September 27, 2012 between TECO Guatemala Holdings II, LLC and Renewable Energy Investments Guatemala Limited (Exhibit 10.3, Form 10-Q, for the quarter ended Sep. 30, 2012 of TECO Energy, Inc. and Tampa Electric Company).	*
2.4	Equity Purchase Agreement dated as of October 17, 2012 between TECO Guatemala Holdings II, LLC and C.F. Financeco, Ltd. (Exhibit 2.5, Form 10-K for 2012 of TECO Energy, Inc. and Tampa Electric Company).	*
2.5	Stock Purchase Agreement, dated as of May 25, 2013, by and among TECO Energy, Inc., New Mexico Gas Intermediate, Inc. and Continental Energy Systems LLC (Exhibit 2.1, Form 8-K dated May 28, 2013 of TECO Energy, Inc.).	*
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, 2011 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	Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company of Florida, N.A., as trustee, dated as of Jun. 1, 2002 (including the form of bond) (Exhibit 4.5, Amendment No. 1 to Form 10-K for 2004 of TECO Energy, Inc. and Tampa Electric Company).	*
4.2	Loan and Trust Agreement among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee, dated as of Jan. 5, 2006 (including the form of bond) (Exhibit 4.1, Form 8-K dated Jan. 19, 2006 of Tampa Electric Company).	*
4.3	Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jul. 1, 1998 (Exhibit 4.1, Registration Statement No. 333-55873 of Tampa Electric Company).	*
4.4	Third Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Jun. 15, 2001 (Exhibit 4.2, Form 8-K dated Jun. 25, 2001 of Tampa Electric Company).	*
4.5	Fourth Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of Aug. 15, 2002 (Exhibit 4.2, Form 8-K dated Aug. 26, 2002 of Tampa Electric Company).	*
4.6	Fifth Supplemental Indenture between Tampa Electric Company and The Bank of New York, as trustee, dated as of May 1, 2006 (Exhibit 4.16, Form 8-K dated May 12, 2006 of Tampa Electric Company).	*
4.7	Amended and Restated Note Agreement dated as of May 30, 1997 between Tampa Electric Company (successor by merger to Peoples Gas System, Inc.) and The Prudential Insurance Company of America (Exhibit 4.2, Form 8-K dated Dec. 15, 2004 of TECO Energy, Inc. and Tampa Electric Company).	*
4.8	Letter Amendment No. 1 dated as of Dec. 9, 2004 to the Amended and Restated Note Agreement dated as of May 30, 1997 between Tampa Electric Company (successor by merger to Peoples Gas System, Inc.) and The Prudential Insurance Company of America (Exhibit 4.1, Form 8-K dated Dec. 15, 2004 of TECO Energy, Inc. and Tampa Electric Company).	*
4.9	Note Purchase Agreement among Tampa Electric Company and the Purchasers party thereto, dated as of Apr. 11, 2003 (Exhibit 10.1, Form 8-K dated Apr. 14, 2003 of Tampa Electric Company).	*
4.10	Loan and Trust Agreement dated as of November 15, 2010 among Tampa Electric Company, Polk County Industrial Development Authority and The Bank of New York Mellon Trust Company, N.A., as trustee (including the form of bond) (Exhibit 4.1, Form 8-K dated Nov. 23, 2010 of Tampa Electric Company).	*

168

4.11	Sixth Supplemental Indenture dated as of May 1, 2007 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.18, Form 8-K dated May 25, 2007 of Tampa Electric Company).	*
4.12	Seventh Supplemental Indenture dated as of May 1, 2008 between Tampa Electric Company and The Bank of New York, as trustee (Exhibit 4.20, Form 8-K dated May 16, 2008 of Tampa Electric Company).	*
4.13	Eighth Supplemental Indenture dated as of Nov. 15, 2010 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee (including the form of 5.40% Notes due 2021) (Exhibit 4.1, Form 8-K dated Dec. 9, 2010 of Tampa Electric Company).	*
4.14	Ninth Supplemental Indenture dated as of May 31, 2012 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 4.10% Notes due 2042) (Exhibit 4.23, Form 8-K dated June 5, 2012 for Tampa Electric Company).	*
4.15	Tenth Supplemental Indenture dated as of September 19, 2012 between Tampa Electric Company, as issuer, and The Bank of New York Mellon, as trustee, supplementing and amending the Indenture dated as of July 1, 1998, as amended (including the form of 2.60% Notes due 2022) (Exhibit 4.25, Form 8-K dated September 28, 2012 for Tampa Electric Company).	*
4.16	Loan and Trust Agreement dated as of Jul. 2, 2007 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (including the form of Bond) (Exhibit 4.1, Form 8-K dated Jul. 25, 2007 of Tampa Electric Company).	*
4.17	First Supplemental Loan and Trust Agreement dated as of Mar. 26, 2008 among Hillsborough County Industrial Development Authority, Tampa Electric Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1, Form 8-K dated Mar. 26, 2008 of Tampa Electric Company).	*
4.18	Indenture between TECO Energy, Inc. and The Bank of New York, as trustee, dated as of Aug. 17, 1998 (Exhibit 4.1, Form 8-K dated Sep. 20, 2000 of TECO Energy, Inc.).	*
4.19	Third Supplemental Indenture dated as of Dec. 1, 2000 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.21, Form 8-K dated Dec. 20, 2000 of TECO Energy, Inc.).	*
4.20	Fourth Supplemental Indenture dated as of Apr. 30, 2001 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.28, Form 8-K dated May 1, 2001 of TECO Energy, Inc.).	*
4.21	Fifth Supplemental Indenture dated as of Sep. 10, 2001 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.16, Form 8-K dated Sep. 26, 2001 of TECO Energy, Inc.).	*
4.22	Seventh Supplemental Indenture dated as of May 1, 2002 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.15, Form 8-K dated May 13, 2002 of TECO Energy, Inc.).	*
4.23	Ninth Supplemental Indenture dated as of Jun. 10, 2003 between TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.15, Form 8-K dated Jun. 13, 2003 of TECO Energy, Inc.).	*
4.24	Tenth Supplemental Indenture dated as of May 26, 2005 between TECO Energy, Inc. and The Bank of New York, as trustee (including the form of 6.75% Note) (Exhibit 4.1, Form 8-K dated May 26, 2005 of TECO Energy, Inc.).	*
4.25	Eleventh Supplemental Indenture dated as of Jun. 7, 2005 between TECO Energy, Inc. and The Bank of New York, as trustee (including the form of Floating Rate Note) (Exhibit 4.1, Form 8-K dated Jun. 7, 2005 of TECO Energy, Inc.).	*
4.26	Indenture dated as of Dec. 21, 2007 by and among TECO Finance, Inc., as issuer, TECO Energy, Inc., as guarantor, and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1, Form 8-K dated Dec. 21, 2007 of TECO Energy, Inc.).	*
4.27	First Supplemental Indenture dated as of Dec. 21, 2007 by and among TECO Finance, Inc., as issuer, TECO Energy, Inc., as guarantor, and The Bank of New York Trust Company, N.A., as trustee (including the form of TECO Finance 7.20% Notes due 2011, TECO Finance 7.00% Notes due 2012 and TECO Finance 6.572% Notes due 2017) (Exhibit 4.2, Form 8-K dated Dec. 21, 2007 of TECO Energy, Inc.).	*
4.28	Second Supplemental Indenture dated as of Dec. 21, 2007 by and among TECO Finance, Inc., as issuer, TECO Energy, Inc., as guarantor, and The Bank of New York Trust Company, N.A., as trustee (including the form of TECO Finance 6.75% Notes due 2015) (Exhibit 4.3, Form 8-K dated Dec. 21, 2007 of TECO Energy, Inc.).	*
4.29	Third Supplemental Indenture dated as of Mar. 15, 2010 by and among TECO Finance, Inc., as issuer, TECO Energy, Inc., as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee (including the form of TECO Finance 4.00% Notes due 2016 and 5.15% Notes due 2020) (Exhibit 4.26, Form 8-K dated Mar. 15, 2010 of TECO Energy, Inc.).	*
4.30	Twentieth Supplemental Indenture dated as of December 1, 2013 between Tampa Electric Company and US Bank, N.A., as successor trustee, to the Indenture of Mortgage among Tampa Electric Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of Aug. 1, 1946.

169

10.1	TECO Energy Group Supplemental Executive Retirement Plan, as amended and restated as of Nov. 1, 2007 (Exhibit 10.1, Form 10-K for 2007 of TECO Energy, Inc. and Tampa Electric Company).	*
10.2	TECO Energy Group Supplemental Disability Income Plan, dated as of Mar. 20, 1989 (Exhibit 10.22, Form 10-K for 1988 of TECO Energy, Inc.).	*
10.3	TECO Energy Group Supplemental Retirement Benefits Trust Agreement, effective as of Nov. 17, 2008 (Exhibit 10.3, Form 10-K for 2008 of TECO Energy, Inc. and Tampa Electric Company).	*
10.4	Annual Incentive Compensation Plan for TECO Energy and subsidiaries, revised as of Feb. 2, 2011 (Exhibit 10.4, Form 10-K for 2011 of TECO Energy, Inc. and Tampa Electric Company).	*
10.5	Form of Change-in-Control Severance Agreement between TECO Energy, Inc. and certain Executive Officers (Exhibit 10.1, Form 10-Q for the quarter ended Sep. 30, 2008 of TECO Energy, Inc. and Tampa Electric Company).	*
10.6	Form of Change-in-Control Severance Agreement between TECO Energy, Inc. and certain Executive Officers (Exhibit 10.1, Form 8-K dated Feb. 5, 2010 of TECO Energy, Inc.).	*
10.7	TECO Energy Directors’ Deferred Compensation Plan, as amended and restated effective as of Aug. 1, 2007 (Exhibit 10.3, Form 10-Q for the quarter ended Sep. 30, 2007 of TECO Energy, Inc. and Tampa Electric Company).	*
10.8	Amendment No. 1 to TECO Energy Directors’ Deferred Compensation Plan, effective as of Apr. 29, 2009 (Exhibit 10.1, Form 10-Q for the quarter ended Jun. 30, 2009 of TECO Energy, Inc. and Tampa Electric Company).	*
10.9	Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1996 Equity Incentive Plan (and its successor plan) (Exhibit 10.5, Form 10-Q for the quarter ended Jun. 30, 1999 of TECO Energy, Inc.).	*
10.10	TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10.1, Form 8-K dated Apr. 16, 1997 of TECO Energy, Inc.).	*
10.11	Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1997 Director Equity Plan, dated as of Jan. 29, 2003 (Exhibit 10.28, Form 10-K for 2002 of TECO Energy, Inc. and Tampa Electric Company).	*
10.12	TECO Energy, Inc. 2004 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended Mar. 31, 2004 of TECO Energy, Inc. and Tampa Electric Company).	*
10.13	Form of Restricted Stock Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2004 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended Jun. 30, 2009 of TECO Energy, Inc. and Tampa Electric Company).	*
10.14	Form of Performance Shares Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2004 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the quarter ended Jun. 30, 2009 of TECO Energy, Inc. and Tampa Electric Company).	*
10.15	Nonstatutory Stock Option granted to S. W. Hudson, dated as of Jul. 6, 2004, under the TECO Energy, Inc. 2004 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended Jun. 30, 2004 of TECO Energy, Inc. and Tampa Electric Company).	*
10.16	TECO Energy, Inc. 2010 Equity Incentive Plan (Exhibit 10.1, Post-Effective Amendment No. 1 to Form S-8 Registration Statement No. 333-115954 dated May 5, 2010 of TECO Energy, Inc.).	*
10.17	Form of Performance Shares Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the quarter ended Jun. 30, 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
10.18	Form of Restricted Stock Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the quarter ended Jun. 30, 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
10.19	Form of Restricted Stock Agreement between TECO Energy, Inc. and certain directors under the TECO Energy, Inc. 2010 Equity Incentive Plan (Exhibit 10.4, Form 10-Q for the quarter ended Jun. 30, 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
10.20	Form of Performance Shares Agreement between TECO Energy, Inc. and certain officers under the TECO Energy, Inc. 2010 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 2013).	*
10.21	Compensatory Arrangements with Executive Officers of TECO Energy, Inc.
10.22	Compensatory Arrangements with Non-Management Directors of TECO Energy, Inc.
10.23	Employment Agreement between TECO Energy, Inc. and Sherrill W. Hudson dated Aug. 4, 2010 (Exhibit 10.1, Form 8-K dated Aug. 4, 2010 of TECO Energy, Inc.).	*
10.24	Change-in-Control Severance Agreement between TECO Energy, Inc. and Clark Taylor (Exhibit 10.1, Form 10-Q for the quarter ended Mar. 31, 2011 of TECO Energy, Inc. and Tampa Electric Company).	*

170

10.25	Change-in-Control Severance Agreement between TECO Coal Corporation and Clark Taylor (Exhibit 10.2, Form 10-Q for the quarter ended Mar. 31, 2011 of TECO Energy, Inc. and Tampa Electric Company).	*
10.26	Insurance Agreement dated as of Jan. 5, 2006 between Tampa Electric Company and Ambac Assurance Corporation (Exhibit 10.1, Form 8-K dated Jan. 19, 2006 of Tampa Electric Company).	*
10.27	Third Amended and Restated Credit Agreement dated as of Oct. 25, 2011, among TECO Finance, Inc., as Borrower, TECO Energy, Inc. as Guarantor, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 4.1, Form 8-K dated Oct. 25, 2011 of TECO Energy, Inc.).	*
10.28	Third Amended and Restated Credit Agreement dated as of Oct. 25, 2011, among Tampa Electric Company, as Borrower, Citibank, N.A., as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 4.2, Form 8-K dated Oct. 25, 2011 of Tampa Electric Company).	*
10.29	Purchase and Contribution Agreement dated as of Jan. 6, 2005, between Tampa Electric Company as the Originator and TEC Receivables Corporation as the Purchaser (Exhibit 4.1, Form 8-K dated Jan. 6, 2005 of TECO Energy, Inc. and Tampa Electric Company).	*
10.30	Loan and Servicing Agreement dated as of Jan. 6, 2005, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citicorp North America, Inc. as Program Agent (Exhibit 4.2, Form 8-K dated Jan. 6, 2005 of TECO Energy, Inc. and Tampa Electric Company).	*
10.31	Omnibus Amendment No. 3 to Loan and Servicing Agreement dated as of Dec. 22, 2006, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citicorp North America, Inc. as Program Agent (also amending the agreement identified in Exhibit 10.29 herein) (Exhibit 10.28.1, Form 10-K for 2009 of TECO Energy, Inc. and Tampa Electric Company).	*
10.32	Amendment No. 6 to Loan and Servicing Agreement dated as of Dec. 18, 2008, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citicorp North America, Inc. as Program Agent (Exhibit 99.1, Form 8-K dated Dec.18, 2008 of TECO Energy, Inc. and Tampa Electric Company).	*
10.33	Amendment No. 8 to Loan and Servicing Agreement dated as of Feb. 19, 2010, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citicorp North America, Inc. as Program Agent (Exhibit 10.28.3, Form 10-K for 2009 of TECO Energy, Inc. and Tampa Electric Company).	*
10.34	Omnibus Amendment No. 9 to Loan and Servicing Agreement dated as of Feb. 18, 2011, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citibank, North America, Inc. as Program Agent (Exhibit 10.37, Form 10-K for 2010 of TECO Energy, Inc. and Tampa Electric Company).	*
10.35	Amendment No. 10 to Loan and Servicing Agreement dated as of Feb. 17, 2012, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citibank, North America, Inc. as Program Agent (Exhibit 10.38, Form 10-K for 2011 of TECO Energy, Inc. and Tampa Electric Company).	*
10.36	Amendment No. 11 to Loan and Servicing Agreement dated as of Feb. 15, 2013, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citibank, North America, Inc. as Program Agent (Exhibit 10.39, Form 10-K for 2012 of TECO Energy, Inc. and Tampa Electric Company).	*
10.37	Omnibus Amendment No. 12 to Loan and Servicing Agreement dated as of Feb. 14, 2014, among TEC Receivables Corp. as Borrower, Tampa Electric Company as Servicer, certain lenders named therein and Citibank, N.A. as Program Agent.
10.38	Commitment Letter, dated as of May 25, 2013, by and among TECO Energy, Inc., TECO Finance, Inc. and Morgan Stanley Senior Funding, Inc. (Exhibit 10.1, Form 8-K dated May 28, 2013 of TECO Energy, Inc.).	*
10.39	Senior Unsecured Bridge Credit Agreement, dated as of June 24, 2013, by and among TECO Energy, Inc., as Guarantor, TECO Finance, Inc., as Borrower, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and the Lenders party thereto (Exhibit 10.1, Form 8-K dated June 28, 2013 of TECO Energy, Inc.).	*
10.40	Amendment No. 1 dated as of June 24, 2013 to the Third Amended and Restated Credit Agreement dated as of October 25, 2011, among TECO Finance, Inc., as Borrower, TECO Energy, Inc. as Guarantor, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Exhibit 10.2, Form 8-K dated June 28, 2013 of TECO Energy, Inc.).	*

171

10.41	Fourth Amended and Restated Credit Agreement dated as of December 17, 2013, among TECO Finance, Inc., as Borrower, TECO Energy, Inc. as Guarantor, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.1, Form 8-K dated Dec. 17, 2013 of TECO Energy, Inc. and Tampa Electric Company).	*
10.42	Fourth Amended and Restated Credit Agreement dated as of December 17, 2013, among Tampa Electric Company, as Borrower, Citibank, N.A., as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.2, Form 8-K dated Dec. 17, 2013 of TECO Energy, Inc. and Tampa Electric Company).	*
10.43	Credit Agreement dated as of December 17, 2013, among TECO Energy, Inc., as Initial Borrower JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders and LC Issuing Banks party thereto (Exhibit 10.3, Form 8-K dated Dec. 17, 2013 of TECO Energy, Inc. and Tampa Electric Company).	*
12.1	Ratio of Earnings to Fixed Charges – TECO Energy, Inc.
12.2	Ratio of Earnings to Fixed Charges – Tampa Electric Company.
21	Subsidiaries of TECO Energy, Inc.
23.1	Consent of Independent Certified Public Accountants – TECO Energy, Inc.
23.2	Consent of Independent Certified Public Accountants – Tampa Electric Company.
23.3	Consent of Cardno MM&A.
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 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 Annual Report on Form 10-K 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 Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.

Certain instruments defining the rights of holders of long-term debt of TECO Energy, Inc. and its consolidated subsidiaries authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. TECO Energy, Inc. will furnish copies of such instruments to the Securities and Exchange Commission upon request.

Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.

Executive Compensation Plans and Arrangements

Exhibits 10.1 through 10.25, above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. participate.

172

EX-4.30

Exhibit 4.30

TAMPA ELECTRIC COMPANY

TO

U.S. BANK NATIONAL ASSOCIATION,

                                             Trustee.

TWENTIETH SUPPLEMENTAL INDENTURE

Dated as of December 1, 2013.

AMENDING AND RESTATING THE INDENTURE OF MORTGAGE

Dated as of August 1, 1946,

As Heretofore Supplemented and Amended.

This is a Security Agreement covering Personal Property as well as a

Mortgage upon Real Estate and Other Property

This Twentieth Supplemental Indenture does not secure any new or

additional indebtedness and is not subject to

Florida documentary stamp tax or

Florida intangible tax.

Table of Contents

		Page
ARTICLE ONE	DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION		6
Section 1.01.	For all purposes of this Indenture, the following terms shall have the following defined meanings:		6
Section 1.02.	Uses of Terms		17
Section 1.03.	Property Additions; Cost		17
Section 1.04.	Earnings Certificate, Net Earnings Available for Interest		20
Section 1.05.	Compliance Certificates and Opinions; Form of Documents Delivered to Trustee		22
Section 1.06.	Acts of Holders		24
Section 1.07.	Notices, Etc		25
Section 1.08.	Notice to Holders of Bonds; Waiver		26
Section 1.09.	Conflict with Trust Indenture Act		27
Section 1.10.	Effect of Headings and Table of Contents		27
Section 1.11.	Successors and Assigns		27
Section 1.12.	Separability Clause		27
Section 1.13.	Parties in Interest		27
Section 1.14.	Governing Law		27
Section 1.15.	Legal Holidays		28
Section 1.16.	Investment of Cash Held by Trustee		28
Section 1.17.	Force Majeure		28
Section 1.18.	Consent to Undertaking for Costs		29
Section 1.19.	Suspension of Certain Obligations when No Bonds are Outstanding		29
ARTICLE TWO	TERMS OF BONDS		29
Section 2.01.	Issuable in Series		29
Section 2.02.	Denominations		32
Section 2.03.	Execution, Authentication, Delivery and Dating		32
Section 2.04.	Temporary Bonds		33
Section 2.05.	Registration, Registration of Transfer and Exchange		33
Section 2.06.	Mutilated, Destroyed, Lost and Stolen Bonds		35

i

Table of Contents

(Continued)

		Page
Section 2.07.	Payment of Interest; Interest Rights Preserved		35
Section 2.08.	Persons Deemed Owners		36
Section 2.09.	Cancellation		37
Section 2.10.	Computation of Interest		37
Section 2.11.	Payment to be in Proper Currency		37
Section 2.12.	Extension of Interest Payment		38
Section 2.13.	CUSIP Numbers		38
Section 2.14.	Forms of Bonds and Trustee Authentication		38
Section 2.15.	Global Bonds		39
ARTICLE THREE	ISSUANCE OF BONDS		40
Section 3.01.	Principal Amount Issuable		40
Section 3.02.	Documents Required to be Delivered		40
ARTICLE FOUR	SINKING FUNDS		43
Section 4.01.	Applicability Of Article		43
Section 4.02.	Satisfaction of Sinking Fund Payments with Bonds		43
Section 4.03.	Redemption of Bonds for Sinking Fund		44
ARTICLE FIVE	REDEMPTION AND PURCHASE OF BONDS		44
Section 5.01.	Right to Redeem		44
Section 5.02.	Notice of Redemption		45
Section 5.03.	Partial Redemption; Selection of Bonds to be Redeemed		45
Section 5.04.	Effect of Call for Redemption; Payment of Redeemed Bonds		46
Section 5.05.	Disposition of Redeemed Bonds		46
ARTICLE SIX	CERTAIN COVENANTS OF THE COMPANY		46
Section 6.01.	Payment of Principal and Interest, etc		46
Section 6.02.	Maintenance of Office or Agency, Appointment of Paying Agents, etc		47
Section 6.03.	Warranty of Title, etc		47
Section 6.04.	After Acquired Property; Instruments of Further Assurance; Recordation and Opinion, etc		48
Section 6.05.	Lien of Indenture and Maintenance of Priority Thereof		49
Section 6.06.	Trust Estate to be Kept in Repair - Rights to be Maintained, etc		49

ii

Table of Contents

(Continued)

		Page
Section 6.07.	Insurance and Disposition of Proceeds		50
Section 6.08.	Prior Lien Indebtedness		51
Section 6.09.	Disposition of Cash, etc		51
Section 6.10.	Limitations on Disposition of Trust Estate		52
Section 6.11.	Annual Filing of Certificate as to No Default		52
ARTICLE SEVEN	POSSESSION, USE AND RELEASE OF TRUST ESTATE		52
Section 7.01.	Use, Possession and Disposition of Trust Estate		52
Section 7.02.	Additional Rights and Powers of Company with respect to Trust Estate		52
Section 7.03.	Release of Trust Estate		54
Section 7.04.	Release of Property Taken by Eminent Domain, Etc		55
Section 7.05.	Release of Minor Properties		55
Section 7.06.	Withdrawal or Other Application of Cash		56
Section 7.07.	Disclaimer or Quitclaim		57
Section 7.08.	General Provisions as to Releases		57
Section 7.09.	Exercise of Powers under Article Seven while an Event of Default Exists		57
Section 7.10.	Non-responsibility of Purchasers for Authority of Trustee, etc		58
Section 7.11.	Lien on Reacquired Property		58
Section 7.12.	Separability of Release Provisions		58
ARTICLE EIGHT	SATISFACTION AND DISCHARGE		58
Section 8.01.	Satisfaction and Discharge of Bonds		58
Section 8.02.	Satisfaction and Discharge of Mortgage		61
Section 8.03.	Application of Trust Money		61
Section 8.04.	Payment of Principal and Interest to Holders		62
Section 8.05.	Transfer to Trustee of Moneys Held by Paying Agent		62
Section 8.06.	Repayment to Company of Unclaimed Moneys		62
ARTICLE NINE	EVENTS OF DEFAULT AND REMEDIES		63
Section 9.01.	Default, Acceleration, Rescission of Acceleration		63
Section 9.02.	Power of Trustee Upon Default		64
Section 9.03.	Right to Judicial Sale; Appointment of Receiver		66

iii

Table of Contents

(Continued)

		Page
Section 9.04.	Sale as Entirety or in Parcels		66
Section 9.05.	Notice of Sale		67
Section 9.06.	Adjournment of Sale		67
Section 9.07.	Purchaser Not Liable for Application of Purchase Money		67
Section 9.08.	Application of Bonds toward Purchase Price, etc		67
Section 9.09.	Conveyance of Property to Purchaser		68
Section 9.10.	Sale a Bar against Company		68
Section 9.11.	Application of Proceeds of Sale		68
Section 9.12.	Acceleration of Maturity of Bonds Upon Sale		69
Section 9.13.	Covenants of Company to Pay Bonds, with Interest if any is Due; Proof of Debt by Trustee; Recovery of Judgment by Trustee and Application of Proceeds		69
Section 9.14.	Proceedings by Trustee to Protect Security		71
Section 9.15.	Payment by Trustee or Bondholders of Amounts Payable by Company		71
Section 9.16.	Waiver of Stay or Extension Laws, etc		71
Section 9.17.	Waiver of Service of Process and Consent to Entry of Judgment by Company		71
Section 9.18.	Personal Property Deemed Real Estate		72
Section 9.19.	Surrender of Possession of Trust Estate to Trustee or Receiver		72
Section 9.20.	Rights of Bondholders to Control Proceedings by Trustee		72
Section 9.21.	Limitation on Bondholders’ Right to Sue		73
Section 9.22.	Waiver of Period of Grace by Company		73
Section 9.23.	Waiver of Certain Defaults by Bondholders		74
Section 9.24.	Delay or Omission in Exercising Remedy Not Waiver of Default		74
Section 9.25.	Effect of Abandonment of Foreclosure or Other Proceedings		74
Section 9.26.	Remedies Cumulative		74
Section 9.27.	Rights of Action Enforceable by Trustee without Possession or Production of Bonds		74
Section 9.28.	Remedies in Article Nine Subject to Applicable Laws		74

iv

Table of Contents

(Continued)

ARTICLE TEN	THE TRUSTEE	75
Section 10.01.	Qualifications of Trustee	75
Section 10.02.	Acceptance of Trust and Duties and Responsibility of Trustee before and after Default	75
Section 10.03.	Extent of Liability of Trustee	76
Section 10.04.	Trustee not Responsible for Recitals, etc	77
Section 10.05.	Trustee not Personally Liable in Case of Entry	77
Section 10.06.	Trustee may Rely on Certificates, Opinions, etc., and Consult with Counsel	78
Section 10.07.	Trustee not Responsible for Approval of Experts, etc	78
Section 10.08.	Trustee may Own and Deal in Bonds, etc	78
Section 10.09.	Notice by Trustee to Bondholders of Defaults by Company	78
Section 10.10.	Compensation of Trustee for Services and Expenses; Indemnification; Right of Trustee to File Claim for Compensation	78
Section 10.11.	Certificate of Officers as Evidence of Facts	79
Section 10.12.	Trustee May Give Notices, etc	80
Section 10.13.	Resignation of Trustee	80
Section 10.14.	Removal of Trustee	80
Section 10.15.	Appointment of Successor Trustee	80
Section 10.16.	Co-Trustee and Separate Trustees	81
Section 10.17.	Resignation or Removal of Co-Trustee or Separate Trustee; Appointment of Successor Co-Trustee	82
Section 10.18.	Rights of Co-Trustee Revest in Trustee	82
Section 10.19.	Trustee not Liable for Acts of any other Trustee	83
Section 10.20.	Execution of Supplemental Indenture by Successor Trustee; Further Acts of Assurance and Confirmation	83
Section 10.21.	Merger Resulting in Successor Trustee; Use of Bonds Already Authenticated	83
ARTICLE ELEVEN	HOLDERS’ LISTS AND REPORTS BY THE TRUSTEE AND COMPANY	84
Section 11.01.	Lists of Holders	84
Section 11.02.	Reports by Trustee and Company	84

v

Table of Contents

(Continued)

		Page
ARTICLE TWELVE	CONSOLIDATION, MERGER, CONVEYANCE AND OTHER TRANSFER		85
Section 12.01.	Merger, Consolidation, etc., Permitted; Assumption of Bonds and this Indenture by Successor		85
Section 12.02.	Substitution of Successor for Company		85
Section 12.03.	Rights of Successor in Respect of Property Owned by Company		86
Section 12.04.	Rights of Successor in Respect of Property Owned by it or Merging or Consolidating Corporations		86
Section 12.05.	Rights of Company with Respect to Property Acquired on Merger or Consolidation		86
Section 12.06.	Exchangeability of Bonds for Bonds in New Name		87
Section 12.07.	Opinion of Counsel as to Consolidation, Merger, Sale, Conveyance, Transfer or Lease		87
Section 12.08.	Surrender of Powers under Article Twelve		87
ARTICLE THIRTEEN	SUPPLEMENTAL INDENTURES		87
Section 13.01.	Supplemental Indentures		87
Section 13.02.	Modification of Indenture with Consent of Bondholders		89
Section 13.03.	Effect of Supplemental Indentures		90
Section 13.04.	Opinion of Counsel as Evidence of Compliance with this Article		90
Section 13.05.	Notation on Bonds; Provision for New Bonds		90
ARTICLE FOURTEEN	LIMITATION OF LIABILITY		90
Section 14.01.	Limitations of Liability		90
ARTICLE FIFTEEN	EXECUTION		91
Section 15.01.	Date		91
Section 15.02.	Counterparts		91

vi

THIS TWENTIETH SUPPLEMENTAL INDENTURE, dated as of December 1, 2013, between Tampa Electric Company, as Debtor (its Federal tax number being 59-0475140), a Florida corporation (hereinafter sometimes called the “Company”), whose mailing address is P.O. Box 111, Tampa, Florida 33601, and the address of whose principal place of business is 702 North Franklin Street, Third Floor, TECO Plaza, Tampa, Florida 33602, party of the first part, and U.S. Bank National Association (hereinafter sometimes called the “Trustee”), successor trustee to State Street Bank and Trust Company (formerly State Street Trust Company), solely in its capacity as Trustee, as Mortgagee and Secured Party (its Federal tax number being 31-0841368), a national banking association, having a corporate trust office at One Federal Street, Boston, Massachusetts 02110, party of the second part.

WHEREAS, the Company has heretofore executed and delivered to State Street Trust Company as Trustee and First Savings & Trust Company of Tampa, as Co-Trustee (the Trustee and Co-Trustee being hereinafter sometimes collectively called the “Trustees”) an Indenture of Mortgage dated as of August 1, 1946 (hereinafter called the “Original Indenture”), to secure, as provided therein, its bonds (in the Original Indenture and herein called the “Bonds”), to be designated generally as its “First Mortgage Bonds”, and to be issued in one or more series as provided in the Original Indenture; and

WHEREAS, the Company has heretofore executed and delivered to the Trustee nineteen indentures supplemental (hereinafter sometimes called the “Existing Supplemental Indentures”) including a Sixteenth Supplemental Indenture dated as of October 30, 1992 (the “Sixteenth Supplemental Indenture”) to the Original Indenture and additional notices of extension of lien of indenture (hereinafter sometimes called the “Extension Notices”) for the purpose of better assuring, mortgaging and confirming unto the Trustee certain additional property acquired by the Company since the execution and delivery of the Original Indenture which by the terms of the Original Indenture is or is intended to be subject to the lien thereof; and

WHEREAS, the Original Indenture, the Existing Supplemental Indentures and the Extension Notices heretofore delivered have been recorded in the public records of the counties as specified on Schedule 1 attached hereto and made a part hereof; and

WHEREAS, by resignation dated December 31, 1993, and accepted by the Company and the Trustee on January 5, 1994, Barnett Banks Trust Company, N.A., successor Co-Trustee, resigned as Co-Trustee, and no Co-Trustee has been appointed; and

WHEREAS, by resignation effective as of October 29, 2003, State Street Bank and Trust Company resigned as trustee, and effective on that date, (i) the Company appointed U.S. Bank National Association as successor Trustee and (ii) U.S. Bank National Association accepted the appointment as successor Trustee; and

WHEREAS, pursuant to the Original Indenture, as so supplemented and as supplemented by the Sixteenth Supplemental Indenture, there have been executed, authenticated and delivered and there were last outstanding $75,000,000 aggregate principal amount of 7 3/4% First Mortgage Bonds Series due 2022, being all of the Bonds heretofore issued which remained outstanding, and all of same have been redeemed and, therefore, no Bonds remain “outstanding” on the date hereof as defined in Section 1.02E of the Original Indenture; and

WHEREAS, the Company desires to execute and deliver this Twentieth Supplemental Indenture, in accordance with the provisions of the Original Indenture, for the purpose of amending and restating in its entirety the recitals, granting clauses and Articles One through Nineteen of the Original Indenture as heretofore supplemented and amended, such modifications of covenants and agreements of the Company to be effective immediately (the Original Indenture as supplemented and modified by the aforesaid nineteen and this Twentieth Supplemental Indenture being herein sometimes called the “Indenture”); and

WHEREAS, all acts and proceedings required by law and the Charter and Bylaws of the Company necessary to constitute the Indenture a valid and binding mortgage and deed of trust for the security of the Bonds from time to time outstanding, in accordance with the terms of the Indenture and the terms of the Bonds, have been done and performed; and the execution and delivery of this Twentieth Supplemental Indenture have been in all respects duly authorized;

NOW, THEREFORE, for the purposes aforesaid and in pursuance of the terms and provisions of the Indenture, amending and restating the recitals, granting clauses and Articles One through Nineteen of the Original Indenture as heretofore supplemented and amended, the Company has executed and delivered this Twentieth Supplemental Indenture, and in consideration of the sum of $1 to the Company duly paid by the Trustee at or before the ensealing and delivery hereof and for other good and valuable consideration, the receipt whereof is hereby acknowledged, the Company hereby covenants to and with the Trustee and its successors in the trust under the Indenture, for the equal and pro rata benefit and security of all future holders of all Bonds to be issued under the Indenture, without preference, priority or distinction whatsoever, as follows:

RECITALS

WHEREAS, the Company is authorized by law, and deems it necessary from time to time, to borrow money for its proper corporate purposes, and to mortgage and pledge its property hereinafter described to secure the payment thereof; and to that end, in the exercise of said authority, has duly authorized and directed the creation of multiple series of its bonds, to an amount limited only by the terms of this Indenture of Mortgage, by law and by the Articles of Incorporation of the Company, as from time to time in effect, to be known generally as its First Mortgage Bonds and to be issued in one or more series, and, in order to secure the payment of the principal of and interest on said Bonds (hereinafter called the “Bonds”), to provide for the authentication and delivery thereof by the Trustee and to establish and declare the terms and conditions upon which the Bonds are to be issued and secured, the Company has heretofore duly authorized and directed the execution and delivery of this Indenture of Mortgage; and

WHEREAS, all acts and proceedings required by law and by the Articles of Incorporation, as amended, and by-laws of the Company necessary to constitute this Indenture a valid and binding mortgage for the security of all of the Bonds, in accordance with its and their terms, have been done and taken; and the execution and delivery of this Indenture have been in all respects duly authorized;

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GRANTING CLAUSES

NOW, THEREFORE, THIS INDENTURE WITNESSETH, that in order to secure the payment of the principal of, premium, if any, and interest on all Bonds at any time issued and outstanding under this Indenture according to their tenor, purport and effect, and to secure the performance and observance of all the covenants and conditions therein and herein contained, and to declare the terms and conditions upon and subject to which the Bonds are and are to be issued and secured, and for and in consideration of the premises and of the mutual covenants herein contained and of the purchase and acceptance of the Bonds by the holders thereof, and of the sum of $1 duly paid to the Company by the Trustee, at or before the ensealing and delivery hereof, and for other valuable considerations, the receipt whereof is hereby acknowledged, the Company has executed and delivered this Indenture, and by these presents, does grant, bargain, sell, alien, remise, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto the Trustee, its successors in trust and assigns, the following property, rights, privileges and franchises (which collectively are hereinafter called the “Trust Estate”), to wit:

CLAUSE I.

All the property, real, personal or mixed, tangible or intangible (other than Excepted Property as hereinafter defined) of every kind, character and description which is described in the Schedule of Mortgaged Properties set forth in Article Twenty of the Original Indenture and in all indentures supplemental thereto and other instruments heretofore delivered and recorded.

CLAUSE II.

Without in any way limiting anything in Clause I or hereinafter described, all and singular the lands, real estate, chattels real, interests in land, leaseholds, ways, rights-of-way, grants, easements, servitudes, rights pursuant to ordinances, consents, permits, patents, licenses, lands under water, water and riparian rights, franchises, privileges, immunities, rights to construct, maintain and operate distribution and transmission systems, all other rights and interests, and electric light, heat and power plants and systems, dams and dam sites, stations and substations, powerhouses, electric transmission and distribution lines and systems, pipe lines, conduits, towers, poles, wires, cables and all other structures, machinery, engines, boilers, dynamos, motors, transformers, generators, electric and mechanical appliances, office buildings, warehouses, garages, stables, sheds, shops, tunnels, subways, bridges, other buildings and structures, implements, tools and other apparatus, appurtenances and facilities, materials and supplies and all other property of any nature appertaining to any of the plants, systems, business or operations of the Company, whether or not affixed to the realty, used in the operation of any of the premises or plants or systems, or otherwise, which are now owned or which may hereafter be owned or acquired by the Company, other than Excepted Property as hereinafter defined; including (but not limited to) all its properties situated in the Cities of Tampa, Plant City, Winter Haven and Dade City, and in the Counties of Hillsborough, Manatee, Pasco, Pinellas, Polk, Highlands and Hardee, Florida, and vicinity, and wheresoever situated (other than Excepted Property as hereinafter defined).

-3-

CLAUSE III.

All corporate, Federal, State, municipal and other permits, consents, licenses, bridge licenses, bridge rights, river permits, franchises, patents, rights pursuant to ordinances, grants, privileges and immunities of every kind and description, now belonging to or which may hereafter be owned, held, possessed or enjoyed by the Company (other than Excepted Property as hereinafter defined) and all renewals, extensions, enlargements and modifications of any of them.

CLAUSE IV.

Also all other property, real, personal or mixed, tangible or intangible (other than Excepted Property as hereinafter defined) of every kind, character and description and wheresoever situated, whether or not useful in the generation, manufacture, production, transmission, distribution, sale or supplying electricity, now owned or which may hereafter be acquired by the Company, it being the intention hereof that all property, rights and franchises acquired by the Company after the date hereof (other than Excepted Property as hereinafter defined) shall be as fully embraced within and subjected to the lien hereof as if such property were now owned by the Company and were specifically described herein and conveyed hereby.

CLAUSE V.

Together with (other than Excepted Property as hereinafter defined) all and singular the plants, buildings, improvements, additions, tenements, hereditaments, easements, rights, privileges, licenses and franchises and all other appurtenances whatsoever belonging or in any wise appertaining to any of the property hereby mortgaged or pledged, or intended so to be, or any part thereof, and the reversion and reversions, reservation and reservations, remainder and remainders, and the tolls, rents, revenues, issues, earnings, income, issues, products and profits thereof, and every part and parcel thereof, and all the estate, right, title, interest, possession, property, claim and demand of every nature whatsoever of the Company at law, in equity or otherwise howsoever, in, of and to such property and every part and parcel thereof.

CLAUSE VI.

Also any and all property, real, personal or mixed, including Excepted Property as hereinafter defined, that may, from time to time hereafter, by delivery or by writing of any kind, for the purposes hereof be in any wise subjected to the lien hereof or be expressly conveyed, mortgaged, assigned, transferred, deposited and/or pledged by the Company, or by anyone in its behalf or with its consent, to and with the Trustee, which is hereby authorized to receive the same at any and all times as and for additional security and also, when and as hereinafter provided, as substituted security hereunder, to the extent permitted by law. Such conveyance, mortgage, assignment, transfer, deposit and/or pledge or other creation of lien by the Company or by anyone in its behalf or with its consent of or upon any property as and for additional security may be made subject to any reservations, limitations, conditions and provisions which shall be set forth in an instrument or agreement in writing executed by the Company or the person or corporation conveying, assigning, mortgaging, transferring, depositing and/or pledging the same, respecting the use, management and disposition of the property so conveyed, assigned, mortgaged, transferred, deposited and/or pledged, or the proceeds thereof.

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CLAUSE VII.

EXCEPTED PROPERTY.

There is, however, expressly excepted and excluded from the lien and operation of this Indenture the following described property of the Company, herein sometimes referred to as “Excepted Property”:

A. All property of the character expressly excepted from the lien of this Indenture in the descriptions contained in the “Schedule of Specifically Excepted Properties” in Article Twenty of the Original Indenture, and identified as property excepted from the lien of this Indenture in each indenture supplemental hereto heretofore delivered and recorded;

B. All cash on hand and in banks, all contracts and other choses in action, all general intangibles, all shares of stock, bonds, notes, evidences of indebtedness and other securities and securities entitlements; and bills, notes and accounts receivable, conditional sales contracts or agreements and appliance rental or lease agreements, other than any of the foregoing which are by the express provisions of this Indenture subjected or required to be subjected to the lien hereof;

C. All goods, wares, merchandise, appliances, materials and supplies, manufactured, produced, purchased or acquired for the purpose of sale or lease in the ordinary course of business; and gas, oil, coal and other minerals and other products, fuel, materials, stores and supplies and other personal property which are consumable (otherwise than by ordinary wear and tear) in their use in the operation of the plants or systems of the Company;

D. All oil, gas, coal and other minerals, if any, lying or being within or under any land subject to the lien of this Indenture;

E. Office furniture, office equipment and office supplies;

F. Aircraft, automobiles, trucks and similar vehicles, together with all equipment necessary to the operation and maintenance thereof;

G. The last day of the term of each leasehold estate (oral or written, and/or any agreement therefor) now or hereafter enjoyed by the Company, and whether falling within a general or particular description of property herein;

H. All other property which for some reason (other than that the same constitutes Excepted Property under the preceding paragraphs A to G, inclusive) does not fall within the definition of Bondable Property as hereinafter defined;

I. All property excepted from the lien hereof pursuant to the provisions of Article Twelve.

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The Company may, however, pursuant to the provisions of Granting Clause VI above, subject to the lien and operation of this Indenture all or any part of the Excepted Property.

TO HAVE AND TO HOLD the Trust Estate and all and singular the lands, properties, estates, rights, franchises, privileges and appurtenances hereby mortgaged, conveyed, pledged or assigned, or intended so to be, together with all the appurtenances thereto appertaining and the rents, issues and profits thereof, unto the Trustee and its successors in trust and to its assigns, forever:

SUBJECT, HOWEVER, to the exceptions, reservations, restrictions, conditions, limitations, covenants and matters recited in the Schedule of Mortgaged Properties set forth in Article Twenty of the Original Indenture and in the indentures supplemental thereto and Extension Notices heretofore delivered and recorded, to Permitted Encumbrances as hereinafter defined, and, with respect to any property which the Company may hereafter acquire, to any liens for unpaid portions of the purchase money placed thereon, at the time of such acquisition;

BUT IN TRUST, NEVERTHELESS, for the equal and proportionate use, benefit, security and protection of those who from time to time shall hold the Bonds authenticated and delivered hereunder and duly issued by the Company, without any discrimination, preference or priority of any one Bond over any other by reason of priority in the time of issue, sale or negotiation thereof or otherwise, so that each and all of said Bonds shall have the same right, lien and privilege under this Indenture and shall be equally secured hereby and shall have the same proportionate interest and share in the Trust Estate, with the same effect as if all of the Bonds had been issued, sold and negotiated simultaneously on the date of the delivery hereof;

AND UPON THE TRUSTS, USES AND PURPOSES and subject to the covenants, agreements and conditions hereinafter set forth and declared.

ARTICLE ONE

Definitions and Other Provisions of General Application

Section 1.01. For all purposes of this Indenture, the following terms shall have the following defined meanings:

“Accountant” means a Person engaged in the accounting profession or otherwise qualified to pass on accounting matters (including, but not limited to, a Person certified, registered or licensed as a public accountant, whether or not then engaged in the public accounting profession), which Person, unless required to be Independent, may be an employee or Affiliate of the Company.

“Act” when used with respect to any Holder of a Bond, has the meaning specified in Section 1.06.

“Affiliate” means, at any time, and with respect to any Person, any other Person that at such time directly or indirectly through one or more intermediaries Controls, or is Controlled by, or is under common Control with, such first Person, and, with respect to the Company, shall include any

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Person beneficially owning or holding, directly or indirectly, 10% or more of any class of voting or equity interests of the Company or any corporation of which the Company beneficially owns or holds, in the aggregate, directly or indirectly, 10% or more of any class of voting or equity interests. As used in this definition, “Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise; and the term “Controlled” shall have the meaning correlative to the foregoing. Unless the context otherwise clearly requires, any reference to an “Affiliate” is a reference to an Affiliate of the Company.

“Authenticating Agent” means any Person or Persons (other than the Company or an Affiliate of the Company) authorized by the Trustee to act on behalf of the Trustee to authenticate the Bonds of one or more series.

“Authorized Officer” means the Chairman of the Board, the Vice Chairman, the President, any Vice President, the Chief Financial Officer, the Treasurer, any Assistant Treasurer, the Controller, or any other officer, manager or agent of the Company duly authorized pursuant to a Board Resolution to act in respect of matters relating to this Indenture.

“Available Cash”, at any time, shall mean all cash then held by, or deposited with, the Trustee other than cash so held or deposited pursuant to Section 2.07 or Article Eight.

“Board of Directors” means either the board of directors, board of managers or similar governing body of the Company or any committee thereof duly authorized to act in respect of matters relating to this Indenture.

“Board Resolution” means a copy of a resolution certified by the Secretary, an Assistant Secretary or an Authorized Officer of the Company to have been duly adopted by the Board of Directors and to be in full force and effect on the date of such certification, and delivered to the Trustee.

“Bondable Property” means and comprises any property now owned or hereafter acquired by the Company, located in the United States of America and coastal waters having its protection, which is used by or useful to the Company in the business of furnishing or distributing electricity, (except as provided below) for heat, light, power or other uses, or in any business which is incidental thereto, including, without limiting the generality of the foregoing, all properties necessary or appropriate for purchasing, generating, manufacturing, producing, utilizing, transmitting, supplying, distributing and/or disposing of electricity, together with betterments, improvements, additions, repairs, replacements, or alterations, of, upon and to such property of the Company and equipment and appliances installed as a part of the operating property of the Company; provided that such property shall be property which the Company under its charter and all applicable laws shall be lawfully authorized to own and as to which the Company has or expects to be able to obtain the franchises, licenses, permits and other rights necessary for the maintenance and use thereof. The term Bondable Property shall not be deemed to include any property excepted from the Lien of this Indenture by paragraphs A to G, inclusive, of Clause VII of the Granting Clauses hereof.

“Bonds” means any Bonds authenticated and delivered under this Indenture.

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“Business Day” means any day other than a Saturday, a Sunday or a day on which commercial banks in New York City or in the place in which the Corporate Trust Office is located are required or authorized to be closed, except as may be otherwise specified as contemplated by Section 2.01.

“Commission” means the Securities and Exchange Commission, as from time to time constituted, created under the Exchange Act, or, if at any time after the date hereof such Commission is not existing and performing the duties now assigned to it under the Trust Indenture Act, then the body, if any, performing such duties at such time.

“Company” means Tampa Electric Company, a Florida corporation, until a successor Person shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Company” shall mean such successor Person.

“Company Order” or “Company Request” means, respectively, a written order or request, as the case may be, signed in the name of the Company by an Authorized Officer and delivered to the Trustee.

“Corporate Trust Office” means the office of the Trustee at which at any particular time its corporate trust business shall be principally administered, which office at the date hereof is currently located at One Federal Street, Boston, Massachusetts 02110; provided, however, that for purposes of presentment and surrender of Bonds Outstanding for transfer, exchanges or final payment, such office is currently located at 60 Livingston Avenue, St. Paul, Minnesota 55107, or such other office as the Trustee may designate from time to time by notice to the Company.

“Corporation” means a corporation, association, company, limited liability company, partnership, limited partnership, joint venture, joint stock company or business or statutory trust, and references to “corporate” and other derivations of “Corporation” herein shall be deemed to include appropriate derivations of such entities.

“Cost” with respect to Property Additions has the meaning specified in Section 1.03(c).

“Co-Trustee” has the meaning specified in Section 10.16(a).

“Defaulted Interest” has the meaning specified in Section 2.07(b).

“Depositary” means, with respect to the Bonds of any series issuable or issued in whole or in part in the form of one or more Global Bonds, the Person designated as Depositary by the Company pursuant to Section 2.01 hereof, which must be a clearing agency registered under the Exchange Act, and, if so provided pursuant to Section 2.01 hereof with respect to the Bonds of any series, any successor to such Person. If at any time there is more than one such Person, “Depositary” shall mean, with respect to any series of Bonds, the qualifying entity which has been appointed with respect to the Bonds of that series.

“Discount Bond” means any Bond which provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration of the Maturity thereof pursuant to Section 9.01. “Interest” with respect to a Discount Bond means interest, if any, borne by such Bond at a Stated Interest Rate.

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“Dollar” or “$” means a dollar or other equivalent unit in such coin or currency of the United States of America as at the time shall be legal tender for the payment of public and private debts.

“Earnings Certificate” has the meaning specified in Section 1.04.

“Eligible Obligations” means:

(a) with respect to Bonds denominated in Dollars, Government Obligations or, if specified pursuant to Section 2.01 with respect to any Bonds, other Investment Securities; or

(b) with respect to Bonds denominated in a currency other than Dollars or in a composite currency, such other obligations or instruments as shall be specified with respect to such Bonds, as contemplated by Section 2.01.

“Event of Default” has the meaning specified in Section 9.01.

“Excepted Property” has the meaning set forth in Clause VII of the Granting Clauses:

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Expert” means a Person which is an engineer, appraiser or other expert and which, with respect to any certificate to be signed by such Person and delivered to the Trustee, is qualified to pass upon the matters set forth in such certificate. For purposes of this definition, (a) “engineer” means a Person engaged in the engineering profession or otherwise qualified to pass upon engineering matters (including, but not limited to, a Person licensed as a professional engineer, whether or not then engaged in the engineering profession) and (b) “appraiser” means a Person engaged in the business of appraising property or otherwise qualified to pass upon the Fair Value or fair market value of property.

“Experts’ Certificate” means a certificate signed by an Authorized Officer, by an Accountant and by an Expert (which Accountant and Expert (a) shall be selected either by the Board of Directors or by an Authorized Officer, the execution of such certificate by such Authorized Officer to be conclusive evidence of such selection, and (b) except as otherwise required in Sections 3.02 and 7.08, may be an employee or Affiliate of the Company) and delivered to the Trustee. The amount stated in any Experts’ Certificate as to the Cost, Fair Value or fair market value of property shall be conclusive and binding upon the Company, the Trustee and the Holders of the Bonds.

“Extension Notice” means a notice of the extension of the Lien of this Indenture to property acquired by the Company constituting part of the Trust Estate.

“Fair Value”, with respect to property, means the fair value of such property as determined in the reasonable judgment of the Expert certifying to such value, such determination to be based on any one or more factors deemed relevant by such Expert including, without limitation, (a) the amount which would be likely to be obtained in an arm’s-length transaction with respect to such property between an informed and willing buyer and an informed and willing seller, under no compulsion, respectively, to buy or sell, (b) the amount of investment with respect to such property

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which, together with a reasonable return thereon, would be likely to be recovered through ordinary business operations or otherwise, (c) the cost, accumulated depreciation, and replacement cost with respect to such property and/or (d) any other relevant factors; provided, however, that (x) the Fair Value of property shall be determined without deduction for any Liens on such property prior to the Lien of this Indenture and (y) the Fair Value to the Company of Property Additions may be of less value to a Person which is not the owner or operator of the Trust Estate or any portion thereof than to a Person which is such owner or operator. Fair Value may be determined, without physical inspection, by the use of accounting and engineering records and other data maintained by the Company or otherwise available to the Expert certifying the same.

“Global Bond” means a Bond evidencing all or part of a series of Bonds, issued to the Depositary for such series or its nominee and registered in the name of such Depositary or nominee.

“Governmental Authority” means the government of the United States or of any State or Territory thereof or of the District of Columbia or of any county, municipality or other political subdivision of any thereof, or any department, agency, authority or other instrumentality of any of the foregoing.

“Government Obligations” means securities which are (a) (i) direct obligations of the United States where the payment or payments thereunder are supported by the full faith and credit of the United States or (ii) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States where the timely payment or payments thereunder are unconditionally guaranteed as a full faith and credit obligation by the United States or (b) depository receipts issued by a bank (as defined in Section 3(a)(2) of the Securities Act, which may include the Trustee or any Authenticating Agent or Paying Agent) as custodian with respect to any such Government Obligation or a specific payment of interest on or principal of or other amount with respect to any such Government Obligation held by such custodian for the account of the holder of a depository receipt, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the Government Obligation or the specific payment of interest on or principal of or other amount with respect to the Government Obligation evidenced by such depository receipt.

“Holder” or “Bondholder” means a Person in whose name a Bond is registered in the Security Register.

“Independent”, when applied to any Accountant or Expert, means such a Person who (a) is in fact independent, (b) does not have any direct material financial interest in the Company or in any other obligor upon the Bonds or in any Affiliate of the Company or of such other obligor, (c) is not connected with the Company or such other obligor as an officer, employee, promoter, underwriter, trustee, partner, director or any person performing similar functions and (d) shall be reasonably acceptable to the Trustee. The acceptance by the Trustee of an opinion or certificate of an Independent Person shall be sufficient evidence that such Independent Person has been approved by the Trustee.

“Independent Experts’ Certificate” means a certificate signed by an Expert who is Independent and delivered to the Trustee.

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“Interest Payment Date”, when used with respect to any Bond, means the Stated Maturity of an installment of interest on such Bond.

“Investment Securities” means any of the following obligations or securities on which neither the Company, any other obligor on the Bonds nor any Affiliate of either is the obligor: (a) Government Obligations; (b) interest bearing deposit accounts (which may be represented by certificates of deposit) in any national or state bank (which may include the Trustee or any Authenticating Agent or Paying Agent) or savings and loan association whose outstanding securities (or securities of the bank holding company owning all of the capital stock of such bank or savings and loan association) are rated by a nationally recognized rating organization in either of the two highest rating categories (without regard to modifiers) for short-term securities or in any of the three highest rating categories (without regard to modifiers) for long-term securities; (c) bankers’ acceptances drawn on and accepted by any commercial bank (which may include the Trustee or any Authenticating Agent or Paying Agent) whose outstanding securities (or securities of the bank holding company owning all of the capital stock of such commercial bank) are rated by a nationally recognized rating organization in either of the two highest rating categories (without regard to modifiers) for short-term securities or in any of the three highest rating categories (without regard to modifiers) for long-term securities; (d) direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, any State or Territory of the United States or the District of Columbia, or any political subdivision of any of the foregoing, which are rated by a nationally recognized rating organization in either of the two highest rating categories (without regard to modifiers) for short-term securities or in any of the three highest rating categories (without regard to modifiers) for long-term securities; (e) bonds or other obligations of any agency or instrumentality of the United States; (f) corporate debt securities which are rated by a nationally recognized rating organization in either of the two highest rating categories (without regard to modifiers) for short-term securities or in any of the three highest rating categories (without regard to modifiers) for long-term securities; (g) repurchase agreements with respect to any of the foregoing obligations or securities with any banking or financial institution (which may include the Trustee or any Authenticating Agent or Paying Agent) whose outstanding securities (or securities of the bank holding company owning all of the capital stock of such bank or financial institution) are rated by a nationally recognized rating organization in either of the two highest rating categories (without regard to modifiers) for short-term securities or in any of the three highest rating categories (without regard to modifiers) for long-term securities; (h) securities issued by any regulated investment company (including any investment company for which the Trustee or any Authenticating Agent or Paying Agent is the advisor), as defined in Section 851 of the Internal Revenue Code of 1986, as amended, or any successor section of such Code or successor federal statute, provided that the portfolio of such investment company is limited to obligations or securities of the character and investment quality contemplated in clauses (a) through (f) above and repurchase agreements which are fully collateralized by any of such obligations or securities; and (i) any other obligations or securities which may lawfully be purchased by the Trustee in its capacity as such.

“Lien” means any mortgage, deed of trust, pledge, security interest, encumbrance, easement, lease, reservation, restriction, servitude, charge or similar right and any other lien of any kind, including, without limitation, any conditional sale or other title retention agreement, any lease in the nature thereof, and any defect, irregularity, exception or limitation in record title.

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“Maturity”, when used with respect to any Bond, means the date on which the principal of such Bond or an installment of principal becomes due and payable as provided in such Bond or in this Indenture, whether at the Stated Maturity, by declaration of acceleration, upon call for redemption or otherwise.

“Officers’ Certificate” means a certificate signed by any two Authorized Officers of the Company and delivered to the Trustee.

“Opinion of Counsel” means a written opinion of counsel, who may be counsel for the Company.

“Outstanding” means, with reference to Bonds, as of the date of determination, all Bonds theretofore authenticated and delivered under this Indenture, except:

(a) Bonds theretofore canceled or delivered to the Security Registrar for cancellation;

(b) Bonds deemed to have been paid for all purposes of this Indenture in accordance with Section 8.01 (whether or not the Company’s indebtedness in respect thereof shall be satisfied and discharged for any other purpose); and

(c) Bonds, the principal, premium, if any, and interest, if any, which have been fully paid pursuant to Section 2.06(c) or in exchange for or in lieu of which other Bonds have been authenticated and delivered pursuant to this Indenture, other than any such Bonds in respect of which there shall have been presented to the Trustee proof satisfactory to it and the Company that such Bonds are held by a bona fide purchaser or purchasers in whose hands such Bonds are valid obligations of the Company;

provided, however, that in determining whether or not the Holders of the requisite principal amount of the Bonds Outstanding under this Indenture, or the Bonds Outstanding of any series, have given any request, demand, authorization, direction, notice, consent or waiver hereunder or whether or not a quorum is present at a meeting of Holders of Bonds:

(x) Bonds owned by the Company or any other obligor upon the Bonds or any Affiliate of the Company or of such other obligor (unless the Company, such Affiliate or such obligor owns all Bonds Outstanding under this Indenture, or (except for the purposes of actions to be taken by Holders of more than one series voting as a class under Section 13.02) all Bonds Outstanding of each such series, determined without regard to this clause (x)) shall be disregarded and deemed not to be Outstanding, except that, in determining whether the Trustee shall be protected in relying upon any such request, demand, authorization, direction, notice, consent or waiver or upon any such determination as to the presence of a quorum, only Bonds which the Responsible Officer of the Trustee actually knows to be so owned shall be so disregarded; provided, however, that Bonds so owned which have been pledged in good faith may be regarded as Outstanding if it is established to the reasonable satisfaction of the Trustee that the pledgee, and not the Company, or any such other obligor or Affiliate of either thereof, has the right so to act with respect to such Bonds and that the pledgee is not the Company or any other obligor upon the Bonds or any Affiliate of the Company or of such other obligor; and provided, further, that in no event shall any Bond which shall have been delivered to evidence or secure, in whole or in part, the Company’s obligations in respect of other indebtedness be deemed to be owned by the Company if the principal of such Bond is payable,

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whether at Stated Maturity or upon mandatory redemption, at the same time as the principal of such other indebtedness is payable, whether at Stated Maturity or upon mandatory redemption or acceleration, but only to the extent of such portion of the principal amount of such Bond as does not exceed the principal amount of such other indebtedness;

(y) the principal amount of a Discount Bond that shall be deemed to be Outstanding for such purposes shall be the amount of the principal thereof that would be due and payable as of the date of such determination upon a declaration of acceleration of the Maturity thereof pursuant to Section 9.01; and

(z) the principal amount of any Bond which is denominated in a currency other than Dollars or in a composite currency that shall be deemed to be Outstanding for such purposes shall be the amount of Dollars which could have been purchased by the principal amount (or, in the case of a Discount Bond, the Dollar equivalent on the date determined as set forth below of the amount determined as provided in (y) above) of such currency or composite currency evidenced by such Bond, in each such case certified to the Trustee in an Officers’ Certificate, based (i) on the average of the mean of the buying and selling spot rates quoted by three banks which are members of the New York Clearing House Association selected by the Company in effect at 11:00 A.M. (New York time) in The City of New York on the fifth Business Day preceding any such determination or (ii) if on such fifth Business Day it shall not be possible or practicable to obtain such quotations from such three banks, on such other quotations or alternative methods of determination which shall be as consistent as practicable with the method set forth in (i) above;

provided, further, that in the case of any Bond the principal of which is payable from time to time without presentment or surrender, the principal amount of such Bond that shall be deemed to be Outstanding at any time for all purposes of this Indenture shall be the original principal amount thereof less the aggregate amount of principal thereof theretofore paid.

“Outstanding” means, with reference to Prior Lien Indebtedness, as of the date of determination, all Prior Lien Indebtedness authenticated and delivered by the trustee under the lien securing the same, or, if there be no such trustee, all Prior Lien Indebtedness theretofore issued or incurred under any such Lien, except (a) Prior Lien Indebtedness theretofore cancelled, (b) Prior Lien Indebtedness issued in substitution for lost, destroyed or mutilated evidences thereof, (c) Prior Lien Indebtedness pledged hereunder, (d) Prior Lien Indebtedness held uncancelled by the trustee under a Prior Lien (on the same property as that securing the Prior Lien indebtedness so held) under conditions such that no transfer of ownership or possession thereof is permissible, except upon a default under such Lien, or except to the Trustee hereunder, or to the trustee or other holder of another Prior Lien on the same property for cancellation or to be held uncancelled under like conditions under the terms of such other Lien, and (e) Prior Lien Indebtedness for the payment or redemption or other retirement of which provision shall have been made by the deposit of cash with the Trustee hereunder or with the trustee under the Lien securing the same, provided that if such Prior Lien Indebtedness is to be redeemed, notice of such redemption shall have been duly given or provision satisfactory to the Trustee for the giving of such notice shall have been made.

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“Paying Agent” means any Person, including the Company, authorized by the Company to pay the principal of, and premium, if any, or interest, if any, on any Bonds on behalf of the Company.

“Permitted Encumbrances” shall mean as of any particular time any of the following:

(1) Liens for taxes, assessments, or governmental charges for the then current year and taxes, assessments or governmental charges not then delinquent; and Liens for taxes, assessments or governmental charges already delinquent, but whose validity is at the time being contested in good faith by the Company as provided in Section 6.05;

(2) Liens and charges incidental to construction or current operation which have not at such time been filed or asserted or the payment of which has been adequately secured or which, in the opinion of counsel, are insignificant in amount;

(3) Liens, securing obligations neither assumed by the Company nor on account of which it customarily pays interest directly or indirectly, existing, either at the date hereof, or, as to property hereafter acquired, at the time of acquisition by the Company, upon real estate or rights in or relating to real estate acquired by the Company for substation or transmission, distribution or other right of way purposes;

(4) Any right which any municipal or governmental body or agency may have by virtue of any franchise, license, contract or statute to purchase, or designate a purchaser of or order the sale of, any property of the Company upon payment of reasonable compensation therefor, or to terminate any franchise, license or other rights or to regulate the property and business of the Company;

(5) The Lien of judgments covered by insurance or if not so covered not exceeding at any one time $50,000,000 in aggregate amount;

(6) Easements or reservations in respect of any property of the Company for the purpose of rights of way, including overhead and underground transmission and distribution lines, and similar purposes, zoning ordinances, regulations, reservations, restrictions, covenants, party wall agreements, conditions of record and other encumbrances (other than to secure the payment of money), which in the opinion of counsel (at the time of the acquisition of the property affected or subsequently) will not interfere with the proper operation and development of the property affected thereby;

(7) Any Lien or encumbrance, moneys sufficient for the discharge of which have been deposited in trust with the Trustee hereunder or with the trustee or mortgagee under the instrument evidencing such Lien or encumbrance, with irrevocable authority to the Trustee hereunder or to such other trustee or mortgagee to apply such moneys to the discharge of such Lien or encumbrance to the extent required for such purpose;

(8) Any Lien reserved as security for rent or for compliance with other provisions of the lease in the case of any leasehold estate;

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(9) Any exceptions, reservations and other matters described in the Schedule of Mortgaged Properties set forth in Article Twenty hereof and in Supplemented Indentures and Extension Notices heretofore delivered, and, with respect to any property which the Company may hereafter acquire, any terms, conditions, agreements, covenants, exceptions and reservations expressed or provided in the deeds or other instruments, respectively, under and by virtue of which the Company shall hereafter acquire the same, which, in the opinion of counsel, will not materially adversely affect the Trust Estate or the operation thereof by the Company; and

(10) The undivided interests of other owners, and Liens on such undivided interests, in property owned jointly or in common with the Company whether or not the Company is presently entitled to require partition of such property.

“Person” means any individual, Corporation or any Governmental Authority.

“Place of Payment”, when used with respect to the Bonds of any series, or thereof, means the place or places, specified as contemplated by Section 2.01, at which, subject to Section 6.02, principal of and premium, if any, and interest, if any, on the Bonds of such series or are payable.

“Predecessor Bond” of any particular Bond means every previous Bond evidencing all or a portion of the same debt as that evidenced by such particular Bond; and, for the purposes of this definition, any Bond authenticated and delivered under Section 2.06 in exchange for or in lieu of a mutilated, destroyed, lost or stolen Bond shall be deemed to evidence the same debt as the mutilated, destroyed, lost or stolen Bond.

“Prior Lien” means any Lien securing Prior Lien Indebtedness.

“Prior Lien Indebtedness” means indebtedness secured by a mortgage or other Lien, other than Permitted Encumbrances, prior to the Lien of this Indenture, upon any Trust Estate of the Company, whether or not assumed by the Company or placed thereon to secure unpaid portions of the purchase price, at the time of such acquisition.

“Property Additions” has the meaning specified in Section 1.03.

“Redemption Date”, when used with respect to any Bond to be redeemed, means the date fixed for such redemption by or pursuant to this Indenture.

“Redemption Price”, when used with respect to any Bond to be redeemed, means the price at which it is to be redeemed pursuant to this Indenture, exclusive of accrued and unpaid interest.

“Regular Record Date” for the interest payable on any Interest Payment Date on the Bonds of any series means the date specified for that purpose as contemplated by Section 2.01.

“Required Currency” has the meaning specified in Section 2.11.

“Responsible Officer”, when used with respect to the Trustee, means any officer within the corporate trust group of the Trustee (or any successor group of the Trustee) with direct responsibility for the administration of this Indenture and also means, with respect to a particular corporate trust matter, any other officer to whom such matter is referred because of his knowledge of and familiarity with the particular subject.

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“Securities Act” means the Securities Act of 1933, as amended.

“Security Register” and “Security Registrar” have the respective meanings specified in Section 2.05.

“Special Record Date” for the payment of any Defaulted Interest on the Bonds of any series means a date fixed by the Trustee pursuant to Section 2.07(b)(i).

“Stated Interest Rate” means a rate (whether fixed or variable) at which an obligation by its terms is stated to bear simple interest. Any calculation or other determination to be made under this Indenture by reference to the Stated Interest Rate on a Bond shall be made without regard to the effective interest cost to the Company of such Bond and without regard to the Stated Interest Rate on, or the effective cost to the Company of, any other indebtedness the Company’s obligations in respect of which are evidenced or secured in whole or in part by such Bond.

“Stated Maturity”, when used with respect to any Bond or any obligation or any installment of principal thereof or interest thereon, means the date on which the principal of such obligation or such installment of principal or interest is stated to be due and payable (without regard to any provisions for redemption, prepayment, acceleration, purchase or extension).

“Successor Company” has the meaning set forth in Section 12.01.

“Supplemental Indenture”, “Supplemental Indenture” or “indenture supplemental hereto” means an instrument supplementing or amending this Indenture executed and delivered pursuant to Article Fourteen.

“Trust Estate” means, as of any particular time, all property which at such time is subject to the Lien of this Indenture.

“Trustee” means U.S. Bank National Association, a national banking association, until a successor Trustee shall have been appointed by the Bondholders or the Company pursuant to Section 10.15 or otherwise have become such with respect to one or more series of Bonds pursuant to the applicable provisions of this Indenture, including Section 10.21, and thereafter “Trustee” shall mean or include each Person who is then a Trustee hereunder, and if at any time there is more than one such Person, “Trustee” as used with respect to the Bonds of any series shall mean the Trustee with respect to Bonds of that series.

“Trust Indenture Act” means, as of any time, the Trust Indenture Act of 1939, as amended, as in effect at such time.

“United States” means the United States of America, its territories, its possessions and other areas subject to its jurisdiction.

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Section 1.02. Uses of Terms.

For all purposes of this Indenture, except as otherwise expressly provided or unless the context otherwise requires:

(a) the terms defined in this Article have the meanings assigned to them in this Article and include the plural as well as the singular;

(b) all terms used herein without definition which are defined in the Trust Indenture Act, either directly or by reference therein, have the meanings assigned to them therein;

(c) all terms used herein without definition which are defined in the Uniform Commercial Code of Florida as in effect on the date hereof shall have the meanings assigned to them therein;

(d) all accounting terms not otherwise defined herein have the meanings assigned to them in accordance with generally accepted accounting principles in the United States, and, except as otherwise herein expressly provided, the term “generally accepted accounting principles” with respect to any computation required or permitted hereunder shall mean such accounting principles as are generally accepted in the United States at the date of such computation; provided, however, that in determining generally accepted accounting principles applicable to the Company, effect shall be given, to the extent required, to any order, rule or regulation of any administrative agency, regulatory authority or other governmental body having jurisdiction over the Company;

(e) the table of contents and headings are for reference purposes only and shall not in any way affect the meaning or interpretation of this Indenture;

(f) any reference to an “Article” or a “Section” refers to an Article or a Section, as the case may be, of this Indenture; and

(g) the words “herein”, “hereof” and “hereunder” and other words of similar import refer to this Indenture as a whole and not to any particular Article, Section or other subdivision.

Section 1.03. Property Additions; Cost.

(a) The term “Property Additions” shall mean and comprise only Bondable Property which shall have been purchased, constructed or otherwise acquired (including acquisition by merger or consolidation) by the Company, including property then in the process of construction in so far as actually constructed subsequent to said date, and the Cost of which is properly chargeable to plant accounts, as further provided in this Paragraph (a).

(i) All property of the character herein described as Property Additions owned by any Successor Company immediately prior to the time it shall become such Successor Company as provided in Article Twelve which shall have been subjected to the Lien of this Indenture as provided in Section 12.04 shall be deemed to be Property Additions acquired by such Successor Company at the date upon which it became such Successor Company and for the purposes of Section 1.04 and of Section 3.02 shall be treated as property used or operated by others in a business similar to that in which it is used or operated by the Company.

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(ii) Property Additions need not consist of a specific or complete accession, addition or improvement or complete new property but may include construction work in progress for which the Company has permits, licenses, franchises or similar rights adequate to construct the same, if carried in plant accounts in accordance with generally accepted accounting principles, whether capable of complete description and identification or not, and may include property purchased, constructed or acquired to renew or replace property retired by the Company.

(iii) The term Property Additions shall be deemed to include

(A) the interest of the Company in property owned jointly or in common with other parties (and the Company’s undivided interest in the title thereto shall be deemed good title for the purposes of this Indenture); and

(B) paving, grading and other improvements to public highways, streets and alleys and other public lands required for or in connection with the installation or repair of overhead, surface or underground facilities of the Company and paid for by the Company (notwithstanding the fact that title thereto may not be in the Company).

(iv) The term Property Additions shall not be deemed to include any plant, system or other property in which the Company shall acquire only a leasehold interest, or, unless the same shall be movable physical property and shall constitute personal property, any betterments, extensions, improvements or additions of, upon or to any plant, system or property in which the Company shall hold only a leasehold interests or governmental or municipal franchises, permits or similar rights, as such, separate and distinct from the property operated thereunder; but there shall not be excluded from Property Additions any equipment or other property of the Company by reason of the fact that it may be located in, upon or under any public highway or customer’s premises or other places not owned by the Company.

(v) In case of any application for any issuance of Bonds or release of Available Cash upon the basis of Property Additions, any Property Additions to be acquired or becoming such concurrently with the granting of the application may, at the Company’s option, be considered and treated as already acquired for the purpose of computing Property Additions hereunder.

(vi) Bondable Property subject to any Prior Lien shall not be deemed to be Property Additions for any of the purposes of this Indenture unless and until such Prior Lien is paid or otherwise satisfied or all the Prior Lien Indebtedness secured thereby has ceased to be Outstanding.

(b) When the aggregate amount of any Property Additions are calculated for any purpose under the Indenture, there shall be deducted from the Cost or Fair Value to the Company thereof, as the case may be (as of the date so calculated), an amount equal to all related reserves

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(estimated, if necessary, as to particular property) for depreciation, depletion, obsolescence or amortization recorded on the books of the Company as of the date so calculated in respect of such Property Additions which have not theretofore been deducted from the Cost or Fair Value of Property Additions theretofore so calculated.

(c) Except as otherwise provided in Section 7.03, the term “Cost” with respect to Property Additions shall mean the sum of (i) any cash delivered in payment therefor or for the acquisition thereof, (ii) an amount equivalent to the fair market value in cash (as of the date of delivery) of any securities or other property delivered in payment therefor or for the acquisition thereof, (iii) the principal amount of any other obligations incurred or assumed in connection with the payment for such Property Additions or for the acquisition thereof and (iv) any other amounts which, in accordance with generally accepted accounting principles, are properly charged or chargeable to the plant or other property accounts of the Company with respect to such Property Additions as part of the cost of construction or acquisition thereof, including, but not limited to, any allowance for funds used during construction or any similar or analogous amount; provided, however, that, notwithstanding any other provision of this Indenture,

(i) with respect to Property Additions owned by a Successor Company immediately prior to the time it shall have become such by consolidation or merger or acquired by a Successor Company in or as a result of a consolidation or merger (excluding, in any case, Property Additions owned by the Company immediately prior to such time), Cost shall mean the amount or amounts at which such Property Additions are recorded in the plant or other property accounts of such Successor Company, or the predecessor Corporation from which such Property Additions are acquired, as the case may be, immediately prior to such consolidation or merger;

(ii) with respect to Property Additions which shall have been acquired (otherwise than by construction) by the Company without any consideration consisting of cash, securities or other property or the incurring or assumption of indebtedness, no determination of Cost shall be required, and, wherever in this Indenture provision is made for Cost or Fair Value, Cost with respect to such Property Additions shall mean an amount equal to the Fair Value to the Company thereof or, if greater, the aggregate amount reflected in the Company’s books of account with respect thereto upon the acquisition thereof;

(iii) in cases where different classes or kinds of property have been acquired for a consideration not divided among the respective classes or kinds of property acquired, the Company may allocate on its books in any reasonable manner consistent with generally accepted accounting principles the Cost of the property comprising the different classes and kinds of property; the Company may from time to time classify or reclassify any property so acquired in accordance with the requirements of any regulatory authority having jurisdiction over the accounts of the Company, and the Cost as so allocated, classified, or reclassified shall be deemed to be the cost of the respective classes or kinds of property; and if the Cost of any property is not separately shown by the books of the Company, an estimate may be used; and

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(iv) in no event shall the Cost of Property Additions be required to reflect any adjustment to the amount or amounts at which such Property Additions are recorded in plant or other property accounts due to the non-recoverability of investment or otherwise.

(d) If any Property Additions are shown by the Experts’ Certificate provided for in Section 3.02(e)(iv) to include property which has been used or operated by others than the Company in a business similar to that in which it has been or is to be used or operated by the Company, the Cost thereof need not be reduced by any amount in respect of any goodwill, going concern value, franchises, contracts, operating agreements and other rights and/or intangible property simultaneously acquired for which no separate or distinct consideration shall have been paid or apportioned, and in such case the term Property Additions as defined herein may include such goodwill, going concern value, rights and intangible property.

Section 1.04. Earnings Certificate, Net Earnings Available for Interest.

(a) The term “Earnings Certificate” shall mean an Officers’ Certificate (which, unless one of the Authorized Officers signing the same is an Accountant, shall also be signed by an Accountant), dated not more than 30 days prior to the date upon which application is made for the authentication and delivery of Bonds on the basis of such certificate and dated subsequent to the last previous date upon which any Bonds have been authenticated and delivered hereunder, containing the statements required by Section 1.05(b) and setting forth in reasonable detail:

(i) The net earnings of the Company available for interest, computed as hereinafter provided, for a period of 12 consecutive calendar months within the 15 calendar months immediately preceding the calendar month in which the application for authentication and delivery of Bonds is made.

(ii) The annual “interest charges on bonded indebtedness”, which term shall mean the aggregate annual interest charges on

(A) all Bonds Outstanding hereunder at the date of said certificate;

(B) all Bonds whose authentication and delivery are applied for in such application or in any other pending application; and

(C) all Outstanding Prior Lien Indebtedness;

excluding, however, from such computation the annual interest charges on any Bond or Prior Lien Indebtedness which is to be paid, redeemed or otherwise retired or provision for the retirement of which is to be made, so that the same will cease to be Outstanding as herein defined, prior to or concurrently with the authentication and delivery of the Bonds applied for.

(iii) That such net earnings available for interest are at least twice the aggregate of such annual interest charges on bonded indebtedness.

(iv) That such net earnings available for interest have been computed as provided in this Section.

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(b) If the aggregate principal amount of Bonds being applied for plus the aggregate principal amount of Bonds authenticated and delivered since the commencement of the then current calendar year (other than Bonds with respect to which an Earnings Certificate is not required or with respect to which an Earnings Certificate signed by an Independent Accountant has been previously furnished) is 10% or more of the aggregate principal amount of the Bonds at the time Outstanding hereunder, and if the 12 months’ period in respect of which the net earnings are being calculated is a period with respect to which an annual report is required to be filed by the Company pursuant to Section 11.02(c), then such Earnings Certificate shall be signed by an Independent Accountant, in addition to being signed as hereinabove required.

(c) Net earnings available for interest shall be computed in accordance with generally accepted accounting principles (a) by deducting, from the total operating revenues of the Company for the period in question derived from the Trust Estate an amount equal to the total operating expenses applicable to the Trust Estate for such period, including (i) all taxes other than income, excess profits and other taxes imposed on or measured by income or undistributed earnings or income; (ii) rentals, insurance, current repairs and maintenance; and (iii) provision for depreciation of the property from which such operating revenues were derived, which shall be the amount actually charged by the Company on its books of account, but excluding any charges on account of interest on indebtedness or on account of debt discount and expense; and (b) by adding to the amount so determined net operating income and revenue from the operation of property not included in the Trust Estate and other income net, to an amount not exceeding 15% of the total of net earnings available for interest, including such income so added. Profits or losses from the sale, abandonment, amortization, retirement or other disposition of capital assets or taxes in respect of any such profits or any amortization or elimination of intangibles or adjustment accounts shall not be taken into account in determining net earnings available for interest.

(d) In case any item of income or expense is not segregated on the books of the Company as between the operation of property which is and property which is not a part of the Trust Estate, the Company may allocate such expense or income in any reasonable manner.

(e) If the Company shall have acquired, within or after the period for which net earnings available for interest is being determined, or will acquire in connection with the issuance of the Bonds being applied for, properties which within six months prior to such acquisition were used or operated in a business similar to that in which they are or are to be used or operated by the Company, then, in computing net earnings available for interest, the net earnings of such properties for the whole of such period shall be included as if such properties had been owned by the Company during the whole of such period; and if, within or after said period, any substantial portion of the properties of the Company shall have been disposed of by the Company, and if the amount of earnings of such properties is capable of being separately determined in accordance with sound accounting practice, then in computing net earnings available for interest, the net earnings of such properties for such period shall be excluded.

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Section 1.05. Compliance Certificates and Opinions; Form of Documents Delivered to Trustee

(a) Except as otherwise expressly provided in this Indenture, upon any application or request by the Company to the Trustee to take any action under any provision of this Indenture, the Company shall furnish to the Trustee an Officers’ Certificate stating that in the opinion of the Authorized Officers executing such Officers’ Certificate all conditions precedent, if any, provided for in this Indenture relating to the proposed action (including any covenants compliance with which constitutes a condition precedent) have been complied with and an Opinion of Counsel stating that in the opinion of such counsel all such conditions precedent, if any, have been complied with, except that in the case of any such application or request as to which the furnishing of such documents is specifically required by any provision of this Indenture relating to such particular application or request, no additional certificate or opinion need be furnished.

(b) Every certificate or opinion with respect to compliance with a condition or covenant provided for in this Indenture shall include:

(i) a statement that each Person signing such certificate or opinion has read such covenant or condition and the definitions herein relating thereto;

(ii) a brief statement as to the nature and scope of the examination or investigation upon which the statements or opinions contained in such certificate or opinion are based;

(iii) a statement that, in the opinion of each such Person, such Person has made such examination or investigation as is necessary to enable such Person to express an informed opinion as to whether or not such covenant or condition has been complied with; and

(iv) a statement as to whether, in the opinion of each such Person, such condition or covenant has been complied with.

(c) Any Officers’ Certificate may be based (without further examination or investigation), insofar as it relates to or is dependent upon legal matters, upon an opinion of, or representations by, counsel, and, insofar as it relates to or is dependent upon matters which are subject to verification by Accountants, upon a certificate or opinion of, or representations by, an Accountant, and insofar as it relates to or is dependent upon matters which are required in this Indenture to be covered by a certificate or opinion of, or representations by, an Expert, upon the certificate or opinion of, or representations by, an Expert, unless, in any case, either such Authorized Officer has actual knowledge that the certificate or opinion or representations with respect to the matters upon which such Officers’ Certificate may be based as aforesaid are erroneous.

(d) Any Experts’ Certificate may be based (without further examination or investigation), insofar as it relates to or is dependent upon legal matters, upon an opinion of, or representations by, counsel, and insofar as it relates to or is dependent upon factual matters, information with respect to which is in the possession of the Company and which are not subject

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to verification by Experts, upon a certificate or opinion of, or representations by, an officer or officers of the Company, unless such Expert has actual knowledge that the certificate or opinion or representations with respect to the matters upon which his certificate or opinion may be based as aforesaid are erroneous.

(e) Any certificate of an Accountant may be based (without further examination or investigation), insofar as it relates to or is dependent upon legal matters, upon an opinion of, or representations by, counsel, and in so far as it relates to or is dependent upon factual matters, information with respect to which is in the possession of the Company and which are not subject to verification by Accountants, upon a certificate of, or representations by, an officer or officers of the Company, unless such Accountant has actual knowledge that the certificate or opinion or representations with respect to the matters upon which his certificate or opinion may be based as aforesaid are erroneous.

(f) Any Opinion of Counsel may be based (without further examination or investigation), insofar as it relates to or is dependent upon factual matters, information with respect to which is in the possession of the Company, upon a certificate of, or representations by, an officer or officers of the Company, and, insofar as it relates to or is dependent upon matters which are subject to verification by Accountants upon a certificate or opinion of, or representations by, an Accountant, and, insofar as it relates to or is dependent upon matters required in this Indenture to be covered by a certificate or opinion of, or representations by, an Expert, upon the certificate or opinion of, or representations by, an Expert, unless such counsel has actual knowledge that the certificate or opinion or representations with respect to the matters upon which his opinion may be based as aforesaid are erroneous. In addition, any Opinion of Counsel may be based (without further examination or investigation), insofar as it relates to or is dependent upon matters covered in an Opinion of Counsel rendered by other counsel, upon such other Opinion of Counsel, unless such counsel has actual knowledge that the Opinion of Counsel rendered by such other counsel with respect to the matters upon which his Opinion of Counsel may be based as aforesaid are erroneous. Further, any Opinion of Counsel with respect to the status of title to or the sufficiency of descriptions of property, and/or the existence of Liens thereon, and/or the recording or filing of documents, and/or any similar matters, may be based (without further examination or investigation) upon (i) title insurance policies or commitments and reports, abstracts of title, lien search certificates and other similar documents or (ii) certificates of, or representations by, officers, employees, agents and/or other representatives of the Company or (iii) any combination of the documents referred to in (i) and (ii), unless, in any case, such counsel has actual knowledge that the document or documents with respect to the matters upon which his opinion may be based as aforesaid are erroneous. If, in order to render any Opinion of Counsel provided for herein, the signer thereof shall deem it necessary that additional facts or matters be stated in any Officers’ Certificate, certificate of an Accountant or Experts’ Certificate provided for herein, then such certificate may state all such additional facts or matters as the signer of such Opinion of Counsel may request.

(g) In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give

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an opinion as to such matters in one or several documents. Where (i) any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Indenture, or (ii) two or more Persons are each required to make, give or execute any such application, request, consent, certificate, statement, opinion or other instrument, any such applications, requests, consents, certificates, statements, opinions or other instruments may, but need not, be consolidated and form one instrument.

(h) Whenever, subsequent to the receipt by the Trustee of any Board Resolution, Officers’ Certificate, Experts’ Certificate, Opinion of Counsel or other document or instrument, a clerical, typographical or other inadvertent or unintentional error or omission shall be discovered therein, a new document or instrument may be substituted therefor in corrected form with the same force and effect as if originally filed in the corrected form and, irrespective of the date or dates of the actual execution and/or delivery thereof, such substitute document or instrument shall be deemed to have been executed and/or delivered as of the date or dates required with respect to the document or instrument for which it is substituted. Anything in this Indenture to the contrary notwithstanding, if any such corrective document or instrument indicates that action has been taken by or at the request of the Company which could not have been taken had the original document or instrument not contained such error or omission, the action so taken shall not be invalidated or otherwise rendered ineffective but shall be and remain in full force and effect, except to the extent that such action was a result of willful misconduct or bad faith. Without limiting the generality of the foregoing, any Bonds issued under the authority of such defective document or instrument shall nevertheless be the valid obligations of the Company entitled to the benefits of this Indenture equally and ratably with all other Outstanding Bonds, except as aforesaid.

Section 1.06. Acts of Holders.

(a) Any request, demand, authorization, direction, notice, consent, election, waiver or other action provided by this Indenture to be made, given or taken by Holders may be embodied in and evidenced by one or more instruments of substantially similar tenor signed by such Holders in person or by an agent duly appointed in writing. Except as herein otherwise expressly provided, such action shall become effective when such instrument or instruments or record or both are delivered to the Trustee and, where it is hereby expressly required, to the Company. Such instrument or instruments (and the action embodied therein and evidenced thereby) are herein sometimes referred to as the “Act” of the Holders signing such instrument or instruments. Proof of execution of any such instrument or of a writing appointing any such agent, or of the holding by any Person of a Bond, shall be sufficient for any purpose of this Indenture and (subject to Sections 10.02 and 10.03) conclusive in favor of the Trustee and the Company, if made in the manner provided in this Section. Without limiting the generality of the foregoing, unless otherwise established in or pursuant to a Board Resolution or set forth or determined in an Officers’ Certificate, or established in one or more Supplemental Indentures, pursuant to Section 2.01 hereof, a Holder, including a Depositary that is a Holder of a Global Bond, may make, give or take, by a proxy, or proxies, duly appointed in writing, any request, demand, authorization, direction, notice, consent, waiver or other action provided in this Indenture to be made, given or taken by Holders, and a Depositary that is a Holder of a Global Bond may provide its proxy or proxies to the beneficial owners of interests in any such Global Bond through such Depositary’s standing instructions and customary practices.

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(b) The fact and date of the execution by any Person of any such instrument or writing may be proved by the affidavit of a witness of such execution or by a certificate of a notary public or other officer authorized by law to take acknowledgments of deeds, certifying that the individual signing such instrument or writing acknowledged to him the execution thereof or may be proved in any other manner which the Trustee and the Company deem sufficient. Where such execution is by a signer acting in a capacity other than his individual capacity, such certificate or affidavit shall also constitute sufficient proof of his authority.

(c) The ownership, principal amount (except as otherwise contemplated in clause (y) of the first proviso to the definition of Outstanding) and serial numbers of Bonds held by any Person, and the date of holding the same, shall be proved by the Security Register.

(d) Any request, demand, authorization, direction, notice, consent, election, waiver or other Act of a Holder shall bind every future Holder of the same Bond and the Holder of every Bond issued upon the registration of transfer thereof or in exchange therefor or in lieu thereof in respect of anything done, omitted or suffered to be done by the Trustee or the Company in reliance thereon, whether or not notation of such action is made upon such Bond.

(e) Until such time as written instruments shall have been delivered to the Trustee with respect to the requisite percentage of principal amount of Bonds for the action contemplated by such instruments, any such instrument executed and delivered by or on behalf of a Holder may be revoked with respect to any or all of such Bonds by written notice by such Holder or any subsequent Holder, proven in the manner in which such instrument was proven.

(f) Bonds of any series, authenticated and delivered after any Act of Holders may bear a notation as to any action taken by such Act of Holders. If the Company shall so determine, new Bonds of any series, so modified as to conform, in the opinion of the Company, to such action may be prepared and executed by the Company and authenticated and delivered by the Trustee in exchange for Outstanding Bonds of such series.

(g) If the Company shall solicit from Holders any request, demand, authorization, direction, notice, consent, waiver or other Act, the Company may, at its option, fix in advance a record date for the determination of Holders entitled to give such request, demand, authorization, direction, notice, consent, waiver or other Act, but the Company shall have no obligation to do so. If such a record date is fixed, such request, demand, authorization, direction, notice, consent, waiver or other Act may be given before or after such record date, but only the Holders of record at the close of business on the record date shall be deemed to be Holders for the purposes of determining whether Holders of the requisite proportion of the Outstanding Bonds have authorized or agreed or consented to such request, demand, authorization, direction, notice, consent, waiver or other Act, and for that purpose the Outstanding Bonds shall be computed as of the record date.

Section 1.07. Notices, Etc. to Trustee or Company.

(a) Except as otherwise provided herein, any request, demand, authorization, direction, notice, consent, election, waiver or Act of Holders or other document provided or permitted by this Indenture to be made upon, given or furnished to, or filed with, the Trustee by

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any Holder or by the Company, or the Company by the Trustee or by any Holder, shall be sufficient for every purpose hereunder (unless otherwise expressly provided herein) if in writing and delivered personally to an officer or other responsible employee of the addressee, or transmitted by facsimile transmission or other direct written electronic means to such telephone number or other electronic communications address set forth for such party below or such other address as the parties hereto shall from time to time designate, or delivered by registered or certified mail or reputable overnight courier, charges prepaid, to the applicable address set forth for such party below or to such other address as either party hereto may from time to time designate:

If to the Trustee, to:

U.S. Bank National Association

Corporate Trust Services

One Federal Street, Tenth Floor

Boston, Massachusetts 02110

Attention: Tampa Electric Company

Telephone:	617-603-6549
Telecopy:	617-603-6683
Email:	eric.donaghey@usbank.com

If to the Company, to:

Tampa Electric Company

702 North Franklin Street

Tampa, Florida 33602

Attention:     Chief Financial Officer

Telephone:

Telecopy:

Email:

(b) Any communication contemplated herein shall be deemed to have been made, given, furnished and filed if personally delivered, on the date of delivery, if transmitted by facsimile transmission or other direct written electronic means, on the date of transmission if transmitted during normal business hours and otherwise on the next Business Day, and if transmitted by registered or certified mail or reputable overnight courier, on the date of receipt.

Section 1.08. Notice to Holders of Bonds; Waiver.

(a) Except as otherwise expressly provided herein, where this Indenture provides for notice to Holders of any event, such notice shall be sufficiently given, and shall be deemed given, to Holders if in writing and mailed, first-class postage prepaid, to each Holder affected by such event, at the address of such Holder as it appears in the Security Register, not later than the latest date, and not earlier than the earliest date, if any, prescribed for the giving of such Notice.

(b) In case by reason of the suspension of regular mail service or by reason of any other cause it shall be impracticable to give such notice to Holders by mail, then any manner of giving such notice as shall be acceptable to the Trustee shall constitute a sufficient notification for every purpose hereunder. In any case where notice to Holders is given by mail, neither the failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to Holders.

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(c) Any notice required by this Indenture may be waived in writing by the Person entitled to receive such notice, either before or after the event otherwise to be specified therein, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.

Section 1.09. Conflict with Trust Indenture Act. If this Indenture shall become qualified and shall become subject to the Trust Indenture Act, (a) if any provision of this Indenture limits, qualifies or conflicts with another provision hereof which is required or deemed to be included in this Indenture by, or is otherwise governed by, any provision of the Trust Indenture Act, such other provision shall control and (b) if any provision hereof otherwise conflicts with the Trust Indenture Act, the Trust Indenture Act shall control unless otherwise provided as contemplated by Section 2.01 with respect to any series of Bonds. Except as expressly provided otherwise herein, any reference herein to a requirement under the Trust Indenture Act shall only apply upon and so long as this Indenture is qualified under and subject to the Trust Indenture Act.

Section 1.10. Effect of Headings and Table of Contents. The Article and Section headings in this Indenture and the Table of Contents are for convenience only and shall not affect the construction hereof.

Section 1.11. Successors and Assigns. All the covenants, stipulations, promises and agreements in this Indenture contained, by or in behalf of the Company or the Trustee, shall bind and inure to the benefit of their respective successors and assigns, whether so expressed or not.

Section 1.12. Separability Clause. In case any one or more of the provisions contained in this Indenture or in the Bonds shall for any reason be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provisions of this Indenture, but this Indenture shall be construed as if such invalid or illegal or unenforceable provision had never been contained herein.

Section 1.13. Parties in Interest. Nothing in this Indenture expressed or implied is intended or shall be construed to give to any Person other than the Company, the Trustee, and the Holders of the Bonds issued hereunder, any legal or equitable right, remedy or claim under or in respect of this Indenture or any covenants, condition or provision herein or in the Bonds contained; and all such covenants, conditions and provisions are and shall be held to be for the sole and exclusive benefit of the Company, the Trustee, and the Holders of the Bonds issued hereunder.

Section 1.14. Governing Law. This Indenture and the Bonds shall be governed by and construed in accordance with the law of the State of Florida, except to the extent that the Trust Indenture Act shall be applicable and except to the extent that the laws of any other state where the Company then owns Trust Estate shall govern the Lien and related provisions of the Indenture with respect to property in such State.

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Section 1.15. Legal Holidays. In any case where any Interest Payment Date, Redemption Date or Stated Maturity of any Bond shall not be a Business Day at any Place of Payment, then (notwithstanding any other provision of this Indenture or of the Bonds other than a provision in Bonds of any series, or in the Supplemental Indenture or Board Resolution which establishes the terms of the Bonds of such series, which specifically states that such provision shall apply in lieu of this Section) payment of interest or principal and premium, if any, need not be made at such Place of Payment on such date, but may be made on the next succeeding Business Day at such Place of Payment with the same force and effect as if made on the Interest Payment Date, Redemption Date, or Stated Maturity, and, if such payment is made or duly provided for on such Business Day, no interest shall accrue on the amount so payable for the period from and after such Interest Payment Date, Redemption Date or Stated Maturity, as the case may be, to such Business Day.

Section 1.16. Investment of Cash Held by Trustee.

(a) Any cash held by the Trustee or any Paying Agent under any provision of this Indenture shall, except as otherwise provided in Section 7.06 or in Article Eight, at the request of the Company evidenced by Company Order, be invested or reinvested in Investment Securities designated by the Company (such Company Order to contain a representation to the effect that the securities designated therein constitute Investment Securities) and any interest on such Investment Securities shall be paid over to the Company as received, free and clear of any Lien as agreed between the Company and the Trustee. Such Investment Securities shall be held subject to the same provisions hereof as the cash used to purchase the same, but upon a like request of the Company shall be sold, in whole or in designated part, and the proceeds of such sale shall be held subject to the same provisions hereof as the cash used to purchase the Investment Securities so sold. If such sale shall produce a net sum less than the cost of the Investment Securities so sold, the Company shall pay to the Trustee or any such Paying Agent, as the case may be, such amount in cash as, together with the net proceeds from such sale, shall equal the cost of the Investment Securities so sold, and if such sale shall produce a net sum greater than the cost of the Investment Securities so sold, the Trustee or any such Paying Agent, as the case may be, shall promptly pay over to the Company an amount in cash equal to such excess, free and clear of any Lien. In no event shall the Trustee be liable for any loss incurred in connection with the performance or the sale of any Investment Security pursuant to this Section. If no Investment Securities are designated by the Company, such cash held by the Trustee shall remain uninvested.

(b) Notwithstanding the foregoing, if an Event of Default shall have occurred and be continuing, interest on Investment Securities and any gain upon the sale thereof shall be held as part of the Trust Estate until such Event of Default shall have been cured or waived, whereupon such interest and gain shall be promptly paid over to the Company free and clear of any Lien.

Section 1.17. Force Majeure. In no event shall the Trustee be responsible or liable for any failure or delay in the performance of its obligations hereunder arising out of or caused by, directly or indirectly, forces beyond its control, including, without limitation, strikes, work

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stoppages, accidents, acts of war or terrorism, civil or military disturbances, nuclear or natural catastrophes or acts of God, and interruptions, loss or malfunctions of utilities, communications or computer (software and hardware) service affecting the banking industry generally; it being understood that the Trustee shall use reasonable efforts which are consistent with accepted practices in the banking industry to resume performance as soon as practicable under the circumstances.

Section 1.18. Consent to Undertaking for Costs. All parties to this Indenture agree, and each holder of any Bond by his acceptance thereof shall be deemed to have agreed, that any court may in its discretion require in any suit for the enforcement of any right or remedy under this Indenture, or in any suit against the Trustee for any action taken or omitted by it as such Trustee, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit, and that such court may in its discretion assess reasonable costs, including reasonable attorneys’ fees, against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant; but the provisions of this Section shall not apply to any suit instituted by the Trustee, to any suit instituted by any Bondholder, or group of Bondholders, holding in the aggregate more than 10% in principal amount of the Bonds Outstanding, or to any suit instituted by any Bondholder for the enforcement of the payment of the principal of or interest on any Bond, on or after the respective due dates expressed in such Bonds.

Section 1.19. Suspension of Certain Obligations when No Bonds are Outstanding. At any time when no Bonds are Outstanding, the Company’s obligations (and for avoidance of doubt, the Trustee’s obligations) under Articles Six and Seven shall be suspended and of no effect. In addition, during such time, notwithstanding the provisions of Article Seven, upon the written request of the Company to the Trustee for any release of any part of the Trust Estate or any Available Cash, all or any part of the Trust Estate or Available Cash may be released by the Trustee without delivery of any Officers’ Certificates or Opinions of Counsel or the satisfaction of any other conditions provided in Article Seven, other than an Opinion of Counsel that such release is authorized and permitted hereunder.

ARTICLE TWO

Terms of Bonds

Section 2.01. Issuable in Series. The Bonds may be issued in one or more series. Subject to the last paragraph of this Section, prior to the authentication and delivery of Bonds of any series there shall be established by specification in a Supplemental Indenture or in a Board Resolution or in an Officers’ Certificate pursuant to a Supplemental Indenture or a Board Resolution:

(a) the title of the Bonds of such series (which shall distinguish the Bonds of such series from Bonds of all other series);

(b) any limit upon the aggregate principal amount of the Bonds of such series which may be authenticated and delivered under this Indenture (except for Bonds authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Bonds of such series pursuant to Section 2.04, 2.05, 2.06, 5.03 or 13.05, and except for any Bonds which, pursuant to Section 2.03, are deemed never to have been authenticated and delivered hereunder);

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(c) the Person or Persons (without specific identification) to whom any interest on Bonds of such series, shall be payable, if other than the Person in whose name that Bond (or one or more Predecessor Bonds) is registered at the close of business on the Regular Record Date for such interest;

(d) the date or dates on which the principal of the Bonds of such series, is payable or any formulary or other method or other means by which such date or dates shall be determined, by reference to an index or other fact or event ascertainable outside of this Indenture or otherwise (without regard to any provisions for redemption, prepayment, acceleration, purchase or extension); and the right, if any, to extend the Maturity of the Bonds of such series, or any thereof, and the duration of any such extension;

(e) the rate or rates at which the Bonds of such series, shall bear interest, if any (including the rate or rates at which overdue principal shall bear interest after Maturity if different from the rate or rates at which such Bonds shall bear interest prior to Maturity, and, if applicable, the rate or rates at which overdue premium or interest shall bear interest, if any), or any formulary or other method or other means by which such rate or rates shall be determined by reference to an index or other fact or event ascertainable outside of this Indenture or otherwise, the date or dates from which such interest shall accrue; the Interest Payment Dates and the Regular Record Dates, if any, for the interest payable on such Bonds on any Interest Payment Date; and the basis of computation of interest, if other than as provided in Section 2.10; and the right, if any, to extend the interest payment periods and the duration of any such extension;

(f) the place or places at which and/or methods (if other than as provided elsewhere in this Indenture) by which (i) the principal of and premium, if any, and interest, if any, on Bonds of such series, shall be payable, (ii) registration of transfer of Bonds of such series, or any thereof, may be effected, (iii) exchanges of Bonds of such series, may be effected and (iv) notices and demands to or upon the Company in respect of the Bonds of such series, and this Indenture may be served; the Security Registrar and any Paying Agent or Agents for such series; and, if such is the case, that the principal of such Bonds shall be payable without the presentment or surrender thereof;

(g) the period or periods within which, or the date or dates on which, the price or prices at which and the terms and conditions upon which the Bonds of such series, may be redeemed, in whole or in part, at the option of the Company and any restrictions on such redemptions; including but not limited to a restriction on a partial redemption by the Company of the Bonds of any series, resulting in delisting of such Bonds from any national exchange;

(h) the obligation or obligations, if any, of the Company to redeem or purchase or repay the Bonds of such series, pursuant to any sinking fund or other mandatory redemption provisions or at the option of a Holder thereof and the period or periods within which or the date or dates on which, the price or prices at which and the terms and conditions upon which such Bonds shall be redeemed or purchased or repaid, in whole or in part, pursuant to such obligation and applicable exceptions to the requirements of Article Five in the case of mandatory redemption or redemption or repayment at the option of the Holder;

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(i) the denominations in which Bonds of such series, shall be issuable if other than denominations of $1,000 and any integral multiple thereof;

(j) if the principal of or premium, if any, or interest, if any, on the Bonds of such series, are to be payable, at the election of the Company or a Holder thereof, in a coin or currency other than that in which the Bonds are stated to be payable, the period or periods within which, and the terms and conditions upon which, such election may be made and the manner in which the amount of such coin or currency payable is to be determined;

(k) the currency or currencies, including composite currencies, in which payment of the principal of and premium, if any, and interest, if any, on the Bonds of such series, shall be payable (if other than Dollars) and the manner in which the equivalent of the principal amount thereof in Dollars is to be determined for any purpose, including for the purpose of determining the principal amount deemed to be Outstanding at any time;

(l) if the principal of or premium, if any, or interest, if any, on the Bonds of such series, are to be payable, or are to be payable at the election of the Company or a Holder thereof, in securities or other property, the type and amount of such securities or other property, or the formulary or other method or other means by which such amount shall be determined, and the period or periods within which, and the terms and conditions upon which, any such election may be made;

(m) if the amount payable in respect of principal of or premium, if any, or interest, if any, on the Bonds of such series, may be determined with reference to an index or other fact or event ascertainable outside this Indenture, the manner in which such amounts shall be determined to the extent not established pursuant to clause (e) of this paragraph;

(n) if other than the entire principal amount thereof, the portion of the principal amount of Bonds of such series, which shall be payable upon declaration of acceleration of the Maturity thereof pursuant to Section 9.01;

(o) any Events of Default, in addition to those specified in Section 9.01, or any exceptions to those specified in Section 9.01, with respect to the Bonds of such series, and any covenants of the Company for the benefit of the Holders of the Bonds of such series, in addition to those set forth in Article Seven, or any exceptions to those set forth in Article Seven;

(p) the terms, if any, pursuant to which the Bonds of such series, may be converted into or exchanged for shares of capital stock or other securities of the Company or any other Person;

(q) the obligations or instruments, if any, which shall be considered to be Eligible Obligations in respect of the Bonds of such series, denominated in a currency other than Dollars or in a composite currency, whether Eligible Obligations include Investment Securities with respect to Bonds of such series, and any provisions for satisfaction and discharge of Bonds of any series, in addition to those set forth in Article Five, or any exceptions to those set forth in Article Five;

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(r) if the Bonds of such series, are to be issued in global form, (i) any limitations on the rights of the Holder or Holders of such Bonds to transfer or exchange the same or to obtain the registration of transfer thereof, (ii) any limitations on the rights of the Holder or Holders thereof to obtain certificates therefor in definitive form in lieu of global form and (iii) any other matters incidental to such Bonds;

(s) to the extent not established pursuant to clause (r) of this paragraph, any limitations on the rights of the Holders of the Bonds of such series, to transfer or exchange such Bonds or to obtain the registration of transfer thereof; and if a service charge will be made for the registration of transfer or exchange of Bonds of such series, the amount or terms thereof;

(t) any exceptions to Section 1.15, or variation in the definition of Business Day, with respect to the Bonds of such series; and

(u) any other terms of the Bonds of such series, that the Company may elect to specify.

Unless otherwise provided with respect to a series of Bonds as contemplated in clause (b) of this Section 2.01, the aggregate principal amount of a series of Bonds may be increased and additional Bonds of such series may be issued up to the maximum aggregate principal amount authorized with respect to such series as increased.

Section 2.02. Denominations. Unless otherwise provided as contemplated by Section 2.01 with respect to any series of Bonds, the Bonds of each series shall be issuable in denominations of $1,000 and any integral multiple thereof.

Section 2.03. Execution, Authentication, Delivery and Dating.

(a) Unless otherwise provided as contemplated by Section 2.01 with respect to any series of Bonds, Bonds shall be executed on behalf of the Company by an Authorized Officer, and may (but need not) have a corporate seal of the Company affixed thereto or reproduced thereon attested by any other Authorized Officer or by the Secretary or an Assistant Secretary of the Company. The signature of any or all of these officers on the Bonds may be manual or facsimile.

(b) Bonds bearing the manual or facsimile signatures of individuals who were at the time of execution Authorized Officers or the Secretary or an Assistant Secretary of the Company shall bind the Company, notwithstanding that such individuals or any of them have ceased to hold such offices prior to the authentication and delivery of such Bonds or did not hold such offices at the date of such Bonds.

(c) If the forms or terms of the Bonds of any series have been established by or pursuant to a Board Resolution as permitted by Sections 2.01 or 2.14, the Trustee shall not be required to authenticate such Bonds if the issuance of such Bonds pursuant to this Indenture will materially and adversely affect the Trustee’s own rights, duties or immunities under the Bonds and this Indenture.

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(d) Except as otherwise specified as contemplated by Section 2.01 with respect to any series of Bonds, each Bond shall be dated the date of its authentication.

(e) Except as otherwise specified as contemplated by Section 2.01 with respect to any series of Bonds, no Bond shall be entitled to any benefit under this Indenture or be valid or obligatory for any purpose unless there appears on such Bond a certificate of authentication substantially in the form provided for herein executed by the Trustee or its agent by manual signature of an authorized officer thereof, and such certificate upon any Bond shall be conclusive evidence, and the only evidence, that such Bond has been duly authenticated and delivered hereunder and is entitled to the benefits of this Indenture.

Section 2.04. Temporary Bonds.

(a) Pending the preparation of definitive Bonds of any series, the Company may execute, and upon Company Order the Trustee shall authenticate and deliver, temporary Bonds which are printed, lithographed, typewritten, mimeographed or otherwise produced, in any authorized denomination, substantially of the tenor of the definitive Bonds in lieu of which they are issued, with such appropriate insertions, omissions, substitutions and other variations as any officer executing such Bonds may determine, as evidenced by such officer’s execution of such Bonds; provided, however, that temporary Bonds need not recite specific redemption, sinking fund, conversion or exchange provisions.

(b) Unless otherwise specified as contemplated by Section 2.01 with respect to the Bonds of any series after the preparation of definitive Bonds of such series, the temporary Bonds of such series shall be exchangeable, without charge to the Holder thereof, for definitive Bonds of such series upon surrender of such temporary Bonds at the office or agency of the Company maintained pursuant to Section 6.02 in a Place of Payment for such Bonds. Upon such surrender of temporary Bonds for such exchange, the Company shall, except as aforesaid, execute and the Trustee shall authenticate and deliver in exchange therefor definitive Bonds of the same series and of authorized denominations and of like tenor and aggregate principal amount.

(c) Until exchanged in full as hereinabove provided, temporary Bonds shall in all respects be entitled to the same benefits under this Indenture as definitive Bonds of the same series and of like tenor authenticated and delivered hereunder.

Section 2.05. Registration, Registration of Transfer and Exchange.

(a) The Company shall cause to be kept in each office designated pursuant to Section 6.02, with respect to the Bonds of each series, a register (all registers kept in accordance with this Section being collectively referred to as the “Security Register”) in which, subject to such reasonable regulations as it may prescribe, the Company shall provide for the registration of Bonds of such series, and the registration of transfer thereof. The Company shall designate one Person to maintain the Security Register for the Bonds of each series on a consolidated basis, and such Person is referred to herein, with respect to such series, as the “Security Registrar.” Anything herein to the contrary notwithstanding, the Company may designate one or more of its

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offices as an office in which a register with respect to the Bonds of one or more series shall be maintained, and the Company may designate itself the Security Registrar with respect to one or more of such series. The Security Register shall be open for inspection by the Trustee and the Company at all reasonable times.

(b) Except as otherwise specified as contemplated by Section 2.01 with respect to the Bonds of any series, upon surrender for registration of transfer of any Bond of such series at the office or agency of the Company maintained pursuant to Section 6.02 in a Place of Payment for such series, the Company shall execute, and the Trustee shall authenticate and deliver, in the name of the designated transferee or transferees, one or more new Bonds of the same series, of authorized denominations and of like tenor and aggregate principal amount.

(c) Except as otherwise specified as contemplated by Section 2.01 with respect to the Bonds of any series, any Bond of such series, other than a Global Bond, may be exchanged at the option of the Holder for one or more new Bonds of the same series, of authorized denominations and of like tenor and aggregate principal amount, upon surrender of the Bonds to be exchanged at any such office or agency. Whenever any Bonds are so surrendered for exchange, the Company shall execute, and the Trustee shall authenticate and deliver, the Bonds, which the Holder making the exchange is entitled to receive.

(d) All Bonds delivered upon any registration of transfer or exchange of Bonds shall be valid obligations of the Company, evidencing the same obligation, and entitled to the same benefits under this Indenture, as the Bonds surrendered upon such registration of transfer or exchange.

(e) Every Bond presented or surrendered for registration of transfer or for exchange shall (if so required by the Company, the Trustee or the Security Registrar) be duly endorsed or shall be accompanied by a written instrument of transfer in form attached to the form of Bond, duly executed by the Holder thereof or his attorney duly authorized in writing.

(f) Unless otherwise specified as contemplated by Section 2.01, with respect to Bonds of any series, or any thereof, no service charge shall be made for any registration of transfer or exchange of Bonds, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of Bonds, other than exchanges pursuant to Section 2.04, 5.03 or 13.05 not involving any transfer.

(g) The Company shall not be required to execute or to provide for the registration of transfer of or the exchange of

(i) Bonds of any series, during a period of 15 days immediately preceding the date notice is to be given identifying the serial numbers of the Bonds of such series called for redemption or

(ii) any Bond so selected for redemption in whole or in part, except the unredeemed portion of any Bond being redeemed in part.

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(h) The provisions of this Section 2.05 are, with respect to any Global Bond, subject to Section 2.15 hereof.

Section 2.06. Mutilated, Destroyed, Lost and Stolen Bonds.

(a) If any mutilated Bond is surrendered to the Trustee or the Security Registrar, the Company shall execute and the Trustee shall authenticate and deliver in exchange therefor a new Bond of the same series, and of like tenor and principal amount, bearing a number not contemporaneously outstanding.

(b) If there shall be delivered to the Company and the Trustee (a) evidence to their satisfaction of the ownership of and the destruction, loss or theft of any Bond and (b) such security or indemnity as may be reasonably required by them to save each of them and any agent of any of them harmless, then, in the absence of notice to the Company or the Trustee that such Bond has been acquired by a bona fide purchaser, the Company shall execute and the Trustee shall authenticate and deliver, in lieu of any such destroyed, lost or stolen Bond, a new Bond of the same series, and of like tenor and principal amount, bearing a number not contemporaneously outstanding.

(c) Notwithstanding the foregoing, in case any such mutilated, destroyed, lost or stolen Bond has become or is about to become due and payable, the Company in its discretion may, instead of issuing a new Bond, pay such Bond.

(d) Upon the issuance of any new Bond under this Section, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other reasonable expenses (including the fees and expenses of the Trustee) in connection therewith.

(e) Every new Bond of any series issued pursuant to this Section in lieu of any destroyed, lost or stolen Bond shall constitute an original additional contractual obligation of the Company, whether or not the destroyed, lost or stolen Bond shall be at any time enforceable by anyone other than the Holder of such new Bond, and any such new Bond shall be entitled to all the benefits of this Indenture equally and proportionately with any and all other Bonds of such series duly issued hereunder.

Section 2.07. Payment of Interest; Interest Rights Preserved.

(a) Unless otherwise specified as contemplated by Section 2.01 with respect to the Bonds of any series, interest on any Bond which is payable, and is punctually paid or duly provided for, on any Interest Payment Date shall be paid to the Person in whose name that Bond (or one or more Predecessor Bonds) is registered at the close of business on the Regular Record Date for such interest.

(b) Any interest on any Bond of any series which is payable, but is not punctually paid or duly provided for, on any Interest Payment Date (herein called “Defaulted Interest”) shall forthwith cease to be payable to the Holder on the related Regular Record Date by virtue of having been such Holder, and such Defaulted Interest may be paid by the Company, at its election, as provided in clause (i) or (ii) below:

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(i) The Company may elect to make payment of any Defaulted Interest to the Persons in whose names the Bonds of such series (or their respective Predecessor Bonds) are registered at the close of business on a date (a “Special Record Date”) for the payment of such Defaulted Interest, which shall be fixed in the following manner. The Company shall notify the Trustee in writing of the amount of Defaulted Interest proposed to be paid on each Bond of such series and the date of the proposed payment, and at the same time the Company shall deposit with the Trustee an amount of money equal to the aggregate amount proposed to be paid in respect of such Defaulted Interest or shall make arrangements satisfactory to the Trustee for such deposit prior to the date of the proposed payment, such money when deposited to be held in trust for the benefit of the Persons entitled to such Defaulted Interest as in this clause provided. Thereupon the Trustee shall fix a Special Record Date for the payment of such Defaulted Interest which shall be not more than 15 days and not less than 10 days prior to the date of the proposed payment and not less than 10 days after the receipt by the Trustee of the notice of the proposed payment. The Trustee shall promptly notify the Company of such Special Record Date and, in the name and at the expense of the Company shall promptly cause notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor to be mailed, first-class postage prepaid, to each Holder of Bonds of such series at the address of such Holder as it appears in the Security Register, not less than 10 days prior to such Special Record Date. Notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor having been so mailed, such Defaulted Interest shall be paid to the Persons in whose names the Bonds of such series (or their respective Predecessor Bonds) are registered at the close of business on such Special Record Date. No interest, other than said Defaulted Interest, shall be payable to such Holders with respect to any such amounts so deposited by the Company with the Trustee.

(ii) The Company may make payment of any Defaulted Interest on the Bonds of any series in any other lawful manner not inconsistent with the requirements of any securities exchange on which such Bonds may be listed, and upon such notice as may be required by such exchange, if, after notice given by the Company to the Trustee of the proposed payment pursuant to this clause, such manner of payment shall be deemed practicable by the Trustee.

(c) Subject to the foregoing provisions of this Section and Section 2.05, each Bond delivered under this Indenture upon registration of transfer of or in exchange for or in lieu of any other Bond shall carry the rights to interest accrued and unpaid, and to accrue, which were carried by such other Bond.

Section 2.08. Persons Deemed Owners.

(a) Prior to due presentment of a Bond for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name such Bond is registered as the absolute owner of such Bond for the purpose of receiving payment of principal of and premium, if any, and (subject to Sections 2.05 and 2.07) interest, if any, on such Bond and for all other purposes whatsoever, whether or not such Bond be overdue, and none of the Company, the Trustee or any agent of the Company or the Trustee shall be affected by notice to the contrary.

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(b) No holder of any beneficial interest in any Global Bond held on its behalf by a Depositary shall have any rights under this Indenture with respect to such Global Bond, and such Depositary may be treated by the Company, the Trustee, and any agent of the Company or the Trustee as the owner of such Global Bond for all purposes whatsoever. Notwithstanding the foregoing, nothing herein shall impair, as between a Depositary and such holders of beneficial interests, the operation of customary practices governing the exercise of the rights of the Depositary as holder of any Bond.

Section 2.09. Cancellation. All Bonds surrendered for payment, redemption, registration of transfer or exchange or for credit against any sinking fund payment shall, if surrendered to any Person other than the Security Registrar, be delivered to the Security Registrar and, if not theretofore canceled, shall be promptly canceled by the Security Registrar. The Company may at any time deliver to the Security Registrar for cancellation any Bonds previously authenticated and delivered hereunder which the Company may have acquired in any manner whatsoever or which the Company shall not have issued and sold, and all Bonds so delivered shall be promptly canceled by the Security Registrar. No Bonds shall be authenticated in lieu of or in exchange for any Bonds canceled as provided in this Section, except as expressly permitted by this Indenture. All canceled Bonds held by the Security Registrar shall be disposed of in accordance with the customary practices of the Security Registrar at the time in effect, and the Security Registrar shall not be required to destroy any such certificates. The Security Registrar shall promptly deliver evidence of any cancellation of a Bond if requested in accordance with this Section 2.09 to the Trustee and the Company.

Section 2.10. Computation of Interest. Except as otherwise specified as contemplated by Section 2.01 for Bonds of any series, interest on the Bonds of each series shall be computed on the basis of a 360-day year consisting of twelve 30-day months, and with respect to any period less than a full month, on the basis of the actual number of days elapsed during such period. For example, the interest for a period running from the 15th day of one month to the 15th day of the next month would be calculated on the basis of one 30-day month.

Section 2.11. Payment to be in Proper Currency. In the case of any Bond denominated in any currency other than Dollars or in a composite currency (the “Required Currency”), except as otherwise specified with respect to such Bond as contemplated by Section 2.01, the obligation of the Company to make any payment of the principal thereof, or the premium or interest thereon, shall not be discharged or satisfied by any tender by the Company, or recovery by the Trustee, in any currency other than the Required Currency, except to the extent that such tender or recovery shall result in the Trustee timely holding the full amount of the Required Currency then due and payable. If any such tender or recovery is in a currency other than the Required Currency, the Trustee may take such actions as it considers appropriate to exchange such currency for the Required Currency. The costs and risks of any such exchange, including without limitation the risks of delay and exchange rate fluctuation, shall be borne by the Company, the Company shall remain fully liable for any shortfall or delinquency in the full amount of Required Currency then due and payable, and in no circumstances shall the Trustee be liable therefor except in the case of its negligence or willful misconduct in the discharge of an express duty hereunder.

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Section 2.12. Extension of Interest Payment. The Company shall have the right at any time, to extend interest payment periods on all the Bonds of any series hereunder, if so specified as contemplated by Section 2.01 with respect to such Bonds and upon such terms as may be specified as contemplated by Section 2.01 with respect to such Bonds.

Section 2.13. CUSIP Numbers. The Company in issuing the Bonds may use “CUSIP” or “ISIN” or other similar numbers (if then generally in use), and, if so, the Company, the Trustee or the Security Registrar may use “CUSIP” or “ISIN” or such other numbers in notices or redemption as a convenience to Holders; provided that any such notice may state that no representation is made as to the correctness of such numbers either as printed on the Bonds or as contained in any notice of a redemption and that reliance may be placed only on the other identification numbers printed on the Bonds, in which case none of the Company or, as the case may be, the Trustee or the Security Registrar, or any agent of any of them, shall have any liability in respect of any “CUSIP” or “ISIN” or other number used on any such notice, and any such redemption shall not be affected by any defect in or omission of such numbers.

Section 2.14. Forms of Bonds and Trustee Authentication.

(a) The definitive Bonds of each series shall be in substantially the form or forms thereof established in the Supplemental Indenture or Board Resolution establishing such series, or in an Officers’ Certificate pursuant to such a Supplemental Indenture or Board Resolution, in each case with such appropriate insertions, omissions, legends, substitutions and other variations as are required or permitted by this Indenture, and may have such letters, numbers or other marks of identification and such legends or endorsements placed thereon as may be required to comply with the rules of any securities exchange or as may, consistently herewith, be determined by the officers executing such Bonds, as evidenced by their execution thereof. If the form or forms of Bonds of any series are established in a Board Resolution or in an Officers’ Certificate pursuant to a Supplemental Indenture or a Board Resolution, such Board Resolution and Officers’ Certificate, if any, shall be delivered to the Trustee at or prior to the delivery of the Company Order contemplated by Section 3.02 for the authentication and delivery of such Bonds.

(b) Unless otherwise specified as contemplated by Section 2.01, the Bonds of each series shall be issuable in registered form without coupons. The definitive Bonds shall be produced in such manner as shall be determined by the officers executing such Bonds, as evidenced by their execution thereof.

(c) The Trustee’s certificate of authentication shall be in substantially the form set forth below:

This is one of the Bonds of the series designated therein referred to in the within-mentioned Indenture.

U.S. Bank National Association (or successor Trustee if applicable); as Trustee
By:
	Authorized Signatory
Dated:

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Section 2.15. Global Bonds.

(a) If the Company establishes pursuant to Section 2.01 hereof that the Bonds of a particular series are to be issued in the form of a Global Bond, then the Company shall execute and the Trustee shall, in accordance with Sections 2.03 and 3.02 hereof, authenticate and deliver, a Global Bond or Bonds which (i) shall represent, and shall be denominated in an aggregate amount equal to the aggregate principal amount of all of the Outstanding Bonds of such series, (ii) shall be registered in the name of the Depositary or its nominee, (iii) shall be deposited with the Trustee as custodian for the Depositary and (iv) shall, unless otherwise specified in the Supplemental Indenture or Board Resolution for such series, bear a legend substantially to the following effect:

“This Bond is a Global Bond within the meaning of the Indenture hereinafter referred to and is registered in the name of a Depositary or a nominee of a Depositary. This Bond is exchangeable for Bonds registered in the name of a person other than the Depositary or its nominee only in the limited circumstances described in the Indenture, and no transfer of this Bond (other than a transfer of this Bond as a whole by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary) may be registered except in limited circumstances.

Unless this Global Bond is presented by an authorized representative of the Depositary to the Company or its agent for registration of transfer, exchange or payment, and any definitive Bond is issued in the name of Cede & Co. or in such other name as is requested by an authorized representative of the Depositary (and any payment is made to Cede & Co. or to such other entity as is requested by an authorized representative of the Depositary), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL in as much as the registered owner hereof, Cede & Co., has an interest herein.”

(b) Notwithstanding the provisions of Section 2.04 hereof, the Global Bond of a series may be transferred, in whole but not in part and in the manner provided in Section 2.04 hereof, only to another nominee of the Depositary for such series, or to a successor Depositary for such series selected or approved by the Company or to a nominee of such successor Depositary.

(c) If (i) at any time the Depositary for a series of Bonds notifies the Company or Trustee that it is unwilling or unable to continue as Depositary for such series or if at any time the Depositary for such series shall no longer be registered or in good standing under the Exchange Act, or other applicable statute or regulation and a successor Depositary for such series is not appointed by the Company within 90 days after the Company receives such notice or

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becomes aware of such condition, as the case may be or (ii) there shall have occurred and be continuing after any applicable grace periods an Event of Default with respect to the Bonds for a series, then in each such case, this Section 2.15 shall no longer be applicable to the Bonds of such series and the Company will execute, and subject to Section 2.05 hereof the Trustee will authenticate and deliver Bonds of such series in definitive registered form without coupons, in authorized denominations, and in an aggregate principal amount equal to the principal amount of the Global Bonds of such series in exchange for such Global Bonds. In addition, the Company may at any time determine that the Bonds of any series shall no longer be represented by Global Bonds and that the provisions of this Section 2.15 shall no longer apply to the Bonds of such series. In such event the Company will execute and subject to Section 2.05 hereof, the Trustee, upon receipt of an Officers’ Certificate evidencing such determination by the Company, will authenticate and deliver Bonds of such series in definitive registered form without coupons, in authorized denominations, and in an aggregate principal amount equal to the principal amount of the Global Bonds of such series in exchange for such Global Bonds. Upon the exchange of the Global Bonds for such Bonds in definitive registered form without coupons, in authorized denominations, the Global Bonds shall be canceled by the Trustee. Such Bonds in definitive registered form issued in exchange for the Global Bonds pursuant to this Section 2.15, shall be registered in such names and in such authorized denominations as the Depositary, pursuant to the instructions from its direct or indirect participants or otherwise, shall instruct the Trustee. The Trustee shall deliver Bonds to the Depositary for delivery to the Persons in whose names such Bonds are so registered.

ARTICLE THREE

Issuance of Bonds

Section 3.01. Principal Amount Issuable. Bonds of any one or more series may be authenticated and delivered in any aggregate principal amount so long as, after immediately giving effect thereto, to the concurrent redemption or payment of Bonds and Prior Lien Indebtedness and to any other transactions contemplated therewith (including the acquisition of Property Additions), the aggregate principal amount of all Bonds and Prior Lien Indebtedness, in each case then Outstanding, will not exceed 60% of the sum of (i) the then Cost or Fair Value, whichever is less, of all Property Additions (after making any deductions pursuant to Section 1.03(b)) and (ii) all Available Cash then held by, or deposited with, the Trustee.

Section 3.02. Documents Required to be Delivered. The Trustee shall authenticate and deliver Bonds of a series for original issue, at one time or from time to time in accordance with the Company Order referred to below, upon receipt by the Trustee of:

(a) the Supplemental Indenture, Board Resolution or other instrument or instruments establishing the form or forms and terms of the Bonds of such series, as provided in Sections 2.01 and 2.14;

(b) a Company Order requesting the authentication and delivery of such Bonds;

(c) Bonds of such series, each executed on behalf of the Company by an Authorized Officer of the Company;

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(d) an Officers’ Certificate (i) which shall comply with the requirements of Section 1.05 of this Indenture and (ii) which states that no Event of Default under this Indenture has occurred and is occurring;

(e) an Experts’ Certificate dated as of a date not more than 90 days prior to the first day of the month in which the Company Order referring to it is delivered to the Trustee,

(i) setting forth the aggregate amount of Property Additions then owned by the Company, such amount to be computed by reference to the Company’s financial statements, on a Dollar basis, and stating the Cost of such Property Additions;

(ii) stating that all such property reflected in clause (i) above constitutes Property Additions;

(iii) stating that such Property Additions are desirable for use in the conduct of the business of the Company;

(iv) stating what part, if any, of such Property Additions includes property which had not been included in a previous Experts’ Certificate and which within six months prior to the date of acquisition thereof by the Company had been used or operated by others than the Company in a business similar to that in which it has been or is to be used or operated by the Company and stating whether or not, in the judgment of the signers, the Fair Value of such Property Additions to the Company, as of the date of such certificate, is more than $25,000 and more than 1% of the aggregate principal amount of Bonds then Outstanding;

(v) stating, in the judgment of the signers, the Fair Value to the Company, as of the date of such certificate, of such Property Additions, except any thereof with respect to the Fair Value to the Company of which a statement is to be made in an Independent Experts’ Certificate pursuant to clause (f) below;

(vi) stating the lower of the Cost or the Fair Value to the Company of such Property Additions (after making deductions pursuant to Section 1.03(b));

(vii) stating the aggregate principal amount of Bonds and Prior Lien Indebtedness to be Outstanding immediately prior to the issuance of the Bonds to be then authenticated and delivered;

(viii) stating the principal amount of Bonds to be then authenticated and delivered;

(ix) stating that, immediately after giving effect to the issuance of the Bonds to be then authenticated and delivered, to the concurrent redemption or payment of Bonds and Prior Lien Indebtedness and any other transactions contemplated therewith (including the acquisition of Property Additions and the incurrence or assumption by the Company of any Prior Lien), the aggregate principal amount of all Bonds and Prior Lien Indebtedness, in each case then Outstanding, will not exceed 60% of the sum of (A) the amount set forth in clause (vi) above, and (B) all Available Cash; and

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(x) stating that the Lien on the Company’s interest in the Property Additions will be subject to no Lien thereon prior to the Lien of this Indenture except Permitted Liens (specifying any Prior Lien).

(f) in case any Property Additions are shown by the Experts’ Certificate provided for in clause (e) above to include property which had not been included in a previous Experts’ Certificate and which, within six months prior to the date of acquisition thereof by the Company, had been used or operated by others than the Company in a business similar to that in which it has been or is to be used or operated by the Company and such certificate does not show the Fair Value thereof to the Company, as of the date of such certificate, to be less than $25,000 or less than 1% of the aggregate principal amount of Bonds then Outstanding, an Independent Experts’ Certificate stating, in the judgment of the signer, the Fair Value to the Company, as of the date of such Independent Experts’ Certificate, of (X) such Property Additions which have been so used or operated and (at the option of the Company) as to any other Property Additions included in the Experts’ Certificate provided for in clause (e) above and (Y) in case such Independent Experts’ Certificate is being delivered in connection with the authentication and delivery of Bonds, any property so used or operated which has been subjected to the Lien of this Indenture since the commencement of the then current calendar year and as to which an Independent Experts’ Certificate has not previously been furnished to the Trustee;

(g) in case any Property Additions are shown by the Experts’ Certificate provided for in clause (e) above to have not been included in a previous Experts’ Certificate and to have been acquired, made or constructed in whole or in part through the delivery of securities or other property, an Experts’ Certificate stating, in the judgment of the signers, the Fair Value in cash of such securities or other property at the time of delivery thereof in payment for or for the acquisition of such Property Additions;

(h) an Opinion of Counsel (which may be Opinions of Counsel) which shall comply with the requirements of Section 1.05 of this Indenture and that states that:

(i) the form or forms of such Bonds have been duly authorized by the Company and have been established in conformity with the provisions of this Indenture;

(ii) the terms of such Bonds have been duly authorized by the Company and have been established in conformity with the provisions of this Indenture;

(iii) when such Bonds shall have been authenticated and delivered by the Trustee and issued and delivered by the Company in the manner and subject to any conditions specified in such Opinion of Counsel, such Bonds will have been duly issued under this Indenture, and will constitute valid and legally binding obligations of the Company, entitled to the benefits provided by this Indenture, and enforceable in accordance with their terms, subject, as to enforcement, to laws relating to or affecting generally the enforcement of mortgagees’ and other creditors’ rights, including, without limitation, bankruptcy, insolvency, reorganization, receivership, moratorium and other laws affecting the rights and remedies of creditors and mortgagees generally, general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and an implied covenant of good faith, fair dealing and reasonableness and any other customary exceptions made by such counsel based on the law of the relevant state made in opinions of this type and scope;

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(iv) this Indenture constitutes, or, upon the delivery of, and/or the filing and/or recording in the proper places and manner of, the instruments of conveyance, assignment or transfer, if any, specified in said opinion, will constitute, a valid and effective mortgage lien, subject only to Permitted Encumbrances, upon the interest of the Company in the Property Additions;

(v) the Company has corporate authority to operate such Property Additions; and

(vi) all conditions precedent to the authentication and delivery of such Bonds as set forth in this Indenture or in a Supplemental Indenture hereto or Board Resolution or other instrument establishing such Bonds have been satisfied;

(i) copies of the instruments of conveyance, assignment and transfer, if any, specified in the Opinion of Counsel provided for in clause (h) above; and

(j) an Earnings Certificate.

ARTICLE FOUR

Sinking Funds

Section 4.01. Applicability Of Article.

(a) The provisions of this Article shall be applicable to any sinking fund for the retirement of the Bonds of any series, except as otherwise specified as contemplated by Section 2.01 for Bonds of such series.

(b) The minimum amount of any sinking fund payment provided for by the terms of Bonds of any series, is herein referred to as a “mandatory sinking fund payment”, and any payment in excess of such minimum amount provided for by the terms of Bonds of any series, is herein referred to as an “optional sinking fund payment”. If provided for by the terms of Bonds of any series, the cash amount of any sinking fund payment may be subject to reduction as provided in Section 4.02. Each sinking fund payment shall be applied to the redemption of Bonds of the series or in respect of which it was made as provided for by the terms of such Bonds.

Section 4.02. Satisfaction of Sinking Fund Payments with Bonds. The Company (a) may deliver to the Trustee Outstanding Bonds (other than any previously called for redemption) of a series in respect of which a mandatory sinking fund payment is to be made and (b) may apply as a credit Bonds of such series which have been redeemed either at the election of the Company pursuant to the terms of such Bonds, at the election of the Holder thereof if applicable, or through the application of permitted optional sinking fund payments pursuant to the terms of such Bonds, in each case in satisfaction of all or any part of such mandatory sinking fund payment with respect to the Bonds of such series; provided, however, that no Bonds shall be

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applied in satisfaction of a mandatory sinking fund payment if such Bonds shall have been previously so applied. Bonds so applied shall be received and credited for such purpose by the Trustee at the Redemption Price specified in such Bonds for redemption through operation of the sinking fund and the amount of such mandatory sinking fund payment shall be reduced accordingly.

Section 4.03. Redemption of Bonds for Sinking Fund.

(a) Not less than 45 days, or such shorter period as the Trustee shall agree to, prior to each sinking fund payment date for the Bonds of any series, or any thereof, the Company shall deliver to the Trustee an Officers’ Certificate specifying:

(i) the amount of the next succeeding mandatory sinking fund payment for such series;

(ii) the amount, if any, of the optional sinking fund payment to be made together with such mandatory sinking fund payment;

(iii) the aggregate sinking fund payment;

(iv) the portion, if any, of such aggregate sinking fund payment which is to be satisfied by the payment of cash; and

(v) the portion, if any, of such aggregate sinking fund payment which is to be satisfied by delivering and crediting Bonds of such series or pursuant to Section 4.02 and stating the basis for such credit and that such Bonds have not previously been so credited, and the Company shall also deliver to the Trustee any Bonds to be so delivered.

(b) If the Company shall not deliver such Officers’ Certificate with respect to the Bonds of any Series and, to the extent applicable, all such Bonds required to be delivered therewith pursuant to Section 4.02, the next succeeding sinking fund payment for such series or shall be made entirely in cash in the amount of the mandatory sinking fund payment. Not less than 30 days before each such sinking fund payment date the Trustee shall select the Bonds to be redeemed upon such sinking fund payment date in the manner specified in Section 5.03 and cause notice of the redemption thereof to be given in the name of and at the expense of the Company in the manner provided in Section 5.02. Such notice having been duly given, the redemption of such Bonds shall be made upon the terms and in the manner stated in Sections 5.03 and 5.04.

ARTICLE FIVE

Redemption and Purchase of Bonds

Section 5.01. Right to Redeem. The Bonds of any series issued hereunder may be made subject to redemption prior to Maturity at the option of the Company, at such times, in such amounts, at such prices and on such terms as may be specified in the Bonds of such series. In case there is Outstanding any Bond of any series of a denomination larger than $1,000, such Bond may be made subject to redemption in part only, in units of $1,000 or any integral multiple

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thereof. Except as otherwise provided in any Supplemental Indenture or Bond Resolution, with respect to Bonds of any particular series, the procedure for the redemption of Bonds of all series which are made redeemable prior to Maturity shall be as hereinafter in this Articles provided.

Section 5.02. Notice of Redemption. Unless otherwise specified in the Bonds of any series which are subject to the redemption prior to Maturity, notice of redemption of such Bonds shall be given in the manner provided in Section 1.08, or otherwise as may be permitted by said Section, unless waived as provided in said Section. Each notice of redemption shall state the Redemption Date and the principal amount of Bonds of each series to be redeemed, and shall specify, in case less than all of the Bonds of a series are to be redeemed, the distinctive number of the Bonds to be redeemed (which may be stated separately or in groups from the number to another, inclusive, except such as shall have been previously called for redemption or otherwise retired, or in groups ending in the same digit or series of digits), and in case any Bond is to be redeemed in part only, the principal amount thereof to be redeemed, and shall also state that the interest on the Bonds in such notice designated for redemption shall cease on such Redemption Date and that on said date there will become due and payable upon each of said Bonds the Redemption Price therein specified, and shall also state the place or places where said Bonds shall be surrendered for payment of such Redemption Price. Each notice of redemption of Bonds for any sinking, improvement, renewal, maintenance, or replacement fund, and each notice of redemption of Bonds through the application of any proceeds of any of the Trust Estate which under the provisions hereof or of any Supplemental Indenture is required to be applied solely to the redemption or purchase of Bonds, or by the application of which such Bonds are being redeemed at a price lower than the then applicable regular Redemption Price at which the same are redeemable at the option of the Company, shall state that the redemption is through the application of such cash.

Section 5.03. Partial Redemption; Selection of Bonds to be Redeemed.

(a) In case the Company shall elect to redeem less than all the Outstanding Bonds of any series, it shall, in each such instance, at least fifteen (15) days before the date upon which the mailing of notice of redemption is required to be made (unless a shorter notice is accepted by the Trustee as sufficient), notify the Trustee in writing of such election and of the aggregate principal amount of Bonds of such series to be redeemed.

(b) Subject to the standard procedures of the Depositary in connection with a Global Bond, the selection of Bonds or of portions thereof to be redeemed shall, in case less than all of the Outstanding Bonds of any series are to be redeemed, be made by the Trustee by lot (either separately or in groups as contemplated by Section 5.02, or by both such methods) in any manner deemed by the Trustee to be proper. In case there are Outstanding Bonds of a denomination greater than $1,000, the Trustee may, for the purpose of determining by lot the portions of any such Bonds to be redeemed, assign numbers to the units of $1,000 represented by such fully registered Bonds, or may draw by lot the portions of such Bonds to be redeemed in such other manner as it may determine. The Trustee shall promptly notify the Company in writing of the distinctive numbers of the Bonds which, or portions of which, have been selected for redemption, and the principal amount thereof to be redeemed in case of Bonds of a denomination greater than $1,000.

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Section 5.04. Effect of Call for Redemption; Payment of Redeemed Bonds.

(a) Notice of redemption having been duly given as aforesaid, the Bonds or a specified portion of Bonds so to be redeemed shall on the date designated in such notice become due and payable at the Redemption Price specified in such notice; and on and after the date so designated (unless the Company shall default in making the deposit hereinafter in this Section required) interest on the Bonds or portion thereof so designated for redemption shall cease to accrue, and upon surrender for payment of any Bond specified therein such Bonds (or such specific portions) shall be paid by the Company at the Redemption Price aforesaid.

(b) In case any Bond shall be redeemed in part only, upon the presentation of such Bond for such partial redemption, the Company shall execute and the Trustee shall authenticate and shall deliver or cause to be delivered to or upon the written order of the registered owner of any such registered Bond, at the expense of the Company, a Bond or Bonds of the same series (but only in authorized denominations) for the unredeemed portion of such Bond, or, at the option of the registered owner of such Bond, the Trustee shall, upon presentation of such Bond for such purpose, make or cause to be made a notation thereon of the payment of the portion of such Bond so redeemed.

(c) The Company shall deposit with the Trustee prior to each date designated for redemption an amount of money sufficient to enable the Trustee to pay the Redemption Price of all Bonds which the Company has elected to redeem on such date.

Section 5.05. Disposition of Redeemed Bonds. All Bonds redeemed pursuant to Section 5.04 shall (except as provided in said Section 5.04 with respect to Bonds on which a notation of partial payment is made) be cancelled by the Trustee in accordance with Section 2.09.

ARTICLE SIX

Certain Covenants of the Company

Section 6.01. Payment of Principal and Interest, etc.

(a) The Company will punctually pay the principal and the interest (and premium, if any) to become due in respect of all the Bonds issued under this Indenture at the times and places and in the manner specified herein and in the Bonds according to the true intent and meaning thereof, all in coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. When and as paid in full, all Bonds shall be surrendered to the Trustee and shall forthwith be cancelled in accordance with Section 2.09.

(b) Money deposited with the Trustee or with any Paying Agent for the purpose of paying the principal of or interest (or premium, if any) on Bonds shall constitute a trust fund for such purpose and for no other purpose whatever, subject to the provisions of Sections 8.03 and 8.04.

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Section 6.02. Maintenance of Office or Agency, Appointment of Paying Agents, etc.

(a) The Company will maintain an office or agency while any of the Bonds are Outstanding at each place at which the principal of or interest on any of the Bonds shall be payable, and where notices, presentations and demands to or upon the Company in respect of this Indenture or of such Bonds as may be payable at such place may be given or made, and will give the Trustee written notice of the location of and any change in the location of each such office or agency. In case the Company shall at any time fail to designate and maintain such office or offices, agency or agencies, the Corporate Trust Office of the Trustee shall be conclusively deemed to be the office or agency of the Company for all such purposes, and the Company hereby appoints the Trustee its agent, on its behalf, to receive all such notices, presentations and demands.

(b) If the Company shall at any time appoint a Paying Agent other than the Trustee, it will cause such Paying Agent to execute and deliver to the Trustee an instrument in writing in which such Paying Agent shall agree with the Trustee, subject to the provisions of this Section, (1) that such Paying Agent shall hold in trust for the benefit of the Bondholders entitled thereto or of the Trustee, all sums held by such Paying Agent for the payment of the principal of or interest and premium, if any, on any of the Bonds; and (2) that such Paying Agent shall give to the Trustee notice of any default by the Company, or any other obligor on the Bonds, in the making of any payment to such Paying Agent on account of the principal of or interest and premium, if any, on any of the Bonds. Such Paying Agent shall not be obligated to segregate such sums from other funds of such Paying Agent except to the extent required by law.

(c) If the Company acts as its own Paying Agent, it will, on or before each due date of each installment of principal of or interest and premium, if any, on the Bonds, set aside and segregate and hold in trust for the benefit of the Bondholders entitled thereto or for the Trustee, as the case may be, a sum sufficient to pay such principal or interest so becoming due on the Bonds and will notify the Trustee of such action or of any failure to take such action.

(d) Anything in this Section to the contrary notwithstanding, the Company may at any time cause any Paying Agent, or itself, to pay or cause to be paid to the Trustee or to any successor Paying Agent, upon the same trusts, all sums so held in trust by any such Paying Agent or by itself.

(e) Anything in Subsections (a), (b) and (c) of this Section to the contrary notwithstanding, the holding in trust by the Trustee, any Paying Agent or the Company, of funds referred to therein, is subject to the provisions of Sections 8.03 and 8.04.

Section 6.03. Warranty of Title, etc. The Company hereby does and will forever warrant and defend the title to the property described in the Granting Clauses hereof, except those properties as to which only the Company’s right, title and interest is purported to be conveyed, against the claims and demands of all Persons whosoever other than (a) claims or demands described or referred to in such Granting Clauses, and (b) Permitted Encumbrances. At the time of the ensealing and delivering of this Indenture, the Company is lawfully seized and possessed of the real property and interests therein specifically described in the Granting Clauses hereof, subject to no mortgage, Lien, charge or encumbrance, except as hereinabove recited, and

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has full power and lawful authority to grant, bargain, sell, convey, assign and mortgage the same in the manner and form aforesaid. The Company lawfully owns and is possessed of the personal property specifically described in the Granting Clauses hereof subject to no mortgage, pledge, Lien, charge or encumbrance, except as hereinabove recited, and the Company has full power and lawful authority to mortgage, assign and transfer the same in the manner and form aforesaid. The circumstance, if it be the fact, that the Company is now or may hereafter be carrying on business and maintaining its properties in certain incorporated municipalities in Florida and in certain areas in Florida outside of incorporated municipalities without franchises or any determination that any franchises under which the Company is now or may hereafter be operating are or may be invalid as against municipalities incorporated subsequently to the granting of such franchises shall not be deemed a violation of any of the covenants contained in this Section.

Section 6.04. After Acquired Property; Instruments of Further Assurance; Recordation and Opinion, etc.

(a) Any and all property hereafter acquired by the Company, and any and all improvements, extensions, betterments or additions to property of the Company, which by this Indenture are to become subject hereto, immediately upon the acquisition thereof by the Company or upon such improvements, extensions, betterments or additions being made, as the case may be, and without any further conveyance, mortgage, assignment or act on the part of the Company or of the Trustee shall become and be subject to the Lien of this Indenture, as fully and completely as though now owned by the Company and specifically described in the Granting Clauses hereof; but nevertheless, the Company will from time to time execute, acknowledge and delivery any and all such further assurances, conveyances, mortgages, or assignments thereof as are required by the terms and provisions of this Indenture or as the Trustee may reasonably require.

(b) The Company will cause this Indenture and any and all Supplemental Indentures, Extension Notices and instruments of further assurance at all times to be kept recorded, filed and registered in such manner and in such places as may, according to an Opinion of Counsel, be required by law in order fully to preserve and protect the rights of the Bondholders and the Trustee hereunder as to all property comprising the Trust Estate, and, without in anywise limiting the generality of the foregoing covenant, the Company will furnish to the Trustee:

(i) promptly after the execution and delivery of this Indenture and of each indenture supplemental hereto, an Opinion of Counsel containing the statements required by Section 1.05(b) and stating that in the opinion of such counsel this Indenture or such Supplement Indenture as the case may be, has been properly recorded, filed and registered so as to make effective the Lien intended to be created thereby, and reciting the details of such action, or stating that in opinion of such counsel no such action is necessary to make such Lien effective; provided that the requirements of this Clause (i) shall be complied with if such Opinion of Counsel shall state that this Indenture or such Supplemental Indenture has been received for record, filing or registration in each public office in which it is required to be recorded, filed or registered and that in the opinion of such counsel no further action needed be taken by the Company to make effective the Lien intended to be created thereby;

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(ii) on or before May 1 of each year, beginning with the year 1947,

(A) an Opinion of Counsel containing the statements required by Section 1.05(b) and either stating that in the opinion of such counsel such action has been taken with respect to the recording, filing, rerecording and refiling of this Indenture and of all previous Supplemental Indentures, or the execution, filing and/or recording of any further Supplemental Indenture or Extension Notice, as is necessary to maintain the Lien of this Indenture, as supplemented, and effectually to subject to such Lien any additional land or interest in land or new plant or system acquired by the Company, and reciting the details of such action, or stating that in the opinion of such counsel no such action is necessary for the purposes aforesaid; and

(B) such additional Supplemental Indentures, Extension Notices or other instruments as may be specified as necessary for any of the purposes aforesaid in the Opinion of Counsel required by the foregoing Clause (A).

Section 6.05. Lien of Indenture and Maintenance of Priority Thereof. This Indenture is and always will be kept a first Lien upon the Trust Estate, subject only to Permitted Encumbrances and Prior Liens (to the extent herein authorized) and, except as otherwise herein expressly permitted, the Company will not create or suffer to be created any mortgage, lien or charge having priority to or preference over, or ranking on a parity with, the Lien of this Indenture upon the Trust Estate or any part thereof or upon the income therefrom; and the Company will from time to time pay or cause to be paid, as the same shall become due and payable and before they become delinquent, all taxes, assessments, governmental charges or levies which may be levied or assessed or imposed upon the Trust Estate or any part thereof or in connection with the operation of the same or upon any income therefrom and also (to the extent that such payment will not be contrary to any applicable laws relating to usury applying to corporate obligations and that such payment will not otherwise be unlawful) all taxes, assessments, governmental charges or levies which may be levied or assessed or imposed upon the Lien or interest of the Trustee or, of the Bondholders in the Trust Estate, so that (to the extent aforesaid) the Lien of this Indenture shall at all times be wholly preserved at the cost of the Company and without expense to the Trustee or the Bondholders; and the Company will not suffer any mechanics’, materialmen’s or other similar Liens to remain upon the Trust Estate, or any part thereof, the Lien whereof might be held to be prior to or on a parity with the Lien of this Indenture; and the Company will not suffer any other matter or thing whatsoever whereby the Lien hereby created might be impaired; provided, however, that if the Company shall have set aside on its books reserves deemed by it adequate therefor, the Company shall have the right to contest, in good faith by appropriate proceedings, any such taxes, assessments, charges, levies or Liens, and pending such contest may delay or defer the payment thereof, unless thereby property subject to the Lien of this Indenture will be in danger of being forfeited or lost.

Section 6.06. Trust Estate to be Kept in Repair - Rights to be Maintained, etc.

(a) The Company will not, except as herein permitted, do or suffer any act or thing whereby the Trust Estate might or could be impaired and it will at all times maintain, preserve and keep all the Trust Estate and every part thereof in good condition, repair and working order

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and equipped with suitable machinery and appliances. The Company from time to time will make all needful and proper repairs, replacements, additions, betterments, and improvements so that the operations and business of the Company pertaining to the Trust Estate and every part thereof shall at all times be conducted properly and advantageously, and so that at all times the efficiency of such property shall be fully maintained.

(b) Except as otherwise permitted hereby, the Company will perform or comply with all the conditions, covenants, stipulations and provisions of any and all leases or other instruments under which it holds rights included in the Trust Estate and will promptly pay all rentals and other indebtedness accruing thereunder and will do all other things necessary to keep unimpaired the Company’s rights thereunder and to prevent any forfeiture or termination thereof.

(c) Nothing herein contained shall, however, be held to prevent the Company from permanently discontinuing the operation of any of its properties if such discontinuance is, in the opinion of the Company, necessary, desirable or advisable in the conduct of the business of the Company and not disadvantageous to the Holders of the Bonds; nor to prevent the Company from taking or causing to be taken such action with respect to the use of its properties as is proper under the circumstances, including the cessation or omission to exercise rights, permits, licenses, privileges or franchises which, in the opinion of the Company, can no longer be profitably exercised or availed of.

Section 6.07. Insurance and Disposition of Proceeds.

(a) The Company will at all times keep all its plants, buildings, stations, machinery, equipment, supplies, tools and apparatus which are subject to the Lien of this Indenture and are of an insurable nature and of the character usually insured by companies operating similar properties, insured in a reasonable amount against loss or damage by fire and from other causes customarily insured against by similar companies. All such insurance shall be carried in responsible insurance companies selected by the Company in good faith.

(b) All policies or other contracts for insurance upon any part of the Trust Estate shall provide that the proceeds of such insurance, except as to any particular loss not exceeding $10,000,000 in amount, shall be payable to the Trustee as its interest may appear (by means of standard mortgagee clause without contribution, if obtainable); provided, however, that in the event that any property subject to this Indenture shall also be subject to a Prior Lien any insurance policies or contracts with respect to such property may be payable also to the trustee or other holder of such Prior Lien as its interest may appear.

(c) All proceeds of insurance received by the Trustee under the provisions of this Section shall be held by the Trustee and paid over or applied by the Trustee as provided with respect to Available Cash in Section 7.06.

(d) All proceeds of any insurance on the Trust Estate, to the extent that the same shall not be payable to the Trustee as aforesaid or to the trustee or other holder of a Prior Lien, shall be applied by the Company to the repair, restoration or replacement of the property destroyed or damaged or other additions to Bondable Property of the Company.

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(e) After an Event of Default, in case of any loss covered by any policy of insurance, any appraisement or adjustment of such loss and settlement which may be agreed upon between the Company and the insurance company shall be consented to and accepted by the Trustee.

Section 6.08. Prior Lien Indebtedness.

(a) The Company will not acquire any property which at the time of acquisition thereof shall be or become subject to any Prior Lien, other than liens securing the unpaid purchase price of net equipment or machinery, (i) if at the date of acquisition of such property the principal amount of indebtedness secured by such Prior Lien or Prior Liens shall exceed 60% of the Cost to the Company of the property so acquired, and (ii) if such property, prior to the acquisition thereof by the Company, was operated by another in a business similar to that carried on or to be carried on by the Company, unless the net earnings of such property, for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the date of acquisition, computed (except with respect to depreciation or obsolescence) as nearly as may be in the manner set forth in Section 1.04 for the computation of the net earnings of the Company, but after deduction of actual charges or provisions for depreciation or obsolescence, shall have been at least twice the actual interest charges upon the Prior Lien Indebtedness to be secured by such Prior Lien or Prior Liens Outstanding immediately after the acquisition of such property by the Company.

(b) The Company will not permit any increase in the aggregate principal amount of the Outstanding indebtedness secured by any Prior Lien to the extent such increase would cause the sum of the principal amount of all Outstanding Prior Lien Indebtedness plus all Outstanding Bonds to exceed 60% of the sum of (i) Available Cash and (ii) the lesser of the Cost or Fair Value of the Company’s Additional Property as of the date of such increase.

(c) In case the Company shall, as hereinabove permitted, acquire any Bondable Property subject to any Prior Lien, the interest of the Company in all such property shall at all times be subject to the Lien of this Indenture and, if and when the title to such property shall vest in the Company free and clear of such Prior Lien, then such property shall forthwith be and become subject to the Lien of this Indenture as a first mortgage thereon, subject only to Permitted Encumbrances as herein defined.

Section 6.09. Disposition of Cash, etc. Held Under Discharged Prior Lien. Upon the cancellation and discharge of any Prior Lien, the Company will cause all cash or purchase money obligations then held by the trustee or other holder of such Prior Lien, which were received by such trustee or other holder by reason of the release of, or which represent the proceeds of the taking by eminent domain or any other disposition of, or the proceeds of insurance on, any of the Trust Estate (including all proceeds of or substitutes for any thereof), to be paid to and/or deposited and pledged with the Trustee, subject to no Lien or charge prior to the Lien of this Indenture, such cash to be held paid over or applied by the Trustee as provided in Section 7.06, and such purchase money obligations constituting Investment Securities to be held and disposed of as provided in Section 1.16 and otherwise liquidated and paid over and applied as provided in Section 7.06; provided, however, that in lieu of paying or delivering to the Trustee all or any part of such cash or purchase money obligations, the Company may deliver to the Trustee (i) a certificate of the trustee or other holder of some other Prior Lien, stating that a specified amount thereof has been deposited with such trustee or other holder pursuant to the requirements of such other Prior Lien, and (ii) an Opinion of Counsel stating that such deposit is required by such other Prior Lien.

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Section 6.10. Limitations on Disposition of Trust Estate. The Company will not sell or otherwise voluntarily dispose of a part (less than substantially all) of the Trust Estate except as provided in Article Seven and it will not consolidate or merge with or into, or sell, convey, transfer or lease the Trust Estate as an entirety or substantially as an entirety to, any other Corporation, except as provided in Article Twelve.

Section 6.11. Annual Filing of Certificate as to No Default. On or before May 1 of each year, beginning with the year 1947, the Company will deliver to the Trustee an Officers’ Certificate, complying with Section 1.05(b), stating whether or not, to the best of the knowledge of the signers, the Company is in default in the performance of any covenant, agreement or condition contained herein, and if so, specifying each such default of which the signers may have knowledge.

ARTICLE SEVEN

Possession, Use and Release of Trust Estate

Section 7.01. Use, Possession and Disposition of Trust Estate. Unless an Event of Default shall have occurred and be continuing, the Company shall be suffered and permitted to possess, use and enjoy all the Trust Estate (except cash, securities or other personal property pledged or deposited with or required to be pledged or deposited with the Trustee hereunder), and to receive and use the rents, revenues, issues, earnings, income, products and profits thereof, including interest or dividends on and other income from stocks and other securities and purchase money obligations held by the Trustee, with power in the ordinary course of business, freely and without let or hindrance on the part of the Trustee or of the Bondholders, to use, consume, sell or otherwise dispose of materials and supplies, deal with closes in action, contracts and leases, exercise the rights and powers conferred upon it thereby, alter, repair and change the location of any of its plants, buildings, works, structures, transmission and distribution systems and equipment, and replace or renew any of its equipment, machinery or other property, except that the position of none of the Trust Estate may be changed so as to impair the lien of this Indenture thereon unless such property is released, sold, exchanged, abandoned or otherwise disposed of as permitted by some provision of this Article.

Section 7.02. Additional Rights and Powers of Company with respect to Trust Estate.

(a) The Company may at any time and from time to time, without any release or consent by the Trustee:

(i) Disposition of Worn-Out, Unserviceable, etc. Property. Sell, exchange or otherwise dispose of, free from the Lien of this Indenture, any apparatus, tools, implements, machinery or equipment subject to the Lien of this Indenture, which has become worn out, unserviceable, undesirable or unnecessary for use in the conduct of its business, upon replacing the same with, or substituting for the same, new apparatus,

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tools, implements, machinery or equipment or other property, not necessarily of the same character but of a value and utility at least equal to that of the property so disposed of and which shall be Bondable Property if the property disposed of was Bondable Property, which new apparatus, tools, implements, machinery, equipment or other property shall without further action become subject to the Lien of this Indenture;

(ii) Demolition or Abandonment of Worn-Out, Unserviceable, etc. Property. In the ordinary course of business, demolish, dismantle, tear down, abandon or surrender any property which has become worn out, unserviceable or unnecessary for use in the conduct of the Company’s business;

(iii) Termination or Change in Contracts, Leases, Easements, Rights-of-Way, Grants, Franchises, etc. Abandon, terminate, cancel, release or make changes in, alterations of or substitutions for any and all contracts, leases, easements or right-of-way grants, franchises, licenses, consents and permits, provided that such action is, in the opinion of the President or a Vice-President of the Company, necessary, desirable or advisable in the conduct of the business of the Company;

(iv) Granting or Conveying Rights-of-Way. Grant or convey rights-of-way and easements over or in respect to any real property owned by the Company, provided that such grant or conveyance will not materially impair the usefulness of such real property in the conduct of the business of the Company.

(b) In the event of any change, alteration or substitution pursuant to Section 7.02(a)(iii), the changed, altered or substituted easement, right-of-way grant or lease, right, power, franchise, license, governmental consent or permit, as the case may be, shall be subject to the Lien of this Indenture to the same extent and in the same manner as those previously existing.

(c) The Company either (i) shall apply any net cash proceeds received for or in connection with the taking of any of the steps authorized by this Section 7.02, in acquiring or in reimbursing itself for other property or rights, not necessarily of the same character but of a value at least equal for the purposes of the Company to that of the property or rights disposed of, which shall forthwith become a part of the Trust Estate, or (ii) if and to the extent that net proceeds of Property Additions exceed $10,000,000 and are not so applied within twelve calendar months after receipt thereof or such further period as the Trustee shall deem reasonable, shall deposit the same with the Trustee. In the event the conditions provided in Section 7.06(a) for such withdrawal of the net cash proceeds required to be deposited hereunder shall be satisfied contemporaneously, the Company shall be excused from depositing such net cash proceeds under this Section with the Trustee upon delivery to the Trustee of the documents required to be delivered under Section 7.06(a).

(d) The Trustee shall, from time to time, upon the written request of the Company, execute any release and/or consent requested to confirm any action taken by the Company pursuant to this Section, but only upon receipt by the Trustee of an Officers’ Certificate and an Opinion of Counsel that the execution of such release and/or consent is appropriate to confirm action taken by the Company pursuant to this Section and that Trustee is authorized and permitted to execute such release or provide the requested consent.

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Section 7.03. Release of Trust Estate. Unless an Event of Default shall have occurred and be continuing, the Company may obtain the release of any part of the Trust Estate, or any interest therein, other than cash held by the Trustee and other than Trust Estate to which the provisions of Section 7.04 are applicable, and the Trustee shall release all its right, title and interest in and to the same from the Lien of this Indenture, upon receipt by the Trustee of:

(a) A Company Order requesting the release of such property and transmitting therewith a form of instrument or instruments to effect such release;

(b) An Officers’ Certificate stating that, to the knowledge of the signers, no Event of Default has occurred and is continuing;

(c) An Experts’ Certificate made and dated not more than 90 days prior to the first day of the month in which such Company Order is delivered to the Trustee:

(i) Describing the property to be released;

(ii) Stating the Fair Value, in the judgment of the signers, of the property to be released;

(iii) Stating the Cost of the property to be released (or, if the Fair Value to the Company of such property at the time such property was first included in an Experts’ Certificate was less than the Cost thereof, then such Fair Value, in lieu of Cost);

(iv) Stating that, in the judgment of the signers, such release will not impair the security under this Indenture in contravention of the provisions hereof;

(v) Stating the aggregate principal amount of Bonds and Prior Lien Indebtedness Outstanding on the date of such Experts’ Certificate; and

(vi) Stating that, after giving effect to the transactions contemplated thereby, including payment, from the proceeds thereof, of any taxes and expenses incidental to any sale, exchange, dedication or other disposition of the property to be released, the Company would be permitted by the provisions of Section 3.01 to have authenticated and delivered at least $1.00 of additional Bonds;

(d) The amount in cash, if any, then required to be deposited with the Trustee in order to permit the Company to meet the requirement of clause (c)(vi) above; and

(e) An Opinion of Counsel to the effect that:

(i) this Indenture constitutes, or, upon the delivery of, and/or the filing and/or recording in the proper places and manner of, the instruments of conveyance, assignment or transfer, if any, specified in said opinion, will constitute, a direct first mortgage lien, subject only to Permitted Encumbrances, upon the interest of the Company in the Property Additions; and

(ii) the Company has corporate authority to operate such Property Additions.

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Any cash deposited with the Trustee pursuant to the provisions of this Section 7.03 shall be held as part of the Trust Estate and shall be withdrawn, released, used or applied in the manner, to the extent and for the purposes, and subject to the conditions, provided in Section 7.06.

Section 7.04. Release of Property Taken by Eminent Domain, Etc. Should any of the Trust Estate, or any interest therein, be taken by exercise of the power of eminent domain or be sold to an entity possessing the power of eminent domain in lieu of its exercise of the same, and should the Company elect not to obtain the release of such property pursuant to other provisions of this Article, the Trustee shall, upon request of the Company evidenced by a Company Order transmitting therewith a form of instrument or instruments to effect such release, release from the Lien of this Indenture all its right, title and interest in and to the property so taken or sold (or with respect to an interest in property, subordinate the Lien of this Indenture to such interest), upon receiving (a) an Opinion of Counsel to the effect that such property has been taken by exercise of the power of eminent domain or has been sold to an entity possessing the power of eminent domain under threat of an exercise of such power, (b) an Officers’ Certificate stating the amount of net proceeds received or to be received for such property so taken or sold, and the amount so stated shall be deemed to be the Fair Value of such property for the purpose of any notice to the Holders of Bonds, (c) an Experts’ Certificate stating the Cost thereof (or, if the Fair Value to the Company of such portion of such property at the time the same was first included in an Experts’ Certificate was less than the Cost thereof, then such Fair Value, as so certified, in lieu of Cost) and (d) a deposit by the Company of an amount in cash equal to the Cost or Fair Value stated in the Experts’ Certificate delivered pursuant to clause (c) above; provided, however, that the amount required to be so deposited shall not exceed the portion of the net proceeds received or to be received for such property so taken or sold which is allocable on a pro-rata or other reasonable basis to such property. Any cash deposited with the Trustee under this Section may, contemporaneously or thereafter, be withdrawn, used or applied in the manner, to the extent and for the purposes, and subject to the conditions, provided in Section 7.06. In the event the conditions provided in Section 7.06(a) for such withdrawal of the amount required to be deposited hereunder shall be satisfied contemporaneously, the Company shall be excused from depositing such amount under this Section with the Trustee upon delivery to the Trustee of the documents required to be delivered under Section 7.06(a).

Section 7.05. Release of Minor Properties.

(a) Notwithstanding the provisions of Section 7.03, unless an Event of Default shall have occurred and be continuing, the Company may obtain the release from the Lien of this Indenture of any part of the Trust Estate, or any interest therein, and the Trustee shall whenever from time to time requested by the Company in a Company Order transmitting therewith a form of instrument or instruments to effect such release, and without requiring compliance with any of the provisions of Section 7.03, release from the Lien of this Indenture all the right, title and interest of the Trustee in and to the same provided that the lesser of the aggregate Cost or the aggregate Fair Value of the property to be so released on any date in a given calendar year, together with all other property theretofore released pursuant to this Section 7.05 in such calendar year, shall not exceed the greater of (i) 1.5% of the sum of the aggregate principal amount of all Bonds then Outstanding and (ii) $10,000,000.

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(b) Prior to the granting of any such release, there shall be delivered to the Trustee (x) an Officers’ Certificate stating that, to the knowledge of the signers, no Event of Default has occurred and is continuing and that such release is authorized pursuant to this Section 7.05 and (y) an Experts’ Certificate stating, in the judgment of the signers, the Fair Value of the property to be released, the aggregate Fair Value of all other property theretofore released pursuant to this Section in such calendar year, and that, in the judgment of the signers, the release thereof will not impair the security under this Indenture in contravention of the provisions hereof.

Section 7.06. Withdrawal or Other Application of Cash. Except as hereafter in this Section provided, unless an Event of Default shall have occurred and be continuing, any Available Cash held by the Trustee, and any other cash which is required to be withdrawn, used or applied as provided in this Section

(a) may be withdrawn from time to time by the Company upon receipt by the Trustee of: (i) a Company Order requesting the withdrawal, use or application of such cash and transmitting appropriate instructions, (ii) an Officers’ Certificate stating that, to the knowledge of the signer, no Event of Default has occurred and is continuing; (iii) an Experts’ Certificate made and dated not more than 90 days prior to the first day of the month in which such Company Order is delivered to the Trustee stating the aggregate principal amount of Bonds and Prior Lien Indebtedness Outstanding on the date of such Experts’ Certificate, and stating that, after giving effect to the transactions contemplated thereby, (A) the Company would be permitted by the provisions of Section 3.01 to have authenticated and delivered at least $1.00 of additional Bonds or, (B) if the Company cannot meet this requirement, stating the lesser amount of such cash which could be so withdrawn, used or applied by the Company and still enable the Company to meet the requirements of subsection (A) of this clause (a) of Section 7.06, which lesser amount may be so withdrawn; and (iv) an Opinion of Counsel to the effect that: (A) this Indenture constitutes, or, upon the delivery of, and/or the filing and/or recording in the proper places and manner of, the instruments of conveyance, assignment or transfer, if any, specified in said opinion, will constitute, a direct first mortgage lien, subject only to Permitted Encumbrance, upon the interest of the Company in the Property Additions; and (B) the Company has corporate authority to operate such Property Additions;

(b) may, upon the request of the Company, be released by the Trustee to the Company for the purchase of Bonds in the manner, at the time or times, in the amount or amounts, at the price or prices and otherwise as directed or approved by the Company, all subject to the limitations hereafter in this Section set forth; or

(c) may, upon the request of the Company, be applied by the Trustee to the payment (or provision therefor pursuant to Article Eight) at Stated Maturity of any Bonds or to the redemption (or similar provision therefor) of any Bonds which are, by their terms, redeemable, in each case of such series as may be designated by the Company, any such redemption to be in the manner and as provided in Article Five, all subject to the limitations hereafter in this Section set forth.

Notwithstanding the generality of clauses (b) and (c) above, no cash to be applied pursuant to such clauses shall be applied to the payment of an amount in excess of the principal amount of any Bonds to be purchased, paid or redeemed except to the extent that the aggregate principal

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amount of all Bonds theretofore, and of all Bonds then to be, purchased, paid or redeemed pursuant to such clauses is not less than the aggregate cost for principal of, premium, if any, and accrued interest, if any, on and brokerage commissions, if any, with respect to, such Bonds.

Section 7.07. Disclaimer or Quitclaim. In case the Company has sold, exchanged, dedicated or otherwise disposed of, or has agreed or intends to sell, exchange, dedicate or otherwise dispose of, or a Governmental Authority has ordered the Company to divest itself of, any Excepted Property or any other property not subject to the Lien of this Indenture, or the Company desires to disclaim or quitclaim title to property to which the Company does not purport to have title, the Trustee shall, from time to time, disclaim or quitclaim such property upon receipt by the Trustee of the following:

(a) A Company Order requesting such disclaimer or quitclaim and transmitting therewith a form of instrument to effect such disclaimer or quitclaim;

(b) An Officers’ Certificate describing the property to be disclaimed or quitclaimed; and

(c) An Opinion of Counsel stating the signer’s opinion that such property is not subject to the Lien of this Indenture or required to be subject thereto by any of the provisions hereof and complying with the requirements of Section 1.05(b) of this Indenture.

Section 7.08. General Provisions as to Releases.

(a) The Experts’ Certificate as to the Fair Value of property to be released from the Lien of this Indenture in accordance with any provision of this Article, and as to the nonimpairment, by reason of such release, of the security under this Indenture in contravention of the provisions hereof, shall be made by an Independent Expert if the Fair Value of such property and of all other property released since the commencement of the then current calendar year, as set forth in the certificates required by this Indenture, is 10% or more of the aggregate principal amount of all Bonds then Outstanding; but such Experts’ Certificate shall not be required to be made by an Independent Expert in the case of any release of property if the Fair Value thereof, as set forth in the certificates required by this Indenture, is less than $25,000 or less than 1% of the aggregate principal amount of all Bonds then Outstanding. To the extent that the Fair Value of any property to be released from the Lien of this Indenture shall be stated in an Independent Experts’ Certificate, such Fair Value shall not be required to be stated in any other Experts’ Certificate delivered in connection with such release.

(b) No release of property from the Lien of this Indenture effected in accordance with the provisions, and in compliance with the conditions, set forth in this Article and in Section 1.05 shall be deemed to impair the security of this Indenture in contravention of any provision hereof.

Section 7.09. Exercise of Powers under Article Seven while an Event of Default Exists.

(a) In case of an Event of Default shall have occurred and be continuing, the Company, while in possession of the Trust Estate (other than securities and cash held by the Trustee or the trustee or other holder of a Prior Lien), may do any of the things enumerated in

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Section 7.01 to 7.05, both inclusive, if the Trustee, acting at the direction of the Holders of at least a majority in principal amount of the Bonds at the time Outstanding, shall in writing expressly authorize or consent to such action, in which event the certificate required by Section 7.03(b) or Section 7.06(a)(ii) need not contain the statement that no Event of Default has occurred and is continuing.

(b) In case the Trust Estate (other than securities and cash held by the Trustee or the trustee or other holder of a Prior Lien) shall be in the possession of a receiver or trustee lawfully appointed, the powers in this Article conferred upon the Company with respect to the sale or other disposition of the Trust Estate may be exercised by such receiver or trustee (subject to authorization or consent of the Trustee or Bondholders as hereinabove in this Section provided), in which case a written request signed by said receiver or trustee shall be deemed the equivalent of the written request of the Company required by Section 7.03, 7.04 or 7.05 and a certificate signed by such receiver or trustee shall be deemed the equivalent of any Officers’ Certificate required by any provision of this Indenture. If during an Event of Default the Trustee shall be in possession of the Trust Estate (other than securities and cash held by the Trustee or the trustee or other holder of a Prior Lien) under any provision of this Indenture, then such powers may be exercised by the Trustee in its discretion.

Section 7.10. Non-responsibility of Purchasers for Authority of Trustee, etc. No purchaser in good faith of property purporting to be released herefrom shall be bound to ascertain the authority of the Trustee to execute the release or to inquire as to the existence of any conditions required by the provisions hereof for the exercise of such authority; nor shall any purchaser or grantee of any property or rights permitted by this Article to be sold, granted or otherwise disposed of by the Company be under any obligation to ascertain or inquire into the authority of the Company to make any such sale, grant or other disposition, or look to the application of the purchase money.

Section 7.11. Lien on Reacquired Property. Any property constituting part of the Trust Estate which is sold, exchanged or otherwise disposed of by the Company and released from the Lien of this Indenture and which is thereafter required by the Company shall without further action become subject to the Lien of this Indenture.

Section 7.12. Separability of Release Provisions. Sections 7.01 to 7.07, inclusive, and Section 7.09, except as therein specified, shall not be construed as being in limitation of one another, but as separate and independent methods of releasing or disposing of property.

ARTICLE EIGHT

Satisfaction and Discharge

Section 8.01. Satisfaction and Discharge of Bonds.

(a) Any Bond or Bonds, or any portion of the principal amount thereof, shall be deemed to have been paid and no longer Outstanding for all purposes of this Indenture, and the entire indebtedness of the Company in respect thereof shall be deemed to have been satisfied and discharged, if there shall have been irrevocably deposited with the Trustee or any Paying Agent (other than the Company), in trust:

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(i) money in an amount which shall be sufficient, or

(ii) in the case of a deposit made prior to the Maturity of such Bonds or portions thereof, Eligible Obligations, which shall not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide moneys which, together with the money, if any, deposited with or held by the Trustee or such Paying Agent, shall be sufficient, or

(iii) a combination of (i) or (ii) which shall be sufficient

to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Bonds or portions thereof on or prior to Maturity; provided, however, that in the case of the provision for payment or redemption of less than all the Bonds of any series, such Bonds or portions thereof shall have been selected by the Trustee as provided herein; and provided, further, that the Company shall have delivered to the Trustee and such Paying Agent:

(w) if such deposit shall have been made prior to the Maturity of such Bonds, a Company Order stating that the money and Eligible Obligations deposited in accordance with this Section shall be held in trust, as provided in Section 8.03;

(x) if such Bonds are to be redeemed prior to Maturity, (A) proof satisfactory to the Trustee that notice of redemption of such Bonds has been duly given or waived, or (B) an irrevocable order of the Company authorizing the Trustee to give such notice for and on behalf of the Company, or (C) evidence satisfactory to the Trustee that such notice will be given or waived;

(y) if Eligible Obligations shall have been deposited, an Officers’ Certificate to the effect that such obligations constitute Eligible Obligations and do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, and a report of an Independent Accountant of nationally recognized standing, selected by the Company, to the effect that the other requirements set forth in clause (ii) or (iii) above have been satisfied; and

(z) if such deposit shall have been made prior to the Maturity of such Bonds, an Officers’ Certificate stating the Company’s intention that, upon delivery of such Officers’ Certificate, its indebtedness in respect of such Bonds or portions thereof will have been satisfied and discharged as contemplated in this Section.

(b) Upon the deposit of money or Eligible Obligations, or both, in accordance with this Section, together with the documents required by clauses (w), (x), (y) and (z) above, the Trustee shall, upon receipt of a Company Request, acknowledge in writing that the Bond or Bonds or portions thereof with respect to which such deposit was made are deemed to have been paid for all purposes of this Indenture and that the entire indebtedness of the Company in respect of such Bonds has been satisfied and discharged as contemplated in this Section. In the event that

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all of the conditions set forth in the preceding paragraph shall have been satisfied in respect of any Bonds or portions thereof except that, for any reason, the Officers’ Certificate specified in clause (z) shall not have been delivered, such Bonds or portions thereof shall nevertheless be deemed to have been paid for all purposes of this Indenture, and the Holders of such Bonds or portions thereof shall nevertheless be no longer entitled to the benefits provided by this Indenture or of any of the covenants of the Company under Article Six (except the covenants contained in Section 6.02 or any other covenants made in respect of such Bonds or portions thereof as contemplated by Section 2.01 or Section 13.01(b), but the indebtedness of the Company in respect of such Bonds or portions thereof shall not be deemed to have been satisfied and discharged prior to Maturity for any other purpose and the Holders of such Bonds or portions thereof shall continue to be entitled to look to the Company for payment of the indebtedness represented thereby; and, upon Company Request, the Trustee shall acknowledge in writing that such Bonds or portions thereof are deemed to have been paid for all purposes of this Indenture.

(c) If payment at Stated Maturity of less than all of the Bonds of any series is to be provided for in the manner and with the effect provided in this Section, the Trustee shall select such Bonds, or portions of principal amount thereof, in the manner specified by Section 5.03 for selection for redemption of less than all the Bonds of a series.

(d) In the event that Bonds which shall be deemed to have been paid for purposes of this Indenture, and, if such is the case, in respect of which the Company’s indebtedness shall have been satisfied and discharged, all as provided in this Section, do not mature and are not to be redeemed within the 60-day period commencing with the date of the deposit of moneys or Eligible Obligations, as aforesaid, the Company shall, as promptly as practicable, give a notice, in the same manner as a notice of redemption with respect to such Bonds, to the Holders of such Bonds to the effect that such deposit has been made and the effect thereof.

(e) Notwithstanding that any Bonds shall be deemed to have been paid for purposes of this Indenture, as aforesaid, the obligations of the Company and the Trustee in respect of such Bonds under Sections 2.04, 2.05, 2.06, 5.03, 6.02 and 10.10 and this Article shall survive such satisfaction and discharge.

(f) The Company shall pay, and shall indemnify the Trustee or any Paying Agent with which Eligible Obligations shall have been deposited as provided in this Section against, any tax, fee or other charge imposed on or assessed against such Eligible Obligations or the principal or interest received in respect of such Eligible Obligations, including, but not limited to, any such tax payable by any entity deemed, for tax purposes, to have been created as a result of such deposit.

(g) Anything herein to the contrary notwithstanding, (i) if, at any time after a Bond would be deemed to have been paid for purposes of this Indenture, and, if such is the case, the Company’s indebtedness in respect thereof would be deemed to have been satisfied and discharged, pursuant to this Section (without regard to the provisions of this paragraph), the Trustee or any Paying Agent, as the case may be, (A) shall be required to return the money or Eligible Obligations, or combination thereof, deposited with it as aforesaid to the Company or its representative under any applicable Federal or State bankruptcy, insolvency or other similar law, or (B) is unable to apply any money in accordance with this Article with respect to any Bonds by

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reason of any order or judgment of any court or governmental authority enjoining, restraining or otherwise prohibiting such application, such Bond shall thereupon be deemed retroactively not to have been paid and any satisfaction and discharge of the Company’s indebtedness in respect thereof shall retroactively be deemed not to have been effected, and such Bond shall be deemed to remain Outstanding and (ii) any satisfaction and discharge of the Company’s indebtedness in respect of any Bond shall be subject to the provisions of Section 8.06.

Section 8.02. Satisfaction and Discharge of Mortgage.

(a) This Indenture shall upon Company Request cease to be of further effect (except as hereinafter expressly provided), and the Trustee, at the expense of the Company, shall execute such instruments as the Company shall reasonably request to evidence and acknowledge the satisfaction and discharge of this Indenture , when:

(i) no Bonds remain Outstanding hereunder; and

(ii) the Company has paid or caused to be paid all other sums payable hereunder by the Company;

provided, however, that if, in accordance with Section 8.01(g), any Bond, previously deemed to have been paid for purposes of this Indenture, shall be deemed retroactively not to have been so paid, this Indenture shall thereupon be deemed retroactively not to have been satisfied and discharged, as aforesaid, and to remain in full force and effect, and the Company shall execute and deliver such instruments as the Trustee shall reasonably request to evidence and acknowledge the same; provided, further, however, in the absence of a Company Request to have the Trust Estate revert to it and to have the Lien of this Indenture cancelled and discharged, the fact that all indebtedness secured by this Indenture shall have been fully paid and satisfied shall not render this Indenture inoperative or prevent the Company from again and from time to time issuing Bonds hereunder pursuant to the terms and conditions hereof.

(b) Notwithstanding the satisfaction and discharge of this Indenture as aforesaid, the obligations of the Company and the Trustee under Sections 2.04, 2.05, 2.06, 5.03, 6.02 and 10.10 and this Article shall survive such satisfaction and discharge.

(c) Upon satisfaction and discharge of this Indenture as provided in this Section, the Trustee shall assign, transfer and turn over to the Company, subject to the Lien provided by Section 10.10, any and all money, securities and other property then held by the Trustee for the benefit of the Holders of the Bonds (other than money and Eligible Obligations held by the Trustee pursuant to Section 8.03) and shall execute and deliver to the Company such instruments as, in the judgment of the Company, shall be necessary, desirable or appropriate to effect or evidence the satisfaction and discharge of this Indenture.

Section 8.03. Application of Trust Money. Neither the Eligible Obligations nor the money deposited pursuant to Section 8.01, nor the principal or interest payments on any such Eligible Obligations, shall be withdrawn or used for any purpose other than, and shall be held in trust for, the payment of the principal of and premium, if any, and interest, if any, on the Bonds or portions of principal amount thereof in respect of which such deposit was made, all subject, however, to the provisions of Section 8.06; provided, however, that so long as there shall not

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have occurred and be continuing an Event of Default, any cash received from such principal or interest payments on such Eligible Obligations, if not then needed for such purpose, shall, to the extent practicable and upon Company Request and delivery to the Trustee of the documents referred to in clause (y) of Section 8.01(a), be invested in Eligible Obligations of the type described in Section 8.01(a)(ii) maturing at such times and in such amounts as shall be sufficient, together with any other moneys and the proceeds of any other Eligible Obligations then held by the Trustee, to pay when due the principal of and premium, if any, and interest, if any, due and to become due on such Bonds or portions thereof on and prior to the Maturity thereof, and interest earned from such reinvestment shall be paid over to the Company as received, free and clear of any trust, Lien or pledge under this Indenture (except the Lien provided by Section 10.10); and provided, further, that, so long as there shall not have occurred and be continuing an Event of Default, any moneys held in accordance with this Section on the Maturity of all such Bonds in excess of the amount required to pay the principal of and premium, if any, and interest, if any, then due on such Bonds shall be paid over to the Company free and clear of any trust, Lien or pledge under this Indenture (except the Lien provided by Section 10.10); and provided, further, that if an Event of Default shall have occurred and be continuing, moneys to be paid over to the Company pursuant to this Section shall be held until such Event of Default shall have been waived or cured.

Section 8.04. Payment of Principal and Interest to Holders. All sums which may become due and payable for principal (and premium, if any) upon any Bond issued hereunder shall be paid to the registered owner thereof or his assigns, but only upon surrender of such Bond. The interest on Bonds shall be paid only to the registered owners thereof.

Section 8.05. Transfer to Trustee of Moneys Held by Paying Agent. For the purpose of obtaining the satisfaction and discharge of this Indenture the Company may require any Paying Agent to pay to the Trustee all moneys held by it, and upon the satisfaction and discharge of this Indenture all moneys then held by any Paying Agent for any series of Bonds shall, upon demand of the Company, be repaid to it. Upon any such payment such Paying Agent shall be released from all further liability with respect to such moneys.

Section 8.06. Repayment to Company of Unclaimed Moneys. Notwithstanding any provisions of this Indenture, any moneys deposited with the Trustee or any Paying Agent in trust for the payment of the principal of, or interest or premium (if any, on, any Bonds and remaining unclaimed for six years after the Maturity of all the Bonds issued hereunder (whether at their Stated Maturity or upon call for redemption or by declaration as provided in this Indenture) shall then be repaid to the Company upon its written request, and the Holders of such Bonds shall thereafter be entitled to look only to the Company as an unsecured creditor for payment thereof, and all liability of the Trustee or any Paying Agent with respect to such moneys shall thereupon cease; provided, however, that before the repayment of such moneys to the Company as aforesaid, the Trustee or Paying Agent, as the case may be, may at the expense of the Company cause to be mailed, on one occasion only, notice to such Holders that such money remains unclaimed and that, after a date specified therein, which shall not be less than 30 days from the date of such mailing, any unclaimed balance of such money will be repaid to the Company.

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ARTICLE NINE

Events of Default and Remedies

Section 9.01. Default, Acceleration, Rescission of Acceleration. The following events are hereby defined for all purposes of this Indenture (except where the term is otherwise defined for specific purposes) as “Events of Default”, namely:

(a) failure to pay the principal of, or premium (if any) on, any Bond when and as the same shall become due and payable, whether at Maturity as therein expressed, by proceedings for redemption, by declaration or otherwise;

(b) failure to pay interest on any Bond for a period of 30 days after such interest shall have become due and payable;

(c) failure to discharge or satisfy any sinking, improvement, maintenance, or renewal and replacement fund obligation for a period of 60 days after such obligation shall have become due as in this Indenture expressed;

(d) failure to perform or observe any other of the covenants, agreements or conditions on the part of the Company in this Indenture or in any of the Bonds contained, and the continuance of such failure for a period of 90 days after written notice thereof to the Company by the Trustee or to the Company and to the Trustee by the Holders of not less than 15% in principal amount of the Bonds Outstanding;

(e) either (1) the entry of an order approving a petition seeking reorganization of the Company under the Federal bankruptcy laws or any other applicable law or statute of the United States of America or any State thereof; or (2) the appointment in any judicial proceeding of a trustee or a receiver of all or a substantial part of the trustee estate; and the continuance of such order or appointment unstayed on appeal or otherwise and in effect for a period of 90 days;

(f) entry of an order for relief against the Company by a court of competent jurisdiction in an involuntary case or proceeding, or the commencement by the Company of a voluntary proceeding, under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law, or the making by the Company of an assignment for the benefit of creditors or the admission by the Company in writing of its inability to pay its debts as they become due; the consent by the Company to the appointment in any judicial proceeding of a receiver or trustee of all or a substantial part of the Trust Estate; the filing by the Company of a petition or answer seeking reorganization or readjustment under the Federal bankruptcy laws, or any other applicable law or statute of the United States of America or of any State thereof; or the filing by the Company of a petition to take advantage of any insolvency act;

(g) the rendering against the Company of a judgment for the payment of moneys in excess of the sum of $50,000,000 and the continuance of such judgment unsatisfied and without stay of execution thereon for a period of 90 days after the entry of such judgment, or the continuance of such judgment unsatisfied for a period of 90 days after the termination of any stay of execution thereon entered within such first mentioned 90 days; but only in either case if such judgment shall have been continued unstayed or unsatisfied for a period of 10 days after written notice of default hereunder shall have been given to the Company by the Trustee, or to the Company and the Trustee by the Holders of not less than 15% in principal amount of the Bonds Outstanding; or

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(h) any other Event of Default with respect to Bonds of a series as shall have been specified in the terms thereof as provided in Section 2.01(o).

In case one or more of such Events of Default, other than such Events of Defaults under clauses (e) or (f) above, shall have occurred and be continuing, then, in each and every case, unless the principal of all the Bonds shall have already become due and payable, either the Trustee (by notice in writing to the Company) or the Holders of not less than 25% in principal amount of all the Bonds Outstanding (by notice in writing to the Company and the Trustee) may declare the principal of all the Bonds then Outstanding, and the interest accrued thereon, to be due and payable immediately, and upon any such declaration the same shall become and be immediately due and payable, anything in this Indenture or in any of the Bonds contained to the contrary notwithstanding; provided, however, that upon the occurrence of an Event of Default under Clause (e) or (f) all of the Bonds then Outstanding, and the interest occurred thereon, shall be immediately due and payable without any notice or other action by the Trustee or any Holder of the Bonds.

This provision, however, is subject to the condition that, if at any time after the principal of all the Bonds shall have been so declared due and payable, and before any sale of all or any substantial part of the Trust Estate shall have been made, all arrears of interest upon all the Bonds, with interest, so far as the same may be legally enforceable, on overdue installments of interest at the same rates respectively borne by the Bonds the interest on which shall be in default, together with the reasonable charges and expenses of the Trustee, its agents and attorneys, and all other sums which may have become due and payable by the Company under this Indenture, other than the principal of such Bonds as shall not have become due and payable by their terms (other than upon such declaration) or upon call for redemption, shall either be paid by the Company to those entitled thereto (or to the Trustee for their account) or be collected out of the income from or earnings of the Trust Estate, and all other defaults known to the Trustee under the Bonds or under this Indenture shall be made good or be cured to the satisfaction of the Trustee, or provision deemed by the Trustee to be adequate shall be made therefor, or shall have been waived as in Section 9.23 provided, then and in every case the Holders of not less than a majority in principal amount of the Bonds then Outstanding, by written notice to the Company and to the Trustee, before any sale or all or any part of the Trust Estate pursuant to the provisions of this Article Nine, may annul any such declaration and its consequences under this Indenture.

Section 9.02. Power of Trustee Upon Default. In case one or more of the Events of Default shall have occurred and be continuing, then and in each and every such case the Trustee, personally or by its attorneys or agents, is hereby authorized and empowered, whether or not the principal of the Bonds shall have matured or been declared due, to exercise any one or more of the following remedies, and to do or cause to be done any or all of the following acts and things, namely:

(a) The Trustee, by its agents or attorneys, may (provided such action shall not at the time be in violation of any laws applicable to the Company or its properties) enter into and upon and take possession of any or all of the Trust Estate and each and every part thereof, and may

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exclude the Company, its successors or assigns, its or their agents, servants and employees wholly therefrom, and have, hold, use, operate, manage and control wholly therefrom, and have, hold, use, operate, manage and control the same and each and every part thereof and, in the name of the Company or otherwise as the Trustee shall deemed best, conduct the business thereof and exercise the franchises pertaining thereto and all the rights and powers of the Company, and use all of the then existing property and assets of the Company for that purpose, and at the expense of the Trust Estate from time to time, maintain, restore, insure and keep insured the properties, plants, equipment and apparatus provided or required for use in connection with such business and likewise, from time to time, at the expense of the Trust Estate, make all such necessary or proper repairs, renewals and replacements, and all such useful alterations, additions, betterments and improvements as to the Trustee may seem judicious, and collect and receive all tolls, earnings, income, rents, issues, profits and revenues of the same and of every part thereof, and after deducting therefrom the expenses of operation and all expenses incurred hereunder and all other property outlays herein authorized, and all payments which may be made for taxes, assessments and other Liens prior hereto and charges upon the Trust Estate or any part thereof, as well as just and reasonable compensation for the services of the Trustee and for the services of such attorneys, agents and assistants as it may in the exercise of its discretion employ for any of the purposes aforesaid, the Trustee shall apply the rest and residue of such moneys received by them, or either of them, as follows:

(i) In case the principal of none of the Bonds shall have become due, to the payment of the interest in default, in the order of the Maturity of the installments of such interest, with interest, so far as the same may be legally enforceable, on the overdue installments thereof at the same rates, respectively, as were borne by the Bonds on which such interest shall be in default, such payments to be made ratably to the parties entitled thereto without discrimination or preference.

(ii) In case the principal of any, but not all, of the Bonds shall have become due, first to the payment of the interest in default, in the order of the Maturity of the installments thereof, with interest, so far as the same may be legally enforceable, on the overdue installments thereof at the same rates, respectively, as were borne by the Bonds on which such interest shall be in default, and next to the payment of the principal of all Bonds then due, with interest on the overdue principal at the rates specified in the respective Bonds, such payments to be made ratably to the parties entitled thereto without discrimination or preference.

(iii) In case the principal of all of the Bonds shall have become due, by declaration or otherwise, then as provided in Paragraph Second of Section 9.11.

In case all payments provided for in Clause (i) and (ii) above and payment of whatever may be payable for any other purpose required by any provision of this Indenture shall have been made in full, and no sale shall have been made as hereinafter provided, and compliance shall have been made by the Company with all other provisions of this Indenture as to which it shall be in default, the Trustee shall restore the possession of the Trust Estate (other than any cash and/or securities required to be deposited or pledged with the Trustee) to the Company or whosoever shall be entitled thereto.

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(b) The Trustee may, with or without entry, collect or enforce the collection of all dividends and interest payable in respect of any stocks, bonds, notes or other evidences of indebtedness which may at the time be held in pledge hereunder, and/or may exercise in its discretion any or all of the voting power represented by any such pledged securities, if any. Any sums so collected or received by the Trustee shall be held and applied by the Trustee in like manner as is provided in the foregoing Subdivision (a) of this Section in respect of tolls, earnings, income, rents, issues, profits and revenues collected or received by the Trustee from or on account of the Trust Estate.

(c) The Trustee may (if such action shall at the time be authorized by law), with or without entry, sell, subject to the Prior Liens, if any, then existing thereon or free from such of said Liens as the Trustee in its discretion may elect to discharge, to the highest and best bidder, all or any part or parts of the Trust Estate and of the right, title, interest, claim and demand of the Company therein and thereto, and the right of redemption thereof, at public auction, at such times and places and upon such conditions as to upset or reserve bids or prices and as to terms of payment and other terms of sale as the Trustee may fix and briefly specify in the notice of sale to be given as hereinafter provided, or as may be required by law, including power and authority to the Trustee to rescind or vary any contract of sale that may be entered into and to resell under the powers herein conferred.

(d) The Trustee may proceed to protect and enforce its rights and the rights of the Bondholders under this Indenture by a suit or suits in equity or at law, whether for the specific performance of any covenant or agreement contained in this Indenture, or in aid of the execution of any power granted in this Indenture, or for the foreclosure of this Indenture, or for the enforcement of any other appropriate legal or equitable remedy as the Trustee being advised by counsel, shall, subject to the provisions of Section 10.02 and 10.03, deem most effectual to protect and enforce any of the rights aforesaid.

Section 9.03. Right to Judicial Sale; Appointment of Receiver. In case the Trustee shall proceed by suit or suits at law or in equity, after a default, it shall be entitled to have the Trust Estate sold by judicial sale or sales under the orders, judgments or decrees of a court or courts of competent jurisdiction, or under executory or other legal process, for or toward the satisfaction of the principal and interest then due or owing on the Bonds then Outstanding, and for the enforcement of the rights, Liens and benefits of the Trustee and the Bondholders, and shall be entitled, pending any such suit or proceedings, as a matter of right, to the appointment of a receiver of the Trust Estate and of the rents, earnings, revenues, issues, profits and income thereof, with such powers as the court making such appointment may confer; but, notwithstanding the appointment of any receiver, the Trustee shall be entitled as pledgee to the possession and control of any cash or securities at the time deposited or pledged with, or required by the provisions hereof to be deposited and pledged with, the Trustee.

Section 9.04. Sale as Entirety or in Parcels. In the event of any sale, whether made under the power of sale herein granted or by virtue of judicial proceedings, the whole of the Trust Estate shall be sold in one parcel and as an entirety, unless such sale as an entirely, in the judgment of the Trustee, shall not be practicable or desirable in the interest of the Bondholders, or unless the Holders of not less than a majority in principal amount of the Bonds at the time Outstanding shall in writing request the Trustee to cause the Trust Estate to be sold in parcels, or

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the court entering the decree of sale shall so direct, in which case the sale shall be made in such parcels and in such order as in the former case the Trustee may determine and in the latter case as may be specified in such request or decree, but, if not so specified, as the Trustee in its discretion shall deem most expedient in the interest of the Bondholders. The Company, for itself, its successors and assigns, and for all Persons and Corporations hereafter claiming through or under it or them or who may at any time hereafter become holders of Liens junior to the Lien of this Indenture, hereby expressly waives and releases all right to have the Trust Estate or any part thereof marshaled upon any foreclosure, sale or other enforcement hereof; and the Trustee or any court in which the foreclosure of this Indenture or the administration of the trusts hereby created is sought, shall have the right as aforesaid to sell the entire Trust Estate as a whole in a single parcel, unless otherwise required by law.

Section 9.05. Notice of Sale. Notice of any sale pursuant to any provision of this Article Nine shall state the time and place, when and where the same is to be made, shall contain a brief general description of the property to be sold and shall briefly state the terms of the sale, and shall be sufficiently given (unless otherwise required by law), (i) with respect to all real property, if published in a newspaper printed in the English language customarily published on each Business Day and of general circulation, once each week for four successive calendar weeks prior to such sale in the City of Tampa, Florida, and (ii) with respect to any personal property if given to the Company and any others entitled thereto under applicable law at least ten days before the date of any such sale or disposition.

Section 9.06. Adjournment of Sale. The Trustee may adjourn from time to time any sale to be made by them under the provisions of this Indenture by announcement at the time and place appointed for such sale or for such adjourned sale or sales, and, without further notice or publication (unless otherwise required by law), they may make such sale at the time and place to which the same may be adjourned.

Section 9.07. Purchaser Not Liable for Application of Purchase Money. The receipt or receipts of the Trustee or of the court officer conducting any such sale, for the purchase money paid at or under any such sale, shall be a sufficient discharge therefor to any purchaser of the property or any part thereof sold as aforesaid; and no such purchaser, or his representatives, grantees, or assigns, after paying such purchase money and receiving such receipt, shall be bound to see to the application of such purchase money upon or for any trust or purpose of this Indenture, or in any manner whatsoever be answerable for any loss, misapplication or non-application of any such purchase money or any part thereof, or be bound to inquire as to the authorization, necessity, expediency or regularity of any such sale.

Section 9.08. Application of Bonds toward Purchase Price, etc. Upon any sale, as aforesaid, any purchaser, for the purpose of making settlement or payment for the property purchased, shall be entitled to use and apply any Bonds then Outstanding, and any claims for interest thereon, by presenting the same to the Trustee so that there may be credited, as paid thereon, the sums payable out of the net proceeds of such sale to the Holder of such Bonds or claims as his ratable share of such net proceeds after allowing for the proportions of the total purchase price required to be paid in cash for the cost and expenses of sale, compensation and other charges; and thereupon such purchaser shall be credited on account of such purchase price payable by him with the portion of such net proceeds that shall be applicable to the payment of,

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and that shall have been credited upon, the Bonds and claims so presented; and at any such sale any Bondholder or Bondholders may bid for and purchase such property, and make payment on account thereof as aforesaid, and, upon compliance with the terms of sale, may hold, retain and dispose of such property without further accountability therefor.

Section 9.09. Conveyance of Property to Purchaser. Upon the completion of any sale or sales under or by virtue of this Indenture, the Trustee shall execute and deliver to the purchaser a good and sufficient deed or other instruments conveying, assigning and transferring the property sold. The Trustee is hereby irrevocably appointed the true and lawful attorney of the Company, in its name and stead, to make all necessary conveyances, assignments and transfers of property thus sold; and for that purpose may execute all necessary deeds and instruments of conveyance, assignment and transfer, and may substitute one or more Persons with like power, the Company hereby ratifying and confirming all that its said attorney, or such substitute or substitutes, shall lawfully do by virtue thereof. Nevertheless, the Company, if so requested by the Trustee, shall ratify and confirm any such sale or sales by executing and delivering to the Trustee or to such purchaser or purchasers all such instruments as may be necessary or in the judgment of the Trustee proper for the purpose and as may be designated in such request.

Section 9.10. Sale a Bar against Company. Any such sale or sales, whether made under the power of sale herein granted or pursuant to judicial proceedings, shall operate to divest all right, title, interest, claim and demand whatsoever, either at law or in equity, of the Company in and to the premises sold, and shall be a perpetual bar both at law and in equity against the Company, its successors and assigns, and against all and any Persons now or hereafter claiming the premises sold or any part thereof from, through or under the Company or its successors or assigns.

Section 9.11. Application of Proceeds of Sale. The purchase money, proceeds and avails of any sale, whether made under the power of sale herein granted or pursuant to judicial proceedings, together with any other sums which then may be held by the Trustee under any provision of this Indenture as part of the Trust Estate or the proceeds thereof, shall be applied in the following order:

FIRST. To the payment of the costs and expenses of such sale and reasonable compensation of the Trustee, its agents, attorneys and counsel, and of all necessary or proper expenses, liabilities and advances made or incurred by the Trustee, without negligence or bad faith, under this Indenture or in executing any power or trust hereunder, and to the payment of all taxes, assessments or Liens superior to the Lien of this Indenture, except any taxes, assessments or other superior Liens subject to which such sale shall have been made;

SECOND. To the payment of the whole amount then owing and unpaid upon the Bonds then Outstanding for principal and interest, with interest, so far as the same may be legally enforceable, on overdue principal and overdue installments of interest at the same rates, respectively, as were borne by the respective Bonds, and, in case such proceeds shall be insufficient to pay in full the whole amount so due and unpaid upon the Bonds, then to the payment of such principal and

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interest, without preference or priority of principal over interest, or of interest over principal, or of any installment of interest over any other installment of interest, or of the Bonds of any series over the Bonds of any other series, ratably to the aggregate of such principal and unpaid interest; and such payments shall be made on the date fixed therefor by the Trustee upon presentation of the several Bonds and stamping such payment thereof, if partly paid, and upon surrender and cancellation thereof, if fully paid; and

THIRD. To the payment of the surplus, if any, to the Company, its successors or assigns, or to whosoever may be lawfully entitled to receive the same, or as a court of competent jurisdiction may direct.

Section 9.12. Acceleration of Maturity of Bonds Upon Sale. In case of any sale, whether made under the power of sale herein granted or pursuant to judicial proceedings, the principal of all the Bonds, if not previously due, together with all accrued and unpaid interest thereon, immediately thereupon shall become due and payable, anything in the Bonds or in this Indenture contained to the contrary notwithstanding.

Section 9.13. Covenants of Company to Pay Bonds, with Interest if any is Due; Proof of Debt by Trustee; Recovery of Judgment by Trustee and Application of Proceeds.

(a) The Company covenants that in case it shall fail to pay any interest on any Bond or Bonds at any time Outstanding, and/or to pay the principal of or premium, if any, on any such Bonds when the same shall have become payable, whether at the Maturity of said Bonds, by call thereof for redemption, or by a declaration as herein provided, or otherwise, then the Company will pay to the Trustee, for the benefit of the Holders of the Bonds then Outstanding, the whole amount then due and payable on all such Bonds then Outstanding, for interest, principal and premium, if any, with interest upon the overdue principal and premium, if any, and overdue installments of interest at the same rates, respectively, as were borne by the respective Bonds; and, in case the Company shall fail to pay the same forthwith, the Trustee, shall be entitled in its own name and as trustee of an express trust to recover judgment against the Company or any other obligor upon the Bonds for the whole amount so due and unpaid.

(b) The Trustee shall be entitled in its own name and as trustee of an express trust, or as attorney in fact for the owners of the Bonds, to file such proofs of debt, amendments to proofs of debt, petitions or other documents and to take such other actions (including sitting on a committee of creditors) as may be necessary in order to have the claims of the owners of the Bonds allowed in any equity receivership, insolvency, liquidation, readjustment, reorganization, bankruptcy or other similar proceeding involving the Company or any other obligor upon the Bonds or the property or the creditors of the Company or of any such obligor. The Trustee is hereby appointed, and the successive respective owners of the Bonds issued hereunder, by taking and holding the same, shall be conclusively deemed to have so appointed the Trustee (subject to deduction from any such claim of the amounts of any claims filed by any Holders of the Bonds themselves) the true and lawful attorney in fact of the respective owners of the Bonds issued hereunder, with authority to make and file, in any such proceeding, either in the respective names of the owners of the Bonds or in behalf of all owners of the Bonds as a class, any proof of debt, amendment to proof of debt, petition or other document; to receive payment of any sums

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becoming distributable on account thereof; and to execute any other papers and documents and to do and perform any and all such acts and things as may be necessary or advisable, in the opinion of the Trustee, in order to have the respective claims of the owners of the Bonds against the Company or any other obligor upon the Bonds allowed in any such proceeding. The Trustee shall have full power of substitution and delegation in respect of any such powers.

(c) Nothing herein shall be deemed, however, to give power to the Trustee to vote the claims of the Holders of the Bonds in any such proceeding, or to accept or consent to any plan or reorganization, readjustment, arrangement, or composition or other like plan, or by other action of any character in any such proceeding to waive or change any right of any Holder of the Bonds.

(d) The Trustee shall be entitled to recover judgment or make or file proof of debt as aforesaid either before or after or during the pendency of any proceedings for the enforcement of the Lien of this Indenture, and the right of the Trustee to recover such judgment or make such proof of debt shall not be affected by any entry or sale hereunder, or by the exercise of any other right, power or remedy for the enforcement of the provisions of this Indenture or the foreclosure of the Lien of this Indenture, and in the case of a sale of the Trust Estate, and of the application of the proceeds of sale to the payment of the indebtedness hereby secured, the Trustee in its own name and as trustee of an express trust shall be entitled to enforce payment of and to receive all amounts then remaining due and unpaid upon any and all of the Bonds then Outstanding, for the benefit of the Holders thereof, and shall be entitled to recover judgment or make or file proof of debt for any portion of the indebtedness remaining unpaid, with interest, as aforesaid. No recovery of any such judgment by the Trustee nor any attachment or levy of execution under any such judgment upon the Trust Estate or any part thereof, or upon any other property, nor any such proof of debt, shall in any manner or to any extent affect the Lien of this Indenture upon the Trust Estate or any part thereof, or any Lien, rights, powers or remedies of the Trustee, or of the Holders of the Bonds, but such Lien, rights, powers and remedies shall continue unimpaired as before.

(e) Any moneys collected by the Trustee under this Section shall be applied in the following order:

FIRST. To the payment of the costs and expenses of the proceedings resulting in the collection of such moneys, the reasonable compensation of the Trustee, its agents, attorneys and counsel, and of all necessary or proper expenses, liabilities and advances made or incurred by the Trustee, without negligence or bad faith, under this Indenture or in executing any trust or power hereunder; and

SECOND. To the payment of the amounts then due and unpaid upon the Bonds and for interest in respect whereof such moneys shall have been collected, ratably and without any preference or priority of any kind according to the amounts due and payable upon such Bonds and for interest, respectively, to the date fixed by the Trustee for the distribution of such moneys, upon presentation of the several Bonds, and stamping such payment thereon, if partly paid, and upon surrender and cancellation thereof, if fully paid.

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Section 9.14. Proceedings by Trustee to Protect Security. The Trustee when directed in writing by the Holders of not less than a majority in principal amount of the Bonds then Outstanding, shall have power to institute and to maintain such suits and proceedings in accordance with the direction of said Holders or as it may be advised by counsel shall be necessary or expedient to prevent any impairment of the security hereunder by any acts of the Company, or of others, which are unlawful, or as it may be advised by counsel shall be necessary or expedient to preserve or protect its interests and the interests of the Bondholders in respect of the Trust Estate, and in respect of the income, earnings, issues and profits arising therefrom, including the power to institute and to maintain suits or proceedings to restrain the enforcement of, or compliance with, or the observance of, any legislative, municipal or other governmental enactment, rule, or order that may be or may appear to the Trustee to be unconstitutional or otherwise invalid, if the enforcement of, compliance with, or observance of, such enactment, rule or order would impair the security hereunder or be prejudicial to the interests of the Bondholders or of the Trustee.

Section 9.15. Payment by Trustee or Bondholders of Amounts Payable by Company. Upon failure of the Company so to do, either any receiver appointed hereunder, or the Holders of not less than 25% in principal amount of the Bonds then Outstanding, may make any payment (other than of the principal, interest and/or any sinking or purchase fund in respect of the Bonds) which the Company by any provision of this Indenture agrees to make or cause to be made, and the Company covenants and agrees that it will forthwith repay to such receiver or to the Bondholders all moneys which such receiver or the Bondholders shall so pay, and will pay interest thereon from the date of such payment by such receiver or the Bondholders until the repayment thereof at the rate of 6% per annum; and until so paid such advances shall be secured by a Lien under and by virtue of this Indenture upon the Trust Estate, in preference to the Bonds issued hereunder. No such payment by any such receiver or by the Bondholders shall be deemed to relieve the Company from the consequence of any default hereunder.

Section 9.16. Waiver of Stay or Extension Laws, etc. The Company agrees, to the extent it may lawfully do so, that it will not at any time insist upon, plead, or in any manner whatever claim, take or insist upon the benefit or advantage of any stay or extension law now or at any time hereafter in force; nor will it claim, take or insist upon any benefit or advantage of any law now or at any time hereafter in force providing for the valuation or appraisement of the Trust Estate or any part thereof prior to any sale or sales thereof to be made pursuant to any provisions herein contained or to the decree, judgment or order of any court of competent jurisdiction; nor after any such sale or sales will it claim or exercise any right under or conferred by any law now or at any time hereafter in force to redeem the property sold or any part thereof; and it hereby expressly waives, renounces and relinquishes all benefit and advantage of any and all such stay, extension, valuation, appraisement and redemption law or laws; and it hereby covenants that it will not hinder, delay or impede the execution of any power herein granted or delegated to the Trustee, but that it will suffer and permit the execution of every such power as though no such law or laws had been made or enacted.

Section 9.17. Waiver of Service of Process and Consent to Entry of Judgment by Company. The Company, for itself, its successors and assigns, hereby expressly covenants to and with the Trustee that, at and immediately upon the commencement of any action, suit or other legal proceeding by the Trustee, (1) to obtain possession of the Trust Estate, or any part

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thereof, the Company, its successors and assigns, shall and will, severally, waiving the issuance and service of process, enter its or their voluntary appearance in such action, suit or proceedings, and consent to the entry of a judgment for the recovery and possession of the Trust Estate and every part thereof; (2) for the foreclosure of the Lien of this Indenture, the Company, its successors and assigns, shall and will, severally, waiving the issuance and service of process, enter its or their voluntary appearance in such action, suit or proceeding and consent to the appointment of a receiver of the Trust Estate and the tolls, income and revenues thereof for the sole benefit of the Holders of the Bonds; and (3) pursuant to the provisions hereof to obtain judgment for the principal of or interest on any of the Bonds or for both, or to obtain a judgment or decree of any other nature in aid of the enforcement of the Bonds or any of them, or of this Indenture, the Company, its successors or assigns, shall and will, severally, waiving the issuance and service of process, enter its or their voluntary appearance in such action, suit or proceeding and consent to the entry of a judgment for such principal and/or interest, with interest on overdue principal and installments of interest, and for the lawful costs and expenses and compensation of the Trustee and its agents and attorneys, and for such other relief as the Trustee may be entitled to under the provisions hereof.

Section 9.18. Personal Property Deemed Real Estate. The personal property and chattels mortgaged, pledged, and transferred pursuant to the provisions hereof, or intended so to be, both those now held and those hereafter acquired, shall be deemed real estate for all the purposes of this Indenture and shall be held and taken to be fixtures and appurtenances of the Company’s real estate and, in case of a foreclosure sale of the property hereunder whether by legal process, judicial sale or under the powers hereof or otherwise, the same may be sold therewith and in the same manner and not separate therefrom, except as herein otherwise provided.

Section 9.19. Surrender of Possession of Trust Estate to Trustee or Receiver. Upon application of the Trustee, and with the consent of the Company, if none of the Events of Default have occurred and are continuing, and without such consent if one or more of such Events of Default shall have occurred and be continuing, a receiver may be appointed to take possession of, and to operate, maintain and manage the Trust Estate or any part thereof, and the Company shall transfer and deliver to such receiver possession of the Trust Estate, wheresoever the same may be situated; but, notwithstanding the appointment of any receiver, the Trustee shall be entitled as pledgee to the possession and control of any cash and/or securities at the time held by, or payable or deliverable under the provisions of this Indenture to, the Trustee. In every case, when a receiver of the whole or any part of the Trust Estate shall be appointed under this Section or otherwise, the net income and profits of the Trust Estate shall be paid over to, and shall be received by, the Trustee for the benefit of the Holders of the Bonds.

Section 9.20. Rights of Bondholders to Control Proceedings by Trustee. In the event an Event of Default shall have occurred and be continuing, anything in this Indenture to the contrary notwithstanding, the Holders of not less than a majority in aggregate principal amount of the Bonds then Outstanding shall, if they so elect and manifest such election by an instrument or concurrent instruments in writing executed and delivered to the Trustee, have the right (1) to require the Trustee to proceed to enforce the Lien of this Indenture, either by suit or suits at law or in equity for the enforcement of the payment of the Bonds then Outstanding hereunder and for the foreclosure of this Indenture and for the sale of the Trust Estate under the judgment or decree of a court

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of competent jurisdiction, or at the election of the Trustee by exercise of its powers with respect to entry or sale, and (2) to direct and control the time, method and place of conducting any and all proceedings hereby authorized for any sale of the Trust Estate, or any adjournment thereof, or for the foreclosure of this Indenture, or for the appointment of a receiver, or any other action or proceeding hereunder instituted by the Trustee, provided, however, that such direction shall not be otherwise then in accordance with the provisions of law and this Indenture, and the Trustee shall not be responsible to anyone for any action taken or omitted by them in good faith pursuant to any such direction; and, provided further, that such Holders shall have offered the Trustee security and indemnity satisfactory to it against loss, liability or expense to be incurred therein or thereby; and, provided further, that, subject to the provisions of Sections 10.02 and 10.03, the Trustee shall have the right to decline to follow any such direction if the Trustee shall be advised by counsel that the action or proceedings so directed may not be lawfully taken or if the Trustee in good faith shall by Responsible Officers determine that the action or proceeding so directed would involve the Trustee in personal liability or be unjustifiably prejudicial to the non-assenting Bondholders, or that it will not be sufficiently indemnified for any expenditures in any action or proceeding so directed.

Section 9.21. Limitation on Bondholders’ Right to Sue.

(a) No Holder of any Bond issued hereunder shall have the right to institute any suit, action or proceeding in equity or at law for the foreclosure of this Indenture, or for the execution of any trust or power hereof, or for the appointment of a receiver, or for the enforcement of any other remedy under or upon this Indenture, unless

(i) such Holder shall have previously given to the Trustee written notice of some existing default, as hereinbefore provided;

(ii) the Holders of not less than 25% in principal amount of the Bonds at the time Outstanding shall, after the right to exercise such powers, or right of action, as the case may be, shall have accrued, have requested the Trustee in writing to act;

(iii) such Holder or Holders shall have offered to the Trustee security and indemnity satisfactory to it against the costs, expenses and liabilities to be incurred therein or thereby, without negligence or bad faith; and

(iv) the Trustee shall have refused or neglected to comply with such request for a period of 60 days.

(b) Without the consent of any Bondholder nothing in this Indenture shall impair the right of such Holder, which is absolute and unconditional, to receive payment of the principal of and interest on such Bond on or after the due date thereof as therein expressed, or to institute suit for the enforcement of any such payment on or after such due date, or the obligation of the Company, which is also absolute and unconditional, to pay the principal of and interest on each of the Bonds to the respective Holders thereof at the time and place in said Bonds expressed.

Section 9.22. Waiver of Period of Grace by Company. The Company may waive any period of grace provided for in this Article Nine.

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Section 9.23. Waiver of Certain Defaults by Bondholders. Anything elsewhere in this Indenture to the contrary notwithstanding, the Holder or Holders of 75% or more in principal amount of the Bonds then Outstanding (including, if more than one series of Bonds be at the time Outstanding, not less than 60% in principal amount of the Bonds of each such series) may, by written instrument or instruments, signed by such Bondholders and delivered to the Trustee and to the Company, waive any past Event of Default hereunder and its consequences, except a default in the payment of the principal of, premium, if any, or interest on any of the Bonds as and when the same shall become due by the terms of such Bonds and upon such waiver such default or Event of Default shall be deemed not to exist for any purpose of this Indenture.

Section 9.24. Delay or Omission in Exercising Remedy Not Waiver of Default. No delay or omission of the Trustee or of any Holder of Bonds to exercise any right or power arising from any Event of Default shall impair any such right or power or shall be construed as a waiver of such Event of Default or an acquiescence therein, nor shall the action of the Trustee or of the Bondholders, in case of any Event of Default and the subsequent waiver of such Event of Default, affect or impair the rights of the Trustee or of such Holders in respect of any subsequent Event of Default on the part of the Company or impair any right resulting therefrom; and every right, power and remedy given by this Article Nine to the Trustee or to the Bondholders, respectively, may be exercised from time to time and as often as may be deemed expedient by the Trustee or by the Bondholders, respectively.

Section 9.25. Effect of Abandonment of Foreclosure or Other Proceedings. In case the Trustee shall have proceeded to enforce any right, power or remedy under this Indenture, by foreclosure or otherwise, and such proceedings shall have been discontinued or abandoned because of any waiver as in this Article Nine provided or for any other reason, or shall have been determined adversely to the Trustee then and in each and every such case the Company and the Trustee shall be restored to their former positions and rights hereunder in respect of the Trust Estate, and all rights, powers and remedies of the Trustee shall continue as though no such proceedings had been taken.

Section 9.26. Remedies Cumulative. Unless herein expressly provided to the contrary, no remedy herein conferred upon or reserved to the Trustee, or the Holders of the Bonds is intended to be exclusive of any other remedy, but each and every such remedy shall be cumulative and shall be in addition to every other remedy given hereunder or how or hereafter existing at law or in equity or by statute; and the employment of any remedy hereunder or otherwise shall not prevent the concurrent employment of any other appropriate remedy or remedies.

Section 9.27. Rights of Action Enforceable by Trustee without Possession or Production of Bonds. All rights of action under this Indenture may be enforced by the Trustee to the extent permitted by the provisions hereof, without the possession of any of the Bonds or the production thereof on the trial or other proceedings relative thereto.

Section 9.28. Remedies in Article Nine Subject to Applicable Laws. All of the rights, remedies and powers provided for in this Article Nine may be exercised only to the extent that the exercise thereof does not violate any applicable provisions of law in the premises, and all of the provisions of this Article Nine are intended to be subject to all applicable mandatory

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provisions of law that may be controlling in the premises and to be limited to the extent necessary in order that they will not render this Indenture invalid or unenforceable in whole or in part or prevent the recording or filing thereof under the provisions of any applicable law.

ARTICLE TEN

The Trustee

Section 10.01. Qualifications of Trustee.

(a) The Trustee shall at all times be a corporation organized and doing business under the laws of the United States, or of any State or the District of Columbia, with a combined capital and surplus of at least $50,000,000 and authorized under such laws to exercise corporate trust powers and subject to supervision or examination by Federal or State authority. If the Trustee publishes reports of condition at least annually, pursuant to law or to the requirements of any supervising or examining authority referred to in this Section, then for the purposes of this Section the combined capital and surplus of the Trustee shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published.

(b) The Company covenants that whenever necessary to avoid or fill a vacancy in the office of trustee, it will, in the manner provided in Section 10.17, appoint a trustee so that there shall at all times be a trustee eligible under this Section.

Section 10.02. Acceptance of Trust and Duties and Responsibility of Trustee before and after Default.

(a) The Trustee hereby accepts the trust hereby created. The Trustee undertakes, prior to the occurrence of an Event of Default, and after the curing of all Events of Default which may have occurred, to perform such duties and only such duties as are specifically set forth in this Indenture, and in case of the occurrence of a default (which has not been cured) to exercise such of the rights and powers vested in them by this Indenture, and to use the same degree of care and skill in their exercise, as a prudent man would exercise or use under the circumstances in the conduct of his own affairs.

(b) For the purposes of this Section 10.02 and of Section 10.03, an Event of Default shall be deemed cured when the act or omission or other event giving rise to such Event of Default shall have been remedied or terminated. If a default is waived as provided in Section 9.23, such default shall be deemed to have been cured.

(c) The Trustee shall not be deemed to have knowledge or be charged with knowledge of any Default or Event of Default except for any Default or Event of Default of which the Trustee shall have received written notification which references the Bonds and this Indenture or of which a Responsible Officer shall have obtained actual knowledge.

(d) Whether or not expressly so provided, every provision of this Indenture relating to the conduct or affecting the liability or affording protection to the Trustee (in any capacity, including Paying Agent or Security Registrar) shall be subject to the provisions of this Section 10.02 and Section 10.03.

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Section 10.03. Extent of Liability of Trustee.

(a) No provision of this Indenture shall be construed to relieve the Trustee from liability for its own negligent action, its own negligent failure to act, or its own willful misconduct, except that

(i) prior to the occurrence of an Event of Default hereunder and after the curing of all Events of Default which may have occurred, the Trustee shall not be liable except for the performance of such duties as are specifically set forth in this Indenture, and no implied covenants or obligations shall be read into this Indenture against the Trustee but the duties and obligation of the Trustee prior to an Event of Default and after the curing of all Events of Default which may have occurred, shall be determined solely by the express provisions of this Indenture;

(ii) prior to the occurrence of an Event of Default hereunder and after the curing of all Events of Default which may have occurred, and in the absence of bad faith on the part of the Trustee, the Trustee may conclusively rely as to the truth of the statements and the correctness of opinions expressed herein, upon certificates or opinions conforming to the requirements of this Indenture; but in the case of any such certificate or opinion which by any provision hereof is specifically required to be furnished to the Trustee, the Trustee shall be under a duty to examine the same to determine whether or not it conforms to the requirements of this Indenture;

(iii) the Trustee shall not be personally liable for any error of judgment made in good faith by a Responsible Officer or Responsible Officers thereof, unless it shall be proved that the Trustee was negligent in ascertaining the pertinent facts; and

(iv) the Trustee shall not be personally liable with respect to any action taken or omitted to be taken by it in good faith in accordance with the direction of the Holders of not less than a majority in principal amount of the Bonds at the time Outstanding, or such lesser amount as shall be required by this Indenture, or their attorneys-in-fact duly authorized, evidenced as provided in Section 1.06, relating to the time, method, and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred upon the Trustee under this Indenture.

(b) None of the provisions contained in this Indenture shall require the Trustee to expend or risk its own funds or otherwise incur personal financial liability in the performance of any of its duties or in the exercise of any of its rights or powers, if there is reasonable ground for believing that the repayment of such funds or liability is not reasonably assured to it under the terms of this Indenture or adequate indemnity against such risk of expense and liability is not reasonably assured to it.

(c) Before the Trustee acts or refrains from acting, it may require an Officers’ Certificate or an Opinion of Counsel or both. The Trustee shall not be liable for any action it takes or omits to take in good faith in reliance on such Officers’ Certificate or Opinion of Counsel. The Trustee may consult with counsel of its own selection and the advice of such counsel and Opinions of Counsel with respect to legal matters relating to this Indenture and the Bonds shall be full and complete authorization and protection from liability in respect of any action taken, suffered or omitted by it hereunder in good faith and in reliance thereon.

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(d) The Trustee shall be under no obligation to exercise any of the rights or powers vested in it by this Indenture at the request, order or direction of any of the Bondholders, pursuant to the provisions of this Indenture, unless such Bondholders shall have offered to the Trustee security or indemnity reasonably satisfactory to it against the costs, expenses and liabilities that may be incurred therein or thereby.

(e) The Trustee shall not be liable for any action taken or omitted to be taken by it in good faith and believed by it to be authorized or within the discretion or rights or powers conferred upon it by this Indenture and the permissive right of the Trustee to take or refrain from taking any actions enumerated in this Indenture shall not be construed as a duty.

(f) The Trustee shall not be bound to make any investigation into the facts or matters stated in any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, approval, bond, security, or other papers or documents, but the Trustee, in its discretion, may make even further inquiry or investigation into such facts or matters as it may see fit; and, if the Trustee shall determine to make such further inquiry or investigation, it shall be entitled to examine the books, records and premises of the Company, personally or by agent or attorney at the sole cost of the Company and shall incur no liability or additional liability of any kind by reason of such inquiry or investigation.

(g) The Trustee may execute any of the trusts or powers hereunder or perform any duties hereunder either directly or by or through agents or attorneys and the Trustee shall not be responsible for any misconduct or negligence on the part of any agent or attorney appointed with due care by it hereunder.

(h) Anything in this Indenture notwithstanding, in no event shall the Trustee be liable for special, indirect, punitive or consequential loss or damage of any kind whatsoever (including but not limited to loss of profit), even if the Trustee has been advised as to the likelihood of such loss or damage and regardless of the form of action.

Section 10.04. Trustee not Responsible for Recitals, etc. The recitals of fact contained herein and in the Bonds (other than the Trustee’s authentication certificate) shall be taken as the statements of the Company, and the Trustee assumes no responsibility for the correctness of the same. The Trustee makes no representations as to the value of the Trust Estate or any part thereof, or as to the title of the Company thereto, or as to the validity or adequacy of the security afforded thereby and hereby, or as to the validity of this Indenture or of the Bonds issued hereunder.

Section 10.05. Trustee not Personally Liable in Case of Entry. Subject to the provisions of Sections 10.02 and 10.03, the Trustee shall not be personally liable in case of entry by it upon the Trust Estate for debts contracted or liability or damage incurred in the management or operation thereof.

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Section 10.06. Trustee may Rely on Certificates, Opinions, etc., and Consult with Counsel. To the extent permitted by Sections 10.02 and 10.03 the Trustee may rely and shall be protected in acting upon any resolution, certificate, opinion, notice, request, consent, direction, order, appraisal, report, bond or other paper or document believed by the, or either of them, to be genuine and to have been signed or presented by the proper party or parties.

Section 10.07. Trustee not Responsible for Approval of Experts, etc.

(a) The Trustee shall not be under any responsibility for the approval of any engineer, Accountant, appraiser or other Expert for any of the purposes expressed in this Indenture.

(b) Nothing contained in this Section shall be deemed to modify the obligation of the Trustee to exercise after an Event of Default (which has not been cured) the rights and powers vested in it by this Indenture with the degree of care and skill specified in Section 10.02.

Section 10.08. Trustee may Own and Deal in Bonds, etc. The Trustee in its individual or any other capacity may become the owner or pledgee of Bonds secured hereby, and, subject to the applicable provisions of the Trust Indenture Act, may otherwise deal with the Company with the same rights it would have if not the Trustee.

Section 10.09. Notice by Trustee to Bondholders of Defaults by Company.

(a) The Trustee shall, within 90 days after the occurrence thereof, give to the Bondholders, in the manner and to the extent provided in Section 1.07 and, if applicable the Trust Indenture Act, notice of all defaults known to the Trustee, unless such defaults shall have been cured before the giving of such notice (the term “default” for the purpose of this Section being herein defined to be any of the Events of Default specified in Clauses (a) to (h), inclusive, of Section 9.01, not including any period of grace provided for in said Clauses and irrespective of the giving of the notice provided for in Clauses (d) and (g) of said Section) but in the case of any default of the character specified in Clause (d) of Section 9.01 no such notice shall be given until at least 60 days after the occurrence thereof; provided, however, that except in the case of default in the payment of the principal of or interest on any of the Bonds, or in the payment of any sinking, improvement or purchase fund installment, the Trustee shall be protected in withholding such notice if and so long as its board of directors, the executive committee or a trust committee of directors and/or Responsible Officers of the Trustee in good faith determine that the withholding of such notice is in the interests of the Bondholders.

(b) Any Co-Trustee shall promptly give to the Trustee notice in writing of all defaults known to the Co-Trustee.

(c) Nothing herein contained shall require the Trustee to give any notice of any default which shall have been cured.

Section 10.10. Compensation of Trustee for Services and Expenses; Indemnification; Right of Trustee to File Claim for Compensation.

(a) The Company covenants and agrees to pay to the Trustee from time to time, and the Trustee shall be entitled to, reasonable compensation for all services rendered by it in the execution of the trusts hereby created and in the exercise and performance of any of the powers and duties hereunder of the Trustee, which compensation shall not be limited by any provision of

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law in regard to the compensation of a trustee of an express trust, and the Company will reimburse the Trustee with interest at the then current legal rate for all advances made by the Trustee in accordance with any of the provisions of this Indenture and will pay to the Trustee from time to time its expenses and disbursements (including all costs, charges and expenses of every kind incidental to any action at law or proceedings in equity to enforce the provisions of this Indenture or to foreclose the same, including attorneys and counsel fees, if placed in the hands of attorneys and counsel for collection, and further including the reasonable compensation and the expenses and disbursements of all Persons not regularly in its employ). The Company also covenants to indemnify the Trustee for, and to hold it harmless against, any loss, liability or expense incurred without negligence or bad faith on the part of the Trustee, arising out of or in connection with the acceptance or administration of his trust, including the costs and expenses of defending against any claim of liability in the premises. The obligations of the Company to the Trustee under this Section shall be secured by a Lien prior to that of the Bonds upon the Trust Estate, including all property or funds held or collected by the Trustee, as such, except funds held in trust for the benefit of the Holders of particular Bonds.

(b) The Trustee may file from time to time in any foreclosure, receivership, bankruptcy, insolvency, liquidation, reorganization, readjustment or other proceeding involving the Company, or any other obligor on the Bonds, its creditors or its property, one or more claims as a creditor for its reasonable compensation, expenses, liabilities and advances (including the reasonable compensation and expenses of its counsel and of all Persons not regularly in its employ) made or incurred by it in the execution of the trusts created by this Indenture and in the exercise and performance of any of the powers and duties of the Trustee under this Indenture and for which the Company is liable under the provisions of this Indenture. Each Holder of any Bond shall be deemed to have agreed that to the extent that an allowance out of the estate in any such proceeding with respect to such reasonable compensation, expenses, liabilities and advances may be denied to the Trustee or to its counsel or other agents for any reason, the court may nevertheless allow such claim in any such proceeding, and for the purposes of any plan of reorganization, readjustment, arrangement or composition or other like plan, may classify the Trustee as a secured creditor having priority over the class in which the Holders of the Bonds are placed, and that the Trustee, also, for the purposes of such claim, in priority to the Holders of the Bonds,

(i) shall be entitled to receive and collect such claim out of all distributions of securities, dividends, cash or other disbursements which would otherwise be made to the Holders of the Bonds in any such proceeding, and

(ii) shall have a Lien upon all securities, cash and other considerations to which the Holders of the Bonds may become entitled pursuant to any such plan in any such proceeding;

and the court may determine the method and conditions under which any such distributions may be made and Lien enforced.

Section 10.11. Certificate of Officers as Evidence of Facts. Whenever in the administration of the trusts of this Indenture, prior to the occurrence of an Event of Default hereunder and after the curing of all Events of Default which may have occurred, the Trustee

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shall deem it necessary or desirable that a matter be proved or established prior to taking or suffering any action hereunder, such matter (unless other evidence in respect thereof be herein specifically prescribed) may, in the absence of bad faith on the part of the Trustee, be deemed to be conclusively proved and established by an Officers’ Certificate, and such certificate shall be full warrant to the Trustee for any action taken or suffered by it, under the provisions of this Indenture upon the faith thereof.

Section 10.12. Trustee May Give Notices, etc. Whenever it is provided in this Indenture that the Trustee shall take any action upon the happening of a specified event or upon the fulfillment of any condition or upon the request of the Company or of Bondholders, the Trustee shall have full power to give any and all notices and to do any and all acts and things incidental to such action.

Section 10.13. Resignation of Trustee. The Trustee may at any time resign and be discharged of the trusts hereby created by giving written notice to the Company and the Bondholders, specifying the day upon which such resignation shall take effect. Such resignation shall take effect upon the day specified in such notice unless previously a successor trustee shall have been appointed by the Bondholders or the Company in the manner hereinafter provided in Section 10.15, and in such event such resignation shall take effect immediately on the appointment of such successor trustee.

Section 10.14. Removal of Trustee.

(a) The Trustee may be removed at any time by the Holders of a majority in principal amount of the Bonds then Outstanding or by their attorneys-in-fact duly authorized, notification thereof being given to the Company and to the Trustee.

(b) In case at any time the Trustee shall cease to be eligible in accordance with the provisions of Section 10.01, then the Trustee shall resign immediately in the manner and with the effect specified in Section 10.13, and, in the event that the Trustee does not resign immediately in such case, then it may be removed forthwith (i) by the Company evidenced by an Officer’s Certificate and filed with the Trustee or (ii) by the Acts of the Holders of a majority in principal amount of the Bonds then Outstanding or by their attorneys-in-fact duly authorized, notification thereof being given to the Company and to the Trustee.

Section 10.15. Appointment of Successor Trustee.

(a) In case at any time the Trustee shall resign or shall be removed or shall become incapable of acting, or shall be adjudged a bankrupt or insolvent, or if a receiver of the Trustee or of its property shall be appointed, or if any public officer shall take charge or control of the Trustee or of its property or affairs for the purpose of rehabilitation, conservation or liquidation, a vacancy shall be deemed to exist in the office of trustee, and a successor may be appointed by the Holders of a majority in principal amount of the Bonds then Outstanding, or by their attorneys-in-fact duly authorized, notification thereof being given to the Company and the retiring trustee as well as the new trustee; provided, nevertheless, that until a new trustee shall be appointed by the Bondholders as

aforesaid, the Company, by an Officer’s Certificate, may appoint a trustee to fill such vacancy until a new trustee shall be appointed by the Bondholders as

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herein authorized. The Company shall give notice to the Bondholders of any such appointment made by it in the manner provided in Section 1.08 hereof. Any new trustee appointed by the Company shall, immediately and without further act, be superseded by a trustee appointed by the Bondholders as above provided, if such appointment by the Bondholders be made prior to the expiration of one year after the mailing of the notice to the Bondholders of the appointment of the new trustee by the Company.

(b) If in a proper case no appointment of a successor trustee shall be made pursuant to the foregoing provisions of this Section within six months after a vacancy shall have occurred in the office of trustee, the Holder of any Bond Outstanding hereunder or any retiring trustee may apply to any court of competent jurisdiction to appoint a successor trustee. Said court may thereupon after such notice, if any, as such court may deem proper and prescribe, appoint a successor trustee.

(c) Any trustee appointed under the provisions of this Section in succession to the Trustee shall be eligible under Section 10.01 hereof, and, when applicable, qualified under the Trust Indenture Act.

(d) Any trustee which has resigned or been removed shall nevertheless retain the Lien upon the Trust Estate, including all property or funds held or collected by the trustee as such, except funds held in trust for the benefit of the particular Bonds, to secure the amounts due to the trustee as compensation, reimbursement, expenses and indemnity, afforded to it by Section 10.10 and shall retain the further rights afforded to it by said Section.

Section 10.16. Co-Trustee and Separate Trustees.

(a) At any time or times, for the purpose of meeting the legal requirements of any applicable jurisdiction, the Company and the Trustee shall have power to appoint, and, upon the written request of the Trustee or of the Holders of at least 33% in principal amount of the Bonds then Outstanding, the Company shall for such purpose join with the Trustee in the execution and delivery of all instruments and agreements necessary or proper to appoint, one or more Persons approved by the Trustee either to act as co-trustee (a “Co-Trustee”), jointly with the Trustee, or to act as separate trustee, in either case with such powers as may be provided in the instrument of appointment, and to vest in such Person or Persons, in the capacity aforesaid, any property, title, right or power deemed necessary or desirable, subject to the other provisions of this Section. If the Company does not join in such appointment within fifteen days after the receipt by it of a request so to do, or if an Event of Default shall have occurred and be continuing, the Trustee alone shall have power to make such appointment.

(b) Should any written instrument or instruments from the Company be required by any Co-Trustee or separate trustee to more fully confirm to such Co-Trustee or separate trustee such property, title, right or power, any and all such instruments shall, on request, be executed, acknowledged and delivered by the Company.

(c) Every Co-Trustee or separate trustee shall, to the extent permitted by law, but to such extent only, be appointed subject to the following conditions:

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(i) the Bonds shall be authenticated and delivered, and all rights, powers, duties and obligations hereunder in respect of the custody of securities, cash and other personal property held by, or required to be deposited or pledged with, the Trustee hereunder, shall be exercised solely by the Trustee;

(ii) the rights, powers, duties, obligations and indemnities hereby conferred or imposed upon the Trustee in respect of any property covered by such appointment shall be conferred or imposed upon and exercised or performed either by the Trustee or by the Trustee and such Co-Trustee or separate trustee jointly, as shall be provided in the instrument appointing such Co-Trustee or separate trustee, except to the extent that under any law of any jurisdiction in which any particular act is to be performed, the Trustee shall be incompetent or unqualified to perform such act, in which event such rights, powers, duties and obligations shall be exercised and performed by such Co-Trustee or separate trustee; and

(iii) any Act of Holders delivered to the Trustee shall be deemed to have been delivered to each such Co-Trustee and separate trustee.

Section 10.17. Resignation or Removal of Co-Trustee or Separate Trustee; Appointment of Successor Co-Trustee.

(a) The Company and the Trustee, at any time by an instrument in writing executed by them jointly, may, and upon the demand of any Co-Trustee or separate trustee appointed pursuant to Section 10.16 shall, accept the resignation of or remove such Co-Trustee or separate trustee, and, upon the request of the Trustee, the Company shall for such purpose join with the Trustee in the execution, delivery and performance of all instruments and agreements necessary or proper to make effective such resignation or removal. In the event that the Company shall not have joined in such action within fifteen (15) days after the receipt by it of a request so to do, or if an Event of Default shall have occurred and be continuing, the Trustee alone shall have power to accept such resignation or to remove such Co-Trustee.

(b) In case at any time a Co-Trustee or separate trustee shall resign or shall be removed or shall become incapable of acting, or shall be adjudged a bankrupt or insolvent, or if a receiver of a Co-Trustee or separate trustee or of its property shall be appointed, or if any public officer shall take charge or control of a Co-Trustee or separate trustee or of its property or affairs for the purpose of rehabilitation, conservation or liquidation, the Company and the Trustee may appoint another Person as successor Co-Trustee or separate trustee, and, upon the request of the Trustee, the Company shall for such purpose join with the Trustee in the execution, delivery and performance of all instruments and agreements necessary or proper to appoint such successor. In the event that the Company shall not have joined in such appointment within fifteen (15) days after the receipt by it of a request so to do, or if an Event of Default shall have occurred and be continuing, the Trustee alone shall have power to make such appointment.

Section 10.18. Rights of Co-Trustee Revest in Trustee. In case any Co-Trustee shall resign or be removed, or shall become incapable of acting or shall be adjudged a bankrupt or insolvent, or a receiver shall be appointed or any public officer take charge or control as mentioned in Section 10.17 all the estates, property, rights, powers, trusts, duties and obligations of the Co-Trustee, so far as permitted by law, shall vest in and be exercised by the Trustee without the appointment of a new trustee or a successor to the Co-Trustee.

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Section 10.19. Trustee not Liable for Acts of any other Trustee. No trustee hereunder shall be personally liable by reason of any act or omission of any other trustee hereunder.

Section 10.20. Execution of Supplemental Indenture by Successor Trustee; Further Acts of Assurance and Confirmation. Any successor trustee appointed hereunder shall execute, acknowledge and deliver to his or its predecessor trustee, and also to the Company, an instrument accepting such appointment hereunder, and thereupon such successor trustee, without any further act, deed or conveyance, shall become fully vested with all the estates, properties, rights, powers, trusts, duties and obligations of his or its predecessor in trust hereunder, with like effect as if originally named as trustee herein; but the trustee ceasing to act shall nevertheless, on the written request of the Company, or of the successor trustee, or of the Holders of ten per centum (10%) in principal amount of the Bonds then Outstanding hereunder, execute and, upon receipt by it of all amounts owing to it hereunder, acknowledge and deliver such instruments of conveyance and further assurance and do such other things as may reasonably be required for more fully and certainly vesting and confirming in such successor trustee all the right, title and interest of the trustee to which he or it succeeds, in and to the Trust Estate and such rights, powers, trusts, duties and obligations, and the trustee ceasing to act shall also, upon like request and payment, pay over, assign and deliver to the successor trustee any money or other property subject to the Lien of this Indenture, including any pledged securities which may then be in his or its possession. Should any deed, conveyance or instrument in writing from the Company be required by the new trustee for more fully and certainly vesting in and confirming to such new trustee such estates, properties, rights, powers, trusts and duties, any and all such deeds, conveyances and instruments in writing shall, on request, be executed, acknowledged and delivered by the Company.

Section 10.21. Merger Resulting in Successor Trustee; Use of Bonds Already Authenticated. Any Corporation into which the Trustee or any Co-Trustee may be merged or with which either of them may be consolidated or any Corporation resulting from any merger or consolidation to which the Trustee or any Co-Trustee shall be a party or any Corporation to which substantially all the corporate trust business of the Trustee or such Co-Trustee may be transferred, provided such Corporation shall be eligible under the provisions of Section 10.01, and, where required, qualified under the Trust Indenture Act, shall be the successor Trustee or Co-Trustee, as the case may be, under this Indenture, without the execution or filing of any paper or the performance of any further act on the part of any other parties hereto, anything herein to the contrary notwithstanding. In case any of the Bonds contemplated to be issued hereunder shall have been authenticated but not delivered, any such successor to the Trustee may, subject to the same terms and conditions as though such successor had itself authenticated such Bonds, adopt the certificate of authentication of the original Trustee or of any successor to it as trustee hereunder, and deliver the said Bonds so authenticated; and in case any of said Bonds shall not have been authenticated, any successor to the Trustee may authenticate such Bonds either in the name of any predecessor trustee hereunder or in the name of the successor trustee and in all such cases such certificates shall have the full force which it is anywhere in said Bonds or in this Indenture provided that the certificate of the Trustee shall have; provided, however, that the right to authenticate Bonds in the name of the Trustee shall apply only to its successor or successors by merger or consolidation or sale as aforesaid.

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ARTICLE ELEVEN

Holders’ Lists and Reports by the Trustee and Company

Section 11.01. Lists of Holders. Semiannually, not later than February 28 and August 28 in each year, commencing August 28, 1947, and at such other times as the Trustee may request in writing, the Company shall furnish or cause to be furnished to the Trustee information as to the names and addresses of the Holders, and the Trustee shall preserve such information and similar information received by it in any other capacity and afford to the Holders access to information so preserved by it, all to such extent, if any, and in such manner as shall be required by the Trust Indenture Act; provided, however, that no such list need be furnished so long as the Trustee shall be the Security Registrar.

Section 11.02. Reports by Trustee and Company.

(a) To the extent the Indenture is qualified under and subject to the Trust Indenture Act, not later than July 15 in each year, commencing with the year 1947, the Trustee shall transmit to the Holders, the Commission, if required by law, and each securities exchange upon which the Bonds are listed, a report, dated as of the next preceding May 15, with respect to any events and other matters described in Section 313(a) of the Trust Indenture Act, in such manner and to the extent required by the Trust Indenture Act. The Trustee shall transmit to the Holders, the Commission, if required, and each securities exchange upon which any Bonds are listed, and the Company shall file with the Trustee (within 30 days after filing with the Commission in the case of reports which pursuant to the Trust Indenture Act must be filed with the Commission and furnished to the Trustee, if any) and transmit to the Holders, such other information, reports and other documents, if any, at such times and in such manner, as shall be required by the Trust Indenture Act if the Company is then subject thereto. The Company shall notify the Trustee of the listing of any Bonds on any securities exchange.

(b) Delivery of such reports, information and documents to the Trustee is for informational purposes only, and the Trustee’s receipt of such shall not constitute notice or constructive notice of any information contained therein or determinable from information contained therein, including the Company’s compliance with any of its covenants hereunder (as to which the Trustee is entitled to rely exclusively on Officers’ Certificates).

(c) The Company shall file with the Trustee (within 30 days after filing with the Commission in the case of reports that pursuant to the Trust Indenture Act must be filed with the Commission and furnished to the Trustee) and transmit to the Holders, such other information, reports and other documents, if any, at such times and in such manner, as shall be required by the Trust Indenture Act if the Company is then subject thereto.

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ARTICLE TWELVE

Consolidation, Merger, Conveyance and Other Transfer

Section 12.01. Merger, Consolidation, etc., Permitted; Assumption of Bonds and this Indenture by Successor. Nothing in this Indenture or any of the Bonds contained shall prevent any merger or consolidation of the Company (either singly or with one or more other Corporations) into or with, or any sale, conveyance transfer or lease, subject to the Lien of this Indenture, of all the Trust Estate as, or substantially as, any entirety to, any Corporation lawfully entitled to acquire or lease and operate the same; provided, however, and the Company covenants and agrees (1) that such consolidation, merger, sale, conveyance, transfer or lease shall be on such terms which in no respect impair the Lien and security of this Indenture or any of the rights or powers of the Trustee or of the Bondholders hereunder; (2) that any such lease shall contain a provision that, if any Event of Default shall exist when such lease is made, or shall occur while it is in effect, such lease may be terminated at any time while such default exists, by the Trustee or by the purchaser of the property so leased at any sale hereunder, whether under the power of sale hereby conferred or under judicial proceedings; (3) that if the property of the Corporation with which the Company is to be merged or consolidated, or to which it is to sell or convey the Trust Estate, is subject to a Lien or Liens which after such consolidation, merger, sale or conveyance would be prior to the Lien of this Indenture upon such property, such Lien shall be deemed to be a Prior Lien within the meaning hereof, and such consolidation, merger, sale or conveyance shall be deemed to be an acquisition of property subject to a Prior Lien; and (4) that in case the Company shall be merged or consolidated as aforesaid (either singly or with one or more other Corporations) into or with any other Corporation, or shall sell, convey or transfer as aforesaid to another Corporation all the Trust Estate as, or substantially as, an entirety (but not in case of any lease) the Corporation resulting from such merger or consolidation or into or with which the Company shall have been merged or consolidated or which shall have received a conveyance or transfer as aforesaid (such Corporation being sometimes herein called the “Successor Company”) shall, (i) be a Corporation, organized and existing under the laws of (A) the United States of America, any state or territory thereof, or the District of Columbia, or (B) a foreign jurisdiction and which consents to the jurisdiction of the courts of the United States, or of any state thereof or the District of Columbia, and (ii) prior to or contemporaneously with such merger, consolidation, conveyance or transfer, execute, and promptly cause to be recorded, a Supplemental Indenture to and with the Trustee, reasonably satisfactory to the Trustee, whereby the Successor Company shall assume and agree to pay duly and punctually the principal of and interest on the Bonds issued hereunder in accordance with the provisions of said Bonds and this Indenture, and shall agree to perform and fulfill all the terms, covenants and conditions of this Indenture binding the Company.

Section 12.02. Substitution of Successor for Company. Upon the execution by any Successor Company of the Supplemental Indenture provided for in Section 12.01, such Successor Company shall thereupon succeed to the Company with the same effect as if it had been named herein as the mortgagor company and in the Bonds as the obligor thereon or maker thereof, and such Supplemental Indenture shall be construed as and shall constitute a novation releasing the Company, unless its identity is merged into or consolidated with that of the Successor Company, from all liabilities upon or with respect to any of the covenants or agreements in this Indenture contained, but not, however, from its liabilities on the Bonds. Upon

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the execution of such Supplemental Indenture, the Successor Company may thereupon use any Bonds theretofore executed by the Company or any intermediate Successor Company and may cause to be signed, issued and delivered either in its own name or in the name of Tampa Electric Company or in the name of any intermediate Successor Company any or all such Bonds which shall not theretofore have been signed by the Company or any intermediate Successor Company and authenticated by the Trustee; and upon the application of the Successor Company in lieu of the Company, and subject to all the terms, conditions and restrictions in this Indenture prescribed with respect to the authentication and delivery of Bonds, the Trustee shall authenticate and deliver any of such Bonds which shall have been previously signed and delivered by the officers of the Company or any intermediate Successor Company to the Trustee for authentication, and any of such Bonds which the Successor Company shall thereafter, in accordance with the provisions of this Indenture, cause to be signed by its appropriate officers and delivered to the Trustee for such purpose. All the Bonds so issued shall in all respects have the same legal rank and security as the Bonds theretofore or thereafter issued in accordance with the terms of this Indenture as though all of said Bonds had been issued at the date of the execution hereof.

Section 12.03. Rights of Successor in Respect of Property Owned by Company. In respect of property owned by the Company at the time of any consolidation, merger, sale, conveyance or transfer as provided in Section 12.01, and substitutions, replacements, additions, betterments, developments, extensions and enlargements thereto subsequently made, constructed or acquired, the rights and duties of the Successor Company hereunder shall be the same as the rights and duties of the Company would have been had such consolidation, merger, sale, conveyance or transfer not taken place.

Section 12.04. Rights of Successor in Respect of Property Owned by it or Merging or Consolidating Corporations. In respect of property at the time of such consolidation, merger, sale, conveyance or transfer owned by the Successor Company, and/or owned by any other Corporation or Corporations merged or consolidated into or with, or the property of other Corporations which is conveyed or transferred to, such Successor Company, and/or of property thereafter acquired by the Successor Company, except said substitutions, replacements, additions, betterments, developments, extensions and enlargements to, of or upon the property owned by the Company referred to in Section 12.03, this Indenture or the Supplemental Indenture to be recorded as above provided in Section 12.01 shall not become or be a Lien upon any of such property except so much thereof as shall be subjected to the Lien of this Indenture by Supplemental Indenture, duly executed, subject, however, to the provisions of Section 12.01. Such Supplemental Indenture may, but need not necessarily, form one and the same instrument with the Supplemental Indenture provided for in said Section 12.01. Nothing herein shall be construed to prevent such Supplemental Indenture, at the option of the Company or the Successor Company, from subjecting to the Lien of this Indenture all or any part of the property of such Successor Company then owned or thereafter acquired.

Section 12.05. Rights of Company with Respect to Property Acquired on Merger or Consolidation. In case any other Corporation or Corporations shall be merged or consolidated into or with the Company under such circumstances that the corporate identity of the Company is not changed, the rights and duties of the Company, with respect to the property owned by such other Corporation or Corporations at the time of such merger or consolidation which is acquired by the Company by virtue of the merger or consolidation and charged to its fixed property accounts, shall be the same as if such property had been acquired by the Company by purchase and charged to its fixed property accounts as of the date of such merger or consolidation.

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Section 12.06. Exchangeability of Bonds for Bonds in New Name. The Company covenants that if Bonds at any time be issued in any new name the Company will provide for the stamping or for the exchange of any Bonds previously issued for Bonds of the same tenor and amounts issued in any such new name, at the option of the Holders and without expense to them, and the Trustee shall also do such acts as may be necessary on its part to that end, including authentication of the Bonds so to be issued in exchange.

Section 12.07. Opinion of Counsel as to Consolidation, Merger, Sale, Conveyance, Transfer or Lease. In case of any such consolidation, merger, sale, conveyance, transfer or lease the Trustee shall be furnished with an Officers’ Certificate and an Opinion of Counsel that the applicable provisions of Sections 12.01 to 12.04, inclusive, or any of them, have been complied with and that any Supplemental Indenture made under any of said Sections of this Article Twelve complies with the conditions and provisions thereof.

Section 12.08. Surrender of Powers under Article Twelve. At any time prior to the exercise of any power by this Article Twelve reserved to the Company or to a Successor Company, the Company or such Successor Company may surrender any such reserved power by delivering to the Trustee an Officers’ Certificate stating that the execution of such instrument was duly authorized by all required corporate action; and thereupon the power so surrendered shall cease. Until so surrendered, the provisions of this Article Twelve shall continue to apply to any number of successive mergers, consolidations, sales, conveyances or transfers, the term “the Company” referring in each such case to the Corporation which immediately before such merger, consolidation, sale, conveyance or transfer was the owner of the Trust Estate.

ARTICLE THIRTEEN

Supplemental Indentures

Section 13.01. Supplemental Indentures.

(a) The Company and the Trustee, from time to time and at any time, subject to the restrictions in this Indenture contained, may, and when so required by this Indenture, shall, enter into such indentures supplemental hereto as may or shall by them be deemed necessary or desirable, which shall thereafter form a part hereof, for one or more of the following purposes:

(i) to mortgage, pledge, convey, transfer or assign to the Trustee, and to subject to the Lien of this Indenture, with the same force and effect as though included in the Granting Clauses hereof, additional properties hereafter acquired by the Company, whether through consolidation or merger or by purchase or otherwise, and to correct or amplify the description of any properties at any time subject to the Lien of this Indenture;

(ii) to add to the conditions, limitations and restrictions on the authorized amount, terms, provisions, purposes of issue, authentication and delivery of Bonds or of any series of Bonds, as herein set forth, other conditions, limitations and restrictions thereafter to be observed;

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(iii) to add to the covenants and agreements of the Company in this Indenture contained, other covenants and agreements thereafter to be observed by the Company although the freedom of action of the Company may be materially restricted thereby, or to add to the Events of Defaults specified in Section 9.01 other Events of Defaults or to surrender any right or power herein reserved to or conferred upon the Company;

(iv) to provide for the creation of any series of Bonds, designating the series to be created and specifying the form and provisions of the Bonds of such series as hereinbefore provided or permitted;

(v) to provide a sinking, amortization, improvement, replacement or other analogous fund for the benefit of all or any of the Bonds of any one or more series, of such character and of such amount and upon such terms and conditions as shall be contained in such Supplemental Indenture;

(vi) to provide the terms and conditions of the exchange of Bonds of one series for Bonds of another or other series, or of the exchange of Bonds of one denomination or kind of Bonds of another denomination or kind, of the same series;

(vii) to provide that the principal of the Bonds of any series may be converted at the option of the Holders into capital stock, bonds and/or other securities, and the terms and conditions of such conversion;

(viii) to change, alter, modify, vary or eliminate any of the terms, provisions, restrictions or conditions of this Indenture; provided, however, that any such changes, alterations, modifications, variations or eliminations made in a Supplemental Indenture pursuant to this Clause which would adversely affect or diminish the rights of the Holders of any Bonds then Outstanding against the Company or its property shall be expressly stated in such Supplemental Indenture to become effective only when there are no Bonds Outstanding of any series authenticated and delivered prior to the execution of such Supplemental Indenture; provided, further, that such Supplemental Indenture shall be specifically referred to in the text of all Bonds of any series authenticated and delivered after the execution of such Supplemental Indenture; provided, further that the Trustee may, in its uncontrolled discretion, decline to enter into any such Supplemental Indenture which, in its opinion, may not afford adequate protection to the Trustee when the same shall become operative;

(ix) to evidence the succession of another Corporation to the Company, or successive successions, and the assumption by a Successor Company of the covenants and obligations of the Company in the Bonds and in this Indenture contained or subject to the Lien of this Indenture any properties owned by it; and

(x) to make such provisions for the purpose of curing any ambiguity, or of curing, correcting or supplementing any defective provision contained in this Indenture, or in regard to matters or questions arising under this Indenture, as the Company may deem necessary or desirable and not inconsistent with this Indenture and which shall not adversely affect the interests of the Holders of the Bonds.

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(b) Any Supplemental Indenture authorized by the provisions of this Section may be executed by the Company and the Trustee without the consent of the Holders of any of the Bonds at the time Outstanding, notwithstanding any of the provisions of Section 13.02.

Section 13.02. Modification of Indenture with Consent of Bondholders.

(a) With the consent of the Holders of not less than 75% in principal amount of the Bonds at the time Outstanding or their attorneys-in-fact duly authorized, including the consent of the Holders of not less than 60% in principal amount of the Bonds at the time Outstanding of each series the rights of the Holders of which are affected, the Company and the Trustee may from time to time and at any time enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Indenture or of any Supplemental Indenture or modifying the rights and obligations of the Company and the rights of the Holders of any of the Bonds; provided, however, that no such Supplemental Indenture shall (1) extend the Maturity of any of the Bonds or reduce the rate or extend the time of payment of interest thereon, or reduce the amount of the principal thereof, or reduce any premium payable on the redemption thereof, without the consent of the Holder of each Bond so affected, or (2) permit the creation of any Lien, not otherwise permitted, prior to or on a parity with the Lien of this Indenture, without the consent of the Holders of all Bonds then Outstanding, or (3) reduce the aforesaid percentage of Holders of Bonds required to approve any such Supplemental Indenture, without the consent of the Holders of all the Bonds then Outstanding. For the purposes of this Section, Bonds shall be deemed to be affected by a Supplemental Indenture if such Supplemental Indenture adversely affects or diminishes the rights of Holders thereof against the Company or against its property. The Trustee may in its discretion determine whether or not, in accordance with the foregoing, Bonds of any particular series would be affected by any Supplemental Indenture and any such determination shall be conclusive upon the Holders of Bonds of such series and all other series. Subject to the provisions of Sections 10.02 and 10.03, the Trustee shall not be liable for any determination made in good faith in connection herewith.

(b) Upon a Company Request, accompanied by a Board Resolution authorizing the execution of any such Supplemental Indenture, and upon the filing with the Trustee of evidence of the consent of Bondholders as aforesaid, the Trustee shall join with the Company in the execution of such Supplemental Indenture unless such Supplemental Indenture affects the Trustee’s own rights, duties or immunities under this Indenture or otherwise, in which case the Trustee may in its discretion but shall not be obligated to enter into such Supplemental Indenture.

(c) It shall not be necessary for the consent of the Bondholders under this Section to approve the particular form of any proposed Supplemental Indenture, but it shall be sufficient if such consent shall approve the substance thereof.

(d) Promptly after the execution by the Company and the Trustee of any Supplemental Indenture pursuant to the provisions of this Section, the Company shall send a notice to the Bondholders, setting forth in general terms the substance of such Supplemental Indenture, in the manner provided in Section 1.08. Any failure of the Company to give such notice, or any defect therein, shall not, however, in any way impair or affect the validity of any such Supplemental Indenture.

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Section 13.03. Effect of Supplemental Indentures. Upon the execution of any Supplemental Indenture pursuant to the provisions of this Article, this Indenture shall be and be deemed to be modified and amended in accordance therewith and the respective rights, duties and obligations under this Indenture of the Company, the Trustee and all Holders of Bonds Outstanding thereunder shall thereafter be determined, exercised and enforced hereunder subject in all respects to such modifications and amendments, and all the terms and conditions of any such Supplemental Indenture shall be and be deemed to be part of the terms and conditions of this Indenture for any and all purposes.

Section 13.04. Opinion of Counsel as Evidence of Compliance with this Article. Subject to the provisions of Sections 10.02 and 10.03, the Trustee may receive an Opinion of Counsel as conclusive evidence that any Supplemental Indenture executed pursuant to the provisions of this Article complies with the requirements of this Article.

Section 13.05. Notation on Bonds; Provision for New Bonds. Bonds authenticated and delivered after the execution of any Supplemental Indenture pursuant to the provisions of this Article may bear a notation in form approved by the Trustee as to any matter provided for in such Supplemental Indenture. If such Supplemental Indenture shall so provide, new Bonds, so modified as to conform, in the opinion of the Trustee and the Company, to any modification of this Indenture contained in any such Supplemental Indenture, may be prepared by the Company, authenticated by the Trustee and delivered without cost to the Holders of Bonds then Outstanding, upon surrender of such Bonds in equal aggregate principal amounts.

ARTICLE FOURTEEN

Limitation of Liability

Section 14.01. Limitations of Liability. No recourse under or upon any obligation, covenant or agreement contained in this Indenture or in any Bond issued hereunder or under or upon any indebtedness hereby secured or arising out of this Indenture, shall be had against any incorporator, stockholder, officer or director, as such, past, present or future, of the Company or of any predecessor Corporation or Successor Company, either directly or through the Company or any such predecessor Corporation or Successor Company, whether by virtue of any constitution, statute or rule of law or by the enforcement of any assessment or penalty or by any legal or equitable proceeding or otherwise howsoever. It is expressly agreed and understood that this Indenture and the Bonds are solely corporate obligations and that no personal liability whatever does or shall attach to or be incurred by the incorporators, stockholders, officers or directors, as such, of the Company or of any predecessor Corporation or Successor Company, or any of them, because of the indebtedness represented by the Bonds, or under or by reason of any of the obligations, covenants or agreements contained in this Indenture or in any of the Bonds, or implied therefrom; and that any and all such personal liability of every name and nature, either at common law or in equity or by statute or constitution, of every such incorporator, stockholder, officer or director, as such, is hereby expressly waived and released as a condition of, and as part of the consideration for, the execution of this Indenture and the issuance of the Bonds.

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ARTICLE FIFTEEN

Execution

Section 15.01. Date. Although this Twentieth Supplemental Indenture is dated for convenience and for the purpose of reference as of December 1, 2013, the actual date or dates of execution by the Company and by the Trustee are as indicated by their respective acknowledgments hereto annexed.

Section 15.02. Counterparts. In order to facilitate the recording or filing of this Twentieth Supplemental Indenture, the same may be simultaneously executed in several counterparts and each shall be deemed to be an original and such counterparts shall together constitute but one and the same instrument.

[signature pages follow]

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IN WITNESS WHEREOF, Tampa Electric Company has caused this Twentieth Supplemental Indenture to be signed in its corporate name and behalf by its President or one of its Vice Presidents and its corporate seal to be hereunto affixed and attested by its Secretary or one of its Assistant Secretaries; and said U.S. Bank National Association in token of its acceptance of the trust hereby created has caused this Twentieth Supplemental Indenture to be signed in its corporate name and behalf by its President, one of its Vice Presidents or one of its Assistant Vice Presidents; all as of the day and year first above written.

TAMPA ELECTRIC COMPANY
By	/s/ Sandra W. Callahan
Name:	Sandra W. Callahan
Title:	Vice President – Finance and Accounting and Chief Financial Officer

(SEAL)

Attest:

/s/ David E. Schwartz

Name: David E. Schwartz

Title: Secretary

Signed, sealed and delivered on behalf of TAMPA

ELECTRIC COMPANY, in the presence of

/s/ Michelle Szekeres

Print Name: Michelle Szekeres

/s/ Heather Douglas

Print Name: Heather Douglas

U.S. BANK NATIONAL ASSOCIATION
By	/s/ Eric J. Donaghey
Name:	Eric J. Donaghey
Title:	Vice President

(U.S. BANK NATIONAL ASSOCIATION HAS NO SEAL)

Signed and delivered on behalf of

U.S. BANK NATIONAL ASSOCIATION in the presence of

/s/ Jessica Perez

Print Name: Jessica Perez

/s/ John G. Correla

Print Name: John G. Corella

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STATE OF FLORIDA

COUNTY OF HILLSBOROUGH, SS.:

Before the undersigned, a Notary Public in and for said State and County, duly qualified, commissioned and sworn, personally came Sandra W. Callahan and David E. Schwartz, each to me well known to be the identical persons described in and who executed and attested, respectively, the foregoing instrument and to be a Vice President and Secretary respectively of TAMPA ELECTRIC COMPANY, the corporation described in and which executed said instrument; and the said Sandra W. Callahan acknowledged and declared that she as a Vice President of said corporation and being duly authorized by it, freely and voluntarily signed its name and caused its corporate seal to be affixed to and executed said instrument in the name of, for and on behalf of said corporation and as and for its act and deed, and did not take an oath. And the said David E. Schwartz, acknowledged and declared that he as Secretary of said corporation, being duly authorized by it, freely and voluntarily affixed the corporate seal of said corporation to said instrument and executed and attested said instrument in the name of, for and on behalf of said corporation and as and for its act and deed, and did not take an oath.

IN TESTIMONY WHEREOF, I do hereunto set my hand and official seal at the City of Tampa in said State and County, this 26th day of November, A.D. 2013.

/s/ Denise Ramseyer

Print Name: Denise Ramseyer

Notary Public

My Commission Expires: 12/07/2013

(SEAL)

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COMMONWEALTH OF MASSACHUSETTS,

COUNTY OF SUFFOLK, SS.:

Before the undersigned, a Notary Public in and for said Commonwealth and County, duly qualified, commissioned and sworn, personally came Eric Donaghey to me well known to be the identical persons described in and who executed and attested, respectively, the foregoing instrument and to be a Vice President of U.S. BANK NATIONAL ASSOCIATION, the corporation described in and which executed said instrument; and the said Eric Donaghey acknowledged and declared that he as a Vice President of said corporation and being duly authorized by it, freely and voluntarily signed its name to and executed said instrument in the name of, for and on behalf of said corporation and as and for its act and deed, and did not take an oath.

IN TESTIMONY WHEREOF, I do hereunto set my hand and official seal at the City of Boston in said Commonwealth and County, this 27th day of November, A.D. 2013.

/s/ Harry McKinley

Print Name: Harry McKinley

Notary Public

My Commission Expires: Aug. 29, 2014

(SEAL)

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SCHEDULE 1

to Twentieth Supplemental Indenture dated as of December 1, 2013

FLORIDA COUNTIES IN WHICH THE ORIGINAL INDENTURE AND SUPPLEMENTAL

INDENTURES HAVE BEEN RECORDED:

Hillsborough County

Manatee County

Pasco County

Pinellas County

Polk County

Highlands County

Hardee County

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EX-10.21

Exhibit 10.21

Compensatory Arrangements with Executive Officers

Compensation for executives at TECO Energy, Inc. (the “Corporation”) consists of several components. Included among these are base salary and an annual incentive award program.

Base salary information for the Chief Executive Officer, Chief Financial Officer and the other executive officers named in our most recently filed proxy statement who are currently serving as executive offers of the Corporation (together, the “named executive officers”) is set forth in the table below.

The Corporation’s annual incentive plan is filed as Exhibit 10.4 to the Corporation’s Annual Report on Form 10-K to which this document is an exhibit (the “Report”). The 2014 target award percentages for awards under the annual incentive plan for the named executive officers are set forth in the table below.

Compensatory arrangements relating to other aspects of the Corporation’s executive compensation program are filed as exhibits to the Report.

Named Executive Officer Salary and Target Award Percentage Information for 2014

Name	Title	Salary		Target Award %
John B. Ramil	President and Chief Executive Officer	$	785,000		100	%
Gordon L. Gillette	President of Tampa Electric Company	$	546,000		70	%
Sandra W. Callahan	Senior Vice President-Finance and Accounting and Chief Financial Officer	$	475,000		70	%
Charles A. Attal III	Senior Vice President – General Counsel and Chief Legal Officer	$	380,000		60	%

EX-10.22

Exhibit 10.22

Compensatory Arrangements with Non-Management Directors

Annual Cash Retainer	$65,000
Additional Annual Cash Retainer for Non-Executive Chairman of the Board	$150,000
Additional Annual Cash Retainer for Audit Committee Chair	$10,000
Additional Annual Cash Retainer for Other Committee Chairs	$7,500
Board and Committee Meeting Attendance Fees	No meeting attendance fees for up to five board and committee meetings attended. For meetings attended over that number, attendance fees of $750 per Board meeting (applicable to TECO Energy, Inc. and Tampa Electric Company Board meetings) and $1,500 for Committee meetings.
Restricted Stock	Annual grant of shares having a value of $80,000, which vest in one installment on the first anniversary of the date of grant
Director Matching Contributions Program	Contributions by non-management directors to eligible non-profit organizations are matched dollar-for-dollar by the Corporation, in an amount not to exceed $10,000 per calendar year for each such director.

TECO Energy, Inc. also pays for or reimburses directors for their meeting-related expenses.

EX-10.37

Exhibit 10.37

OMNIBUS AMENDMENT NO. 12

This OMNIBUS AMENDMENT NO. 12 (this “Amendment”) dated as of February 14, 2014 is by and among Tampa Electric Company, in its capacity as originator (in such capacity, the “Originator”) and as servicer (in such capacity, the Servicer”), TEC Receivables Corp., in its capacity as “Purchaser” under the Purchase Agreement (as defined below) (in such capacity, the “Purchaser”) and as “Borrower” under the Loan Agreement (as defined below) (in such capacity, the “Borrower”), Citibank, N.A., as the sole Managing Agent (in such capacity, the “Managing Agent”) and as the Program Agent (in such capacity, the “Program Agent”), and CAFCO, LLC, as the sole Conduit Lender (in such capacity, the “Conduit Lender”) and as the sole Committed Lender (in such capacity, the “Committed Lender”). Capitalized terms used herein but not specifically defined herein shall have the meanings given to such terms in the Loan Agreement (as defined below) or the Purchase Agreement (as defined below).

PRELIMINARY STATEMENTS:

(1) The Originator and the Purchaser are parties to that certain Purchase and Contribution Agreement dated as of January 6, 2005, as amended by the Omnibus Amendment dated as of June 7, 2005, Omnibus Amendment No. 3 dated as of December 22, 2006, Omnibus Amendment No. 5 dated as of September 26, 2008 and Omnibus Amendment No. 9 dated as of February 18, 2011 (the “Purchase Agreement”).

(2) The Servicer, the Borrower, the Conduit Lender, the Committed Lender, the Managing Agent and the Program Agent are parties to that certain Loan and Servicing Agreement dated as of January 6, 2005, as amended by (i) the Omnibus Amendment dated as of June 7, 2005, (ii) Amendment No. 2 dated as of January 5, 2006, (iii) Omnibus Amendment No. 3 dated as of December 22, 2006, (iv) Amendment No. 4 dated as of December 20, 2007, (v) Omnibus Amendment No. 5 dated as of September 26, 2008, (vi) Amendment No. 6 dated as of December 18, 2008, (vii) Amendment No. 7 dated as of December 16, 2009, (viii) Amendment No. 8 dated as of February 19, 2010, (ix) Omnibus Amendment No. 9 dated as of February 18, 2011, (x) Amendment No. 10 dated as of February 17, 2012 and (xi) Amendment No. 11 dated as of February 15, 2013 (the “Loan Agreement”).

(3) Citibank, N.A. has assigned all of its rights and obligations as a Committed Lender under the Loan Agreement and other Facility Documents to CAFCO, LLC.

(4) The Originator and the Purchaser wish to amend the Purchase Agreement upon the terms and subject to the conditions set forth herein.

(5) The Borrower and the Servicer wish to amend the Loan Agreement upon the terms and subject to the conditions set forth herein.

(6) The Managing Agent, the Program Agent, the Conduit Lender and the Committed Lender consent to the amendments to the Purchase Agreement and the Loan Agreement upon the terms and subject to the conditions set forth herein.

NOW, THEREFORE, the parties hereto agree as follows:

SECTION 1. Amendment to the Purchase Agreement. Effective as of the date hereof and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, Section 3.01(o) of the Purchase Agreement is hereby amended and restated in its entirety as follows:

(o) Investment Company Act. The Originator is not an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

SECTION 2. Amendments to the Loan Agreement. Effective as of the date hereof and subject to the satisfaction of the condition precedent set forth in Section 3 hereof, the Loan Agreement is hereby amended as follows:

(a) Section 1.01 of the Loan Agreement is hereby amended to delete the definitions of “Asset Purchase Agreement”, “Liquidity Provider” and “Scheduled Termination Date” and replace them with the following:

“Asset Purchase Agreement” means any asset purchase or other agreements pursuant to which a Lender may from time to time assign part or all of the Loans made by such Lender to a Liquidity Provider, as amended, restated, supplemented or otherwise modified from time to time.

“Liquidity Provider” means any of the financial institutions from time to time party to any Asset Purchase Agreement or any liquidity loan agreement or similar arrangement with a Lender.

“Scheduled Termination Date” means, (i) with respect to the Committed Lenders’ Commitments hereunder, February 13, 2015, unless such date is extended pursuant to Section 2.01(c) and (ii) with respect to the Conduit Lenders, February 13, 2015, unless such date is extended with the consent of the parties hereto.

(b) Section 4.01(q) of the Loan Agreement is hereby amended and restated in its entirety as follows:

(q) Investment Company Act. The Borrower is not an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

(c) Schedule I to the Loan Agreement is deleted in its entirety and replaced with the form attached hereto as Annex A.

SECTION 3. Condition of Effectiveness. This Amendment shall become effective as of the date hereof upon the receipt by the Program Agent of (a) this Amendment duly executed by all of the parties hereto, (b) the Fee Letter dated the date hereof duly executed by the Borrower and the Managing Agent, and (c) the Upfront Fee (as such term is defined in the Fee Letter).

2

SECTION 4. Representations and Warranties. Each of the parties hereto represents and warrants that this Amendment and the Purchase Agreement and the Loan Agreement, each as amended by this Amendment, constitute legal, valid and binding obligations of such Person enforceable against such Person in accordance with their terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors’ rights generally and general equitable principles.

SECTION 5. Reference to and the Effect on the Purchase Agreement and the Loan Agreement.

(a) On and after the effective date of this Amendment, each reference in the Purchase Agreement to “this Agreement”, “hereunder”, “hereof”, “herein” or words of like import referring to the Purchase Agreement and each reference to the Purchase Agreement in any certificate delivered in connection therewith, shall mean and be a reference to the Purchase Agreement as amended hereby.

(b) Each of the parties hereto hereby agrees that, except as specifically amended above, the Purchase Agreement is hereby ratified and confirmed and shall continue to be in full force and effect and enforceable, except as such enforcement may be limited by applicable bankruptcy, insolvency, reorganization or other similar laws relating to or limiting creditors’ rights generally and general equitable principles.

(c) On and after the effective date of this Amendment, each reference in the Loan Agreement to “this Agreement”, “hereunder”, “hereof”, “herein” or words of like import referring to the Loan Agreement and each reference to the Loan Agreement in any certificate delivered in connection therewith, shall mean and be a reference to the Loan Agreement as amended hereby.

(d) Each of the parties hereto hereby agrees that, except as specifically amended above, the Loan Agreement is hereby ratified and confirmed and shall continue to be in full force and effect and enforceable, except as such enforcement may be limited by applicable bankruptcy, insolvency, reorganization or other similar laws relating to or limiting creditors’ rights generally and general equitable principles.

SECTION 6. Execution in Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same agreement.

SECTION 7. Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[Signature page follows.]

3

IN WITNESS WHEREOF, the parties have executed this Amendment as of the day and year first above written.

TAMPA ELECTRIC COMPANY,
as Originator and as Servicer
By:	/s/ Kim M. Caruso
Name:	Kim M. Caruso
Title:	Treasurer
TEC RECEIVABLES CORP., as Purchaser and as Borrower
By:	/s/ Kim M. Caruso
Name:	Kim M. Caruso
Title:	Treasurer
CITIBANK, N.A., as Program Agent and as the sole Managing Agent
By:	/s/ Kosta Karantzoulis
Name:	Kosta Karantzoulis
Title:	Vice President
CAFCO, LLC, as the sole Conduit Lender and as the sole Committed Lender
By:	Citibank, N.A.,
	as Attorney-in-Fact
By:	/s/ Kosta Karantzoulis
Name:	Kosta Karantzoulis
Title:	Vice President

Signature Page to

Omnibus Amendment No. 12

Annex A

SCHEDULE I

LENDER GROUPS

Citibank, N.A. Lender Group

Managing Agent:	Citibank, N.A.
Conduit Lender:	CAFCO, LLC
Conduit Lending Limit:	$150,000,000
Committed Lender:	CAFCO, LLC
Commitments:	$150,000,000
Reference Bank:	Citibank, N.A.

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.

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

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.

	Year Ended Dec. 31,
(millions)	2013			2012			2011			2010			2009
Income from continuing operations, before income tax	$	364.4		$	368.9		$	380.7		$	386.6		$	303.7
Interest expense		112.7			129.9			141.9			143.9			141.2
Earnings before taxes and fixed charges	$	477.1		$	498.8		$	522.6		$	530.5		$	444.9
Interest expense	$	112.7		$	129.9		$	141.9		$	143.9		$	141.2
Total fixed charges	$	112.7		$	129.9		$	141.9		$	143.9		$	141.2
Ratio of earnings to fixed charges		4.23	x		3.84	x		3.68	x		3.69	x		3.15	x

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

EX-21

Exhibit 21

SUBSIDIARIES OF TECO ENERGY, INC.

The following is a list of subsidiaries (greater than 50% owned) of TECO Energy, Inc. and their resepctive states or other jurisdictions of incorporation or organization:

Subsidiary Name	State or Other Jurisdiction of Incorporation or Organization
Bear Branch Coal Company	Kentucky
Clintwood Elkhorn Mining Company	Kentucky
Gatliff Coal Company	Kentucky
Peoples Gas System (Florida), Inc.	Florida
Perry County Coal Corporation	Kentucky
Pike-Letcher Land Company	Kentucky
Premier Elkhorn Coal Company	Kentucky
Raven Rock Development Corporation	Kentucky
Ray Coal Company, Inc.	Kentucky
Rich Mountain Coal Company	Tennessee
SeaCoast Gas Transmission, LLC	Delaware
Tampa Electric Company	Florida
TECO Clean Advantage Corporation	Florida
TECO Coalbed Methane Florida, Inc.	Florida
TECO Coal Corporation	Kentucky
TECO Diversified, Inc.	Florida
TECO Energy Foundation, Inc.	Florida
TECO EnergySource, Inc.	Florida
TECO Finance, Inc.	Florida
TECO Gemstone, Inc.	Florida
TECO Guatemala Holdings II, LLC	Florida
TECO Guatemala Holdings, LLC	Delaware
TECO Guatemala, Inc.	Florida
TECO Investments, Inc.	Florida
TECO Oil & Gas, Inc.	Florida
TECO Partners, Inc.	Florida
TECO Pipeline Holding Company, LLC	Florida
TECO Properties Corporation	Florida
TECO Services, Inc.	Florida
TECO Solutions, Inc.	Florida
TECO Wholesale Generation, Inc.	Florida
TEC Receivables Corp.	Delaware
Whitaker Coal Corporation	Kentucky

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED CERTIFIED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-02563, 333-25563, 333-60776 and 333-115954) and Form S-3 (Nos. 333-110273 and 333-179719) of TECO Energy, Inc. of our report dated February 28, 2014 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

February 28, 2014

PricewaterhouseCoopers LLP, 4040 West Boy Scout Boulevard, Suite 1000, Tampa, FL 33607-5745

T: (813) 229 0221, F: (812) 229 3646, www.pwc.com/us

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED CERTIFIED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-179719) of Tampa Electric Company of our report dated February 28, 2014 relating to the financial statements and the financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

February 28, 2014

PricewaterhouseCoopers LLP, 4040 West Boy Scout Boulevard, Suite 1000, Tampa, FL 33607-5745

T: (813) 229 0221, F: (812) 229 3646, www.pwc.com/us

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT EXPERTS

Cardno MM&A hereby consents to the incorporation by reference into the Registration Statement on Form S-3 (Registration Statement No. 333-179719) of TECO Energy, Inc. (the “Company”) of the information contained in our audit report, dated as of January 29, 2014, regarding the coal reserves of the Company’s subsidiaries, the results of which audit are reflected in the Company’s Annual Report on Form 10-K.

Cardno MM&A

/s/ K. Scott Keim

K. Scott Keim

President

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, John B. Ramil, certify that:

1. I have reviewed this annual report on Form 10-K 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: February 28, 2014	/s/ J. B. RAMIL
	J. B. RAMIL
	President and Chief Executive Officer (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

1. I have reviewed this annual report on Form 10-K 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: February 28, 2014	/s/   S.W. CALLAHAN
	S.W. CALLAHAN
	Senior Vice President-Finance and Accounting and Chief       Financial Officer
	(Chief Accounting Officer)
	(Principal Financial and Principal Accounting Officer)

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, John B. Ramil, certify that:

1. I have reviewed this annual report on Form 10-K 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: February 28, 2014	/s/ J. B. RAMIL
	J. B. RAMIL
	Chief Executive Officer
	(Principal Executive Officer)

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Sandra W. Callahan, certify that:

1. I have reviewed this annual report on Form 10-K 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: February 28, 2014	/s/ S.W. CALLAHAN
	S.W. CALLAHAN
	Vice President-Finance and Accounting and     Chief Financial Officer
	(Chief Accounting Officer)
	(Principal Financial and Principal 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 or her knowledge, the Annual Report on Form 10-K of the Company for the year ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 28, 2014	/s/ J. B. RAMIL
	J. B. RAMIL
	President and Chief Executive Officer     (Principal Executive Officer)

Dated: February 28, 2014	/s/ S.W. CALLAHAN
	S.W. CALLAHAN
	Senior Vice President-Finance and Accounting and Chief     Financial Officer
	(Chief Accounting Officer)     (Principal Financial and Principal Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signatures that appear 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-K and shall not be considered filed as part of the Form 10-K.

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 or her knowledge, the Annual Report on Form 10-K of the Company for the year ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in that Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 28, 2014	/s/ J. B. RAMIL
	J. B. RAMIL
	Chief Executive Officer
	(Principal Executive Officer)

Dated: February 28, 2014	/s/ S.W. CALLAHAN
	S.W. CALLAHAN
	Vice President-Finance and Accounting and     Chief Financial Officer
	(Chief Accounting Officer)     (Principal Financial and Principal Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signatures that appear 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-K and shall not be considered filed as part of the Form 10-K.

EX-95

Exhibit 95

MINE SAFETY DISCLOSURE

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

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

					For the year ended December 31, 2013 (1)(2)
Mine ID #	Section 104 Significant & Substantial Citations		Section 104(b) Orders		Section 104(d) Citations and Orders		Section 110(b)(2) Violations		Section 107(a) Orders		Proposed MSHA Assessments (in thousands)		Fatalities		Pending Legal Actions (3)(4)		Legal Actions Initiated			Legal Actions Resolved During 2013
Clintwood Elkhorn
15-16734		0		0		0		0		0	$	1		0		6		0			1
15-18524		0		0		0		0		0		0		0		0		0			0
15-19396		1		0		0		0		0		1		0		0		0			1
44-03010		10		0		0		0		0		6		0		2		2			17
44-07108		0		0		0		0		0		0		0		1		0			3
44-07199		16		0		0		0		0		17		0		8		4			25
YGX (5)		0		0		0		0		0		0		0		3		0			2
Totals		27		0		0		0		0	$	25		0		20		6			49
Perry County
15-05485		11		0		0		0		0	$	8		0		24		24			22
15-18565 (9)		32		0		0		0		0		84		0		49		53			263
15-18662 (10)		9		0		0		0		0		28		0		35		14			359
15-19015 (11)		41		0		1		0		0		103		0		45		63			409
Totals		93		0		1		0		0	$	223		0		153		154			1,053
Premier Elkhorn
15-16470		2		0		0		0		0	$	2		0		0		0			11
15-17360 (8)		0		0		0		0		0		0		0		0		0			0
15-18784		7		0		0		0		0		17		0		0		0			3
15-18823		11		0		0		0		0		23		0		6		6			15
15-18892		0		0		0		0		0		0		0		0		0			0
15-18946		4		0		0		0		0		9		0		0		0			0
15-19411		0		0		0		0		0		0		0		0		0			0
15-19590		0		0		0		0		0		0		0		0		0			0
15-19622		2		0		0		0		0		3		0		0		0			6
15-19642		0		0		0		0		0		0		0		0		0			0
15-19649		0		0		0		0		0		0		0		0		0			0
15-19650		0		0		0		0		0		0		0		0		0			0
15-19721		0		0		0		0		0		0		0		0		0			0
A906 (6)( 7)		0		0		0		0		0		7		0		0		0			5
Totals		26		0		0		0		0	$	61		0		6		6			40
Grand Totals		146		0		1		0		0	$	309		0		179		166	(12)		1,142

1. Based on data obtained from MSHA Mine Data Retrieval System (MDRS) as of Jan. 3, 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 period, nor indicates a POV status on MSHA’s MDRS system as of Jan. 3, 2014.

3. All of the Pending Legal Actions identified in this column are based on data contained in the MSHA MDRS at the time of data retrieval for this report. Includes any citation status “In Contest”, “Hearing Case Filed” or “Payment Pending”.

4. All of the Pending Legal Actions involve citations or orders referenced in Subpart B of 29 C.F.R. Part 2700 that are being contested by a TECO Coal Corporation subsidiary. Includes any citation status “In Contest”, “Hearing Case Filed” or “Payment Pending”.

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

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

7. In addition to the number of “Legal Actions Resolved During the Period”, 18 vacated citations that were shown “In Contest” in the 2012 year-end report are no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

8. In addition to the number of “Legal Actions Resolved During the Period”, two vacated citations that were shown “In Contest” in the 2012 year-end report are no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

9. In addition to the number of “Legal Actions Resolved During the Period”, two vacated citations that were shown “In Contest” in the 2012 year-end report are no longer within the MSHA MDRS, and are therefore no longer reflected on this report. Also, two citations shown in the MDRS at the time of data retrieval for the second quarter of 2013 had been moved from Perry County Coal Corporation to a trucking contractor sometime during the 3rd quarter of 2013.

10. In addition to the number of “Legal Actions Resolved During the Period”, six vacated citations that were shown “In Contest” in the 2012 year-end report are no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

11. In addition to the number of “Legal Actions Resolved During the Period”, four vacated citations that were shown “In Contest” in the 2012 year-end report are no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

12. 34 vacated citations that were shown as “Legal Actions Initiated” during 2013 are no longer within the MSHA MDRS, and are therefore no longer reflected on this report.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Estimated Useful Lives of Depreciable Property

Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:

Asset	Estimated Useful Lives
Building and improvements	5 - 40 years
Office equipment and furniture	3 - 30 years
Vehicles, mining and other equipment	2 - 15 years
Coal processing facilities	7 - 20 years
Computer software	2 - 15 years

Schedule of Fuel Inventory

Fuel Inventory (millions)	Dec. 31, 2013		Dec. 31, 2012
TEC	$	93.7	$	89.1
TECO Coal		25.0		34.5
Total	$	118.7	$	123.6

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Asset Retirement Obligations - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	$ 28.6	$ 28.6	$ 53.8
Accretion expense	1.4	1.4	1.4
Liabilities settled	1.4	29.1
Tampa Electric Company [Member]
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	4.8	5.0	30.8
Cost of removal or dismantling of assets charged to regulatory liability	4.8	5.0
Liabilities settled	0.2	27.6
TECO Energy [Member]
Asset Retirement Obligation [Line Items]
Obligations arise from environmental remediation	$ 23.8	$ 23.6

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Goodwill and Asset Impairments (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Changes in Carrying Amount of Goodwill

The changes in the carrying amount of goodwill for the year ended Dec. 31, 2012 are represented in the following table:

(millions)	TPS GO			TPS SJI			Total
Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4
Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)
Goodwill written off upon sale, pretax		0.0			(40.2	)		(40.2	)
Balance as of Dec. 31, 2012	$	0.0		$	0.0		$	0.0

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Future Minimum Lease Payments

The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:

Future Minimum Lease and Capacity Payments
(millions)	Capacity Payments		Operating Leases		Total
Year ended Dec. 31:
2014	$	14.8	$	5.0	$	19.8
2015		14.9		3.9		18.8
2016		14.6		2.6		17.2
2017		9.9		2.4		12.3
2018		10.1		2.2		12.3
Thereafter		0.0		13.4		13.4
Total future minimum payments	$	64.3	$	29.5	$	93.8

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 Dec. 31, 2013 are as follows:

Guarantees-TECO Energy
(millions)					After (1)				Liabilities Recognized
Guarantees for the Benefit of:	2014		2015-2018		2018		Total		at Dec. 31, 2013
TECO Coal
Fuel purchase related (2)	$	0.8	$	0.7	$	4.0	$	5.5	$	1.5
Other subsidiaries
Guaranty under sale agreement (3)		0.0		5.0		0.0		5.0		5.0
Fuel sales and transportation (2)		10.0		0.0		91.8		101.8		0.1
Total	$	10.8	$	5.7	$	95.8	$	112.3	$	6.6
Letters of Credit-Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2014		2015-2018		2018		Total		at Dec. 31, 2013
Tampa Electric (2)	$	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 Dec. 31, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement. See Note 19 for additional information.

Tampa Electric Company [Member]

Schedule of Future Minimum Lease Payments

The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:

Future Minimum Lease and Capacity Payments
(millions)	Capacity Payments		Operating Leases		Total
Year ended Dec. 31:
2014	$	14.8	$	2.3	$	17.1
2015		14.9		2.3		17.2
2016		14.6		2.2		16.8
2017		9.9		2.2		12.1
2018		10.1		2.2		12.3
Thereafter		0.0		13.4		13.4
Total future minimum payments	$	64.3	$	24.6	$	88.9

Letters of Credit and Guarantees

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After (1) 2018		Total		Liabilities Recognized at Dec. 31, 2013
Tampa Electric (2)
Letters of credit	$	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 Dec. 31, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

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Accounting for Derivative Instruments and Hedging Activities - Derivative Volumes Expected to Settle (Detail)	Dec. 31, 2013 gal
Diesel Fuel Derivatives [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Physical [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Diesel Fuel Derivatives [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,000,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	2,000,000
Diesel Fuel Derivatives [Member] | Financial [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2014 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Physical [Member] | 2015 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0
Natural Gas Contracts [Member] | Financial [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	44,500,000
Natural Gas Contracts [Member] | Financial [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	44,500,000
Natural Gas Contracts [Member] | Financial [Member] | 2014 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36,900,000
Natural Gas Contracts [Member] | Financial [Member] | 2014 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36,900,000
Natural Gas Contracts [Member] | Financial [Member] | 2015 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,600,000
Natural Gas Contracts [Member] | Financial [Member] | 2015 [Member] | Tampa Electric Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,600,000

XML

Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Beginning Balance	$ 2.9	$ 4.1
Decreases due to tax positions related to prior years	0	0
Decreases due to settlements with taxing authorities	0	0
Decreases due to expiration of statute of limitations	(2.9)	0
Dispositions	0	(1.2)
Ending Balance	$ 0	$ 2.9

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Fair Value Measurements - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	$ 10.0	$ 0.2
Total Swap Liabilities	0.3	15.2
Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	10.0	0.2
Total Swap Liabilities	0.3	15.2
Tampa Electric Company [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value Assets Liabilities Measured On Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	$ 0	$ 0

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Quarterly Data (unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Financial Data by Quarter

Financial data by quarter is as follows:

(millions, except per share amounts) Quarter ended	Dec. 31		Sept. 30		June 30		March 31
2013
Revenues	$	688.4	$	765.9	$	735.9	$	661.1
Income from operations		99.6		140.5		119.5		104.1
Net income from continuing operations		42.1		62.9		51.6		41.2
Net income attributable to TECO Energy		42.0		62.8		51.4		41.5
EPS - Basic
From continuing operations	$	0.20	$	0.29	$	0.24	$	0.19
Attributable to TECO Energy		0.20		0.29		0.24		0.19
EPS - Diluted
From continuing operations	$	0.20	$	0.29	$	0.24	$	0.19
Attributable to TECO Energy		0.20		0.29		0.24		0.19
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220
Quarter ended	Dec. 31		Sept. 30		June 30		March 31
2012
Revenues (1)	$	688.4	$	858.6	$	752.5	$	697.1
Income from operations (1)		109.5		183.1		149.1		114.8
Net income from continuing operations (1)		45.6		90.2		65.6		44.6
Net income attributable to TECO Energy		45.1		44.0		73.1		50.5
EPS - Basic
From continuing operations (1)	$	0.21	$	0.42	$	0.30	$	0.21
Attributable to TECO Energy		0.21		0.20		0.34		0.24
EPS - Diluted
From continuing operations (1)	$	0.21	$	0.42	$	0.30	$	0.20
Attributable to TECO Energy		0.21		0.20		0.34		0.23
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220

(1) Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

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Employee Postretirement Benefits - Schedule of Assumptions Used to Determine Benefit (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.118%	4.196%
Rate of compensation increase - weighted	3.73%	3.76%
Healthcare cost trend rate
Immediate rate
Ultimate rate
Year rate reaches ultimate
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.118%	4.196%
Rate of compensation increase - weighted	3.73%	3.76%
Healthcare cost trend rate
Immediate rate
Ultimate rate
Year rate reaches ultimate
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.096%	4.18%
Rate of compensation increase - weighted	3.71%	3.74%
Healthcare cost trend rate
Immediate rate	7.25%	7.50%
Ultimate rate	4.50%	4.50%
Year rate reaches ultimate	2025	2025
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.096%	4.18%
Rate of compensation increase - weighted	3.71%	3.74%
Healthcare cost trend rate
Immediate rate	7.25%	7.50%
Ultimate rate	4.50%	4.50%
Year rate reaches ultimate	2025	2025
Net Periodic Benefit Cost [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.196%	4.797%	5.30%
Expected long-term return on plan assets	7.50%	7.50%	7.75%
Rate of compensation increase	3.76%	3.83%	3.88%
Healthcare cost trend rate
Immediate rate
Ultimate rate
Year rate reaches ultimate
Net Periodic Benefit Cost [Member] | Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.196%	4.797%	5.30%
Expected long-term return on plan assets	7.50%	7.50%	7.75%
Rate of compensation increase	3.76%	3.83%	3.88%
Healthcare cost trend rate
Immediate rate
Ultimate rate
Year rate reaches ultimate
Net Periodic Benefit Cost [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.18%	4.744%	5.25%
Expected long-term return on plan assets
Rate of compensation increase	3.74%	3.82%	3.87%
Healthcare cost trend rate
Immediate rate	7.50%	7.75%	8.00%
Ultimate rate	4.50%	4.50%	4.50%
Year rate reaches ultimate	2025	2025	2023
Net Periodic Benefit Cost [Member] | Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.18%	4.744%	5.25%
Rate of compensation increase	3.74%	3.82%	3.87%
Healthcare cost trend rate
Immediate rate	7.50%	7.75%	8.00%
Ultimate rate	4.50%	4.50%	4.50%
Year rate reaches ultimate	2025	2025	2023

XML

Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended			6 Months Ended	12 Months Ended			11 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013 Tampa Electric Company [Member] Plaintiff	Dec. 31, 2013 Tampa Electric Company [Member]	Dec. 31, 2012 Tampa Electric Company [Member]	Dec. 31, 2011 Tampa Electric Company [Member]	Nov. 30, 2010 PGS [Member] Plaintiff	Dec. 31, 2013 PGS [Member]
Long Term Commitments [Line Items]
Number of commercial PGS customers filing on behalf of PGS customers				3				2
Ultimate financial liability to superfund sites and former MGP sites									$ 40.4
Total rental expense and leases	7.6	8.1	10.2		2.3	2.2	2.2
Letters of Credit Outstanding	$ 0.7	$ 1.5			$ 0.7	$ 1.5

XML

Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2013

Other Comprehensive Income

TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

Other Comprehensive Income
(millions)	Gross			Tax			Net
2013
Unrealized gain (loss) on cash flow hedges	$	1.0		$	(0.4	)	$	0.6
Reclassification from AOCI to net income		1.3			(0.5	)		0.8
Gain (Loss) on cash flow hedges		2.3			(0.9	)		1.4
Amortization of unrecognized benefit costs and other		23.6			(8.8	)		14.8
Recognized benefit costs due to settlement		2.6			(1.0	)		1.6
Total other comprehensive income (loss)	$	28.5		$	(10.7	)	$	17.8
2012
Unrealized (loss) gain on cash flow hedges	$	(7.4	)	$	2.8		$	(4.6	)
Reclassification from AOCI to net income		0.6			(0.2	)		0.4
(Loss) Gain on cash flow hedges		(6.8	)		2.6			(4.2	)
Amortization of unrecognized benefit costs and other (1)		(4.8	)		0.0			(4.8	)
Total other comprehensive (loss) income	$	(11.6	)	$	2.6		$	(9.0	)
2011
Unrealized gain (loss) on cash flow hedges	$	1.8		$	(0.6	)	$	1.2
Reclassification from AOCI to net income		(3.1	)		1.1			(2.0	)
(Loss) Gain on cash flow hedges		(1.3	)		0.5			(0.8	)
Amortization of unrecognized benefit costs and other		(7.9	)		3.3			(4.6	)
Recognized benefit costs due to settlement		0.9			(0.3	)		0.6
Total other comprehensive (loss) income	$	(8.3	)	$	3.5		$	(4.8	)

(1) Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions) As of Dec. 31,	2013			2012
Unrecognized pension losses and prior service credits (2)	$	(20.5	)	$	(32.9	)
Unrecognized other benefit gains, prior service costs and transition obligations (3)		15.1			11.1
Net unrealized losses from cash flow hedges (4)		(7.8	)		(9.2	)
Total accumulated other comprehensive loss	$	(13.2	)	$	(31.0	)

(2) Net of tax benefit of $12.6 million and $20.1 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax expense of $9.1 million and $6.7 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

(4) Net of tax benefit of $4.9 million and $5.8 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

TEC reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income
(millions)	Gross			Tax			Net
2013
Unrealized gain (loss) on cash flow hedges	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		1.4			(0.5	)		0.9
Gain (Loss) on cash flow hedges		1.4			(0.5	)		0.9
Total other comprehensive income (loss)	$	1.4		($	0.5	)	$	0.9
2012
Unrealized (loss) gain on cash flow hedges	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		1.4			(0.6	)		0.8
(Loss) Gain on cash flow hedges		(6.6	)		2.5			(4.1	)
Total other comprehensive (loss) income	($	6.6	)	$	2.5		($	4.1	)
2011
Unrealized gain (loss) on cash flow hedges	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		1.2			(0.5	)		0.7
Gain (Loss) on cash flow hedges		1.2			(0.5	)		0.7
Total other comprehensive income (loss)	$	1.2		($	0.5	)	$	0.7

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss
(millions) As of Dec. 31,	2013			2012
Net unrealized losses from cash flow hedges (1)	($	7.8	)	($	8.7	)
Total accumulated other comprehensive loss	($	7.8	)	($	8.7	)

(1) Net of tax benefit of $4.9 million and $5.5 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

XML

Dispositions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Dispositions

21. Dispositions

Sale of San José and Alborada

On Sept. 27, 2012, TECO Guatemala entered into an agreement to sell all of the equity interests in the Alborada and San José power stations and their related facilities and operations in Guatemala for a total purchase price of $227.5 million in cash. The TECO Guatemala segment was accounted for as discontinued operations beginning in the third quarter of 2012. For more information regarding the sale, see Note 19.

While TECO Energy and its subsidiaries will no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala in October 2010 under the DR – CAFTA. For more information on the claim, see Note 19.

Net proceeds from the sale of all Guatemalan operations, after estimated transaction-related costs and the $25.3 million repayment of the San José power station project debt, were approximately $197.0 million. The sale resulted in an after-tax book loss and an after-tax charge associated with foreign tax credits of $28.6 million and $22.9 million, respectively.

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Employee Postretirement Benefits - Schedule of One-percentage-point Change in Assumed Health Care Cost (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Effect on periodic cost - Increase	$ 0.3
Effect on periodic cost - Decrease	(0.3)
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on periodic cost - Increase	0.2
Effect on periodic cost - Decrease	(0.2)
Assumed One-percentage-point Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation - Increase	6.8
Effect on postretirement benefit obligation - Decrease	(6.1)
Assumed One-percentage-point Change [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on postretirement benefit obligation - Increase	5.6
Effect on postretirement benefit obligation - Decrease	$ (5.0)

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Accounting for Derivative Instruments and Hedging Activities - Energy Related Derivatives (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Current regulatory assets	$ 34.3	$ 70.3
Long-term regulatory assets	293.1	382.6
Regulatory assets	327.4	452.9
Current regulatory liabilities	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	34.3	70.3
Long-term regulatory assets	293.1	382.6
Regulatory assets	327.4	452.9
Current regulatory liabilities	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Regulatory liabilities	717.2	737.0
Energy Related Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	0	14.1
Long-term regulatory assets	0.2	0.2
Regulatory assets	0.2	14.3
Current regulatory liabilities	9.5	0
Long-term regulatory liabilities	0.3	0.2
Regulatory liabilities	9.8	0.2
Energy Related Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current regulatory assets	0	14.1
Long-term regulatory assets	0.2	0.2
Regulatory assets	0.2	14.3
Current regulatory liabilities	9.5	0
Long-term regulatory liabilities	0.3	0.2
Regulatory liabilities	$ 9.8	$ 0.2

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Discontinued Operations - Components of Discontinued Operations (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) from discontinued operations	$ (0.2)	$ (10.6)	$ 33.3
Provision for income taxes	0.1	(22.4)	(11.2)
Income (loss) from discontinued operations, net	(0.1)	(33.0)	22.1
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.3	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	(0.1)	(33.3)	21.8
TECO Guatemala [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	0	114.2	133.5
(Loss) income from operations	(0.2)	27.7	33.7
Loss on assets sold, including transaction costs	0	(38.3)	(0.4)
Income (loss) from discontinued operations	(0.2)	(10.6)	33.3
Provision for income taxes	(0.1)	22.4	11.2
Income (loss) from discontinued operations, net	(0.1)	(33.0)	22.1
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.3	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	$ (0.1)	$ (33.3)	$ 21.8

XML

Subsequent Events - Additional Information (Detail) (USD $)								0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Tampa Electric Company [Member]	Dec. 17, 2013 Tampa Electric Company [Member]	Dec. 31, 2012 Tampa Electric Company [Member]	Dec. 31, 2013 1-year Accounts Receivable Facility [Member] Tampa Electric Company [Member]	Dec. 31, 2012 1-year Accounts Receivable Facility [Member] Tampa Electric Company [Member]	Feb. 15, 2014 Subsequent Event [Member]	Feb. 15, 2014 Subsequent Event [Member] Tampa Electric Company [Member]	Feb. 15, 2014 Subsequent Event [Member] 1-year Accounts Receivable Facility [Member]	Feb. 15, 2014 Subsequent Event [Member] 1-year Accounts Receivable Facility [Member] Tampa Electric Company [Member]
Subsequent Event [Line Items]
Line of credit facility maximum borrowing capacity	$ 675,000,000	$ 675,000,000	$ 475,000,000	$ 200,000,000	$ 475,000,000	$ 150,000,000	$ 150,000,000		$ 150,000,000	$ 150,000,000	$ 150,000,000
Basis spread on federal funds rate									0.50%	0.50%
Commitment fees, percentage									0.70%	0.70%
Debt instrument maturity date								Feb. 13, 2015	Feb. 13, 2015	Feb. 13, 2015

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Employee Postretirement Benefits - Schedule of Change in Plan Assets (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Change in plan assets
Fair value of plan assets at beginning of year	$ 529,100,000
Employer contributions	42,000,000	35,500,000
Fair value of plan assets at end of year	593,000,000	529,100,000
Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	529,100,000	467,600,000
Actual return on plan assets	63,700,000	57,900,000
Employer contributions	45,900,000	36,800,000
Plan participants' contributions	0	0
Settlements	(2,600,000)	0
Gross benefits paid	(43,100,000)	(33,200,000)
Fair value of plan assets at end of year	593,000,000	529,100,000
Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	11,900,000	9,800,000
Plan participants' contributions	2,900,000	3,700,000
Settlements	0	0
Gross benefits paid	(14,800,000)	(13,500,000)
Fair value of plan assets at end of year	0	0
TECO Energy [Member] | Pension Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	529,100,000	467,600,000
Actual return on plan assets	63,700,000	57,900,000
Employer contributions	45,900,000	36,800,000
Plan participants' contributions	0	0
Settlements	(2,600,000)	0
Gross benefits paid	(43,100,000)	(33,200,000)
Fair value of plan assets at end of year	593,000,000	529,100,000
TECO Energy [Member] | Other Postretirement Benefits [Member]
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	11,900,000	9,800,000
Plan participants' contributions	2,900,000	3,700,000
Settlements	0	0
Gross benefits paid	(14,800,000)	(13,500,000)
Fair value of plan assets at end of year	$ 0	$ 0

XML

Long Term Debt - Schedule of Long Term Debt Outstanding (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term debt, total	$ 2,923.8	$ 2,975.4
Unamortized debt discount, net	(2.7)	(2.7)
Long-term debt, carrying amount	2,921.1	2,972.7
Less amount due within one year	83.3	0
Total long-term debt	2,837.8	2,972.7
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,650.9	1,702.5
Less amount due within one year	83.3	0
Total long-term debt	1,797.5	1,932.6
TECO Finance [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,041.2	1,041.2
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	231.7	231.7
Variable Rate Bonds Repurchased In 2008 [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	0	0
6.75% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2015
Long-term debt, total	191.2	191.2
4.00% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2016
Long-term debt, total	250.0	250.0
6.752% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2017
Long-term debt, total	300.0	300.0
5.15% Notes [Member] | TECO Finance [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	300.0	300.0
5.65% Refunding bonds [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	54.2	54.2
5.15% Refunding bonds [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2025
Long-term debt, total	0	51.6
1.5% term rate bonds repurchased in 2011 [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2030
Long-term debt, total	0	0
5.0% Refunding bonds [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2034
Long-term debt, total	0	0
6.25% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Maturity range start	2014
Due	2016
Long-term debt, total	250.0	250.0
6.1% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	200.0	200.0
6.1% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	50.0	50.0
5.4% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	231.7	231.7
5.4% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	46.7	46.7
2.6% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	225.0	225.0
2.6% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	25.0	25.0
6.55% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	250.0	250.0
6.15% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	190.0	190.0
6.15% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	60.0	60.0
4.1% Notes [Member]
Debt Instrument [Line Items]
Due	2042
4.1% Notes [Member] | Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	250.0	250.0
4.1% Notes [Member] | PGS [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 50.0	$ 50.0

XML

Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended			56 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Equity method investment information	In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest
Equity method investment, Ownership percentage	50.00%			50.00%
Restricted cash	$ 0	$ 8.7		$ 0
Percentage of original cost of depreciable property	3.70%	3.80%	3.60%
Depreciation expense	316.5	309.3	306.6
Purchased power	64.7	105.3	125.9
Franchise fees and gross receipts taxes	108.5	111.5	109.3
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	3.51%	2.60%
Minimum [Member] | Computer Software [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	2 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rates used in estimating other self-insurance liabilities	4.86%	4.00%
Maximum [Member] | Computer Software [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	15 years
Unbilled Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	46.7	49.0		46.7
Tampa Electric Company [Member]
Summary Of Significant Accounting Policies [Line Items]
Equity method investment information	In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest
Equity method investment, Ownership percentage	50.00%			50.00%
Percentage of original cost of depreciable property	3.70%	3.80%	3.60%
Depreciation expense	284.2	275.1	263.7
Allowance for funds used during construction rate				8.16%
Allowance for funds used during construction	9.9	4.1	1.6
Purchased power	64.7	105.3	125.9
Franchise fees and gross receipts taxes	108.5	111.5	109.3
Tampa Electric Company [Member] | Computer Software [Member]
Summary Of Significant Accounting Policies [Line Items]
Amortization period	15 years
Tampa Electric Company [Member] | Unbilled Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Unbilled revenues	46.7	49.0		46.7
TECO Energy Source [Member]
Summary Of Significant Accounting Policies [Line Items]
Costs netted against revenues	23.1	13.8	2.5
TECO Coal [Member]
Summary Of Significant Accounting Policies [Line Items]
Shipping and Handling	$ 8.2	$ 9.0	$ 16.6

XML

Segment Information - Schedule of Segment Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Total revenues	$ 688.4	$ 765.9	$ 735.9	$ 661.1	$ 688.4	$ 858.6	$ 752.5	$ 697.1	$ 2,851.3	$ 2,996.6	$ 3,209.9
Depreciation and amortization									329.5	330.6	317.2
Total interest charges									166.9	183.5	197.4
Internally allocated interest									0	0	0
Provision for income taxes									108.9	137.8	142.7
Net income from continuing operations	42.1	62.9	51.6	41.2	45.6	90.2	65.6	44.6	197.8	246.0	250.8
Discontinued operations attributable to TECO, net of tax									(0.1)	(33.3)	21.8
Net income	42.0	62.8	51.4	41.5	45.1	44.0	73.1	50.5	197.7	212.7	272.6
Total assets	7,448.0				7,334.9				7,448.0	7,334.9	7,307.2
Capital expenditures									532.4	505.1	454.1
Goodwill					0					0	55.4
Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									11.1	7.5	2.8
Depreciation and amortization									1.5	1.4	1.4
Total interest charges									56.1	50.6	51.0
Internally allocated interest									(6.4)	(6.8)	(6.7)
Provision for income taxes									(26.3)	(19.6)	(18.1)
Net income from continuing operations									(36.8)	(31.4)	(36.0)
Discontinued operations attributable to TECO, net of tax									(0.1)	(4.0)	(0.6)
Net income									(36.9)	(35.4)	(36.6)
Total assets	(16.4)				(238.8)				(16.4)	(238.8)	(240.0)
Capital expenditures									2.4	1.2	3.5
Goodwill											0
Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues									2,851.3	2,996.6	3,209.9
Revenues - External [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									12.8	10.4	7.1
Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
Sales to Affiliates [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									(1.7)	(2.9)	(4.3)
Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									1,950.5	1,981.3	2,020.6
Depreciation and amortization									238.8	237.6	222.1
Total interest charges									91.8	109.8	121.8
Internally allocated interest									0	0	0
Provision for income taxes									116.9	120.2	124.8
Net income from continuing operations									190.9	193.1	202.7
Discontinued operations attributable to TECO, net of tax									0	0	0
Net income									190.9	193.1	202.7
Total assets	6,126.9				6,042.3				6,126.9	6,042.3	5,925.9
Capital expenditures									428.6	361.7	314.9
Goodwill											0
Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									1,949.6	1,980.7	2,019.3
Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0.9	0.6	1.3
PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									393.5	398.9	453.5
Depreciation and amortization									51.5	50.6	48.4
Total interest charges									13.5	16.0	17.7
Internally allocated interest									0	0	0
Provision for income taxes									21.9	21.5	20.6
Net income from continuing operations									34.7	34.1	32.6
Discontinued operations attributable to TECO, net of tax									0	0	0
Net income									34.7	34.1	32.6
Total assets	1,021.2				1,009.9				1,021.2	1,009.9	932.0
Capital expenditures									79.0	97.3	71.9
Goodwill											0
PGS [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									392.7	396.6	450.5
PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0.8	2.3	3.0
TECO Coal [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									496.2	608.9	733.0
Depreciation and amortization									37.7	41.0	45.3
Total interest charges									5.5	7.1	6.9
Internally allocated interest									6.4	6.8	6.7
Provision for income taxes									(3.6)	15.7	15.4
Net income from continuing operations									9.0	50.2	51.5
Discontinued operations attributable to TECO, net of tax									0	0	0
Net income									9.0	50.2	51.5
Total assets	316.3				356.6				316.3	356.6	385.2
Capital expenditures									22.4	36.3	56.6
Goodwill											0
TECO Coal [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									496.2	608.9	733.0
TECO Coal [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
TECO Guatemala [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Depreciation and amortization									0	0	0
Total interest charges									0	0	0
Internally allocated interest									0	0	0
Provision for income taxes									0	0	0
Net income from continuing operations									0	0	0
Discontinued operations attributable to TECO, net of tax									0	(29.3)	22.4
Net income									0	(29.3)	22.4
Total assets	0				164.9				0	164.9	304.1
Capital expenditures									0	8.6	7.2
Goodwill											55.4
TECO Guatemala [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
TECO Guatemala [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Total revenues									2,342.8	2,378.0	2,470.6
Depreciation and amortization									290.3	288.2	270.5
Total interest charges									105.3	125.8	139.5
Provision for income taxes									138.8	141.7	145.4
Net income									225.6	227.2	235.3
Total assets	6,875.8				6,744.6				6,875.8	6,744.6	6,556.4
Capital expenditures									507.6	459.0	386.8
Tampa Electric Company [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									(1.2)	(2.2)	(3.5)
Depreciation and amortization									0	0	0
Total interest charges									0	0	0
Provision for income taxes									0	0	0
Net income									0	0	0
Total assets	(8.9)				13.3				(8.9)	13.3	(10.0)
Capital expenditures									0	0	0
Tampa Electric Company [Member] | Revenues - External [Member]
Segment Reporting Information [Line Items]
Total revenues									2,342.8	2,378.0	2,470.6
Tampa Electric Company [Member] | Revenues - External [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues									0	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0	0	0
Tampa Electric Company [Member] | Sales to Affiliates [Member] | Other & Eliminations [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									(1.2)	(2.2)	(3.5)
Tampa Electric Company [Member] | Tampa Electric [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									1,950.5	1,981.3	2,020.6
Depreciation and amortization									238.8	237.6	222.1
Total interest charges									91.8	109.8	121.8
Provision for income taxes									116.9	120.2	124.8
Net income									190.9	193.1	202.7
Total assets	5,895.4				5,760.4				5,895.4	5,760.4	5,678.0
Capital expenditures									428.6	361.7	314.9
Tampa Electric Company [Member] | Tampa Electric [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									1,950.1	1,980.9	2,020.1
Tampa Electric Company [Member] | Tampa Electric [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									0.4	0.4	0.5
Tampa Electric Company [Member] | PGS [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									393.5	398.9	453.5
Depreciation and amortization									51.5	50.6	48.4
Total interest charges									13.5	16.0	17.7
Provision for income taxes									21.9	21.5	20.6
Net income									34.7	34.1	32.6
Total assets	989.3				970.9				989.3	970.9	888.4
Capital expenditures									79.0	97.3	71.9
Tampa Electric Company [Member] | PGS [Member] | Revenues - External [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues									392.7	397.1	450.5
Tampa Electric Company [Member] | PGS [Member] | Sales to Affiliates [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Sales to affiliates									$ 0.8	$ 1.8	$ 3.0

XML

Consolidated Statements of Capitalization - Capital Stock (Detail) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Common equity, shares authorized	400,000,000	400,000,000	400,000,000	400,000,000
Capital Stock Outstanding December 31, Shares	217,300,000	216,600,000	217,300,000	216,600,000
Cash Dividends Paid Per Share	$ 0.220	$ 0.220	$ 0.88	$ 0.88
Cash Dividends Paid			$ 191.2	$ 190.4
Tampa Electric Company [Member]
Common equity, shares authorized	25,000,000	25,000,000	25,000,000	25,000,000
Current Redemption on Price
Capital Stock Outstanding December 31, Shares	10	10	10	10
Capital Stock Outstanding December 31, Amount	2,030.4	1,970.4	2,030.4	1,970.4
Cash Dividends Paid Per Share
Cash Dividends Paid			$ 222.1	$ 228.3

XML

Employee Postretirement Benefits - Schedule of Funded Status (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of Spread years for Fair value of plan asset adjusted for experience gains and losses	5 years	5 years

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Short-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended		12 Months Ended		0 Months Ended		12 Months Ended				12 Months Ended			0 Months Ended		12 Months Ended						12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 17, 2013 Revolving Credit Facility [Member]	Feb. 15, 2014 Subsequent Event [Member]	Feb. 15, 2014 Subsequent Event [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2013 TECO Energy [Member]	Dec. 31, 2013 TECO Energy [Member] Revolving Credit Facility [Member]	Dec. 17, 2013 TECO Finance [Member]	Dec. 17, 2013 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member]	Dec. 31, 2012 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2012 Tampa Electric Company [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2013 Tampa Electric Company [Member] Amended And Restated Credit Agreement [Member]	Dec. 17, 2013 Tampa Electric Company [Member] Amended And Restated Credit Agreement [Member]	Dec. 17, 2013 Tampa Electric Company [Member] Previous Agreement [Member]	Feb. 15, 2014 Tampa Electric Company [Member] Subsequent Event [Member]	Feb. 15, 2014 Tampa Electric Company [Member] Subsequent Event [Member] 1-year Accounts Receivable Facility [Member]	Dec. 31, 2013 Minimum [Member]	Dec. 31, 2013 Minimum [Member] TECO Energy [Member]	Dec. 31, 2013 Minimum [Member] Tampa Electric Company [Member]	Dec. 31, 2013 Maximum [Member]	Dec. 31, 2013 Maximum [Member] TECO Energy [Member]	Dec. 31, 2013 Maximum [Member] TECO Energy [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 Maximum [Member] Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Commitment fees, percentage					0.70%												0.70%		0.125%		0.125%	0.25%			0.25%
Outstanding borrowings	$ 84,000,000	$ 0								$ 84,000,000	$ 0	$ 78,000,000	$ 0
Weighted-average interest rate	0.56%									0.56%
Amended credit facility	675,000,000	675,000,000	200,000,000		150,000,000			200,000,000	200,000,000	475,000,000	475,000,000	150,000,000	150,000,000		325,000,000	200,000,000	150,000,000	150,000,000
Debt instrument maturity date				Feb. 13, 2015	Feb. 13, 2015									Oct. 25, 2016 to Dec. 17, 2018			Feb. 13, 2015
Amended maturity date of credit facility	Dec. 17, 2018									Dec. 17, 2018										Oct. 25, 2016			Dec. 17, 2018
Interest rate description						TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%.			Tampa Electric Company to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%
Increase of credit facility								$ 100,000,000	$ 175,000,000
Normal capitalization ratio							0.65																	0.70

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Employee Postretirement benefits - Schedule of Pension Plan Assets (Detail) (USD $)									12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Actual Asset Allocation [Member]	Dec. 31, 2012 Actual Asset Allocation [Member]	Dec. 31, 2013 Actual Asset Allocation [Member] Equity Securities [Member]	Dec. 31, 2012 Actual Asset Allocation [Member] Equity Securities [Member]	Dec. 31, 2013 Actual Asset Allocation [Member] Fixed Income Securities [Member]	Dec. 31, 2012 Actual Asset Allocation [Member] Fixed Income Securities [Member]	Dec. 31, 2013 Target Allocation [Member]	Dec. 31, 2013 Target Allocation [Member] Equity Securities [Member] Minimum [Member]	Dec. 31, 2013 Target Allocation [Member] Equity Securities [Member] Maximum [Member]	Dec. 31, 2013 Target Allocation [Member] Fixed Income Securities [Member] Minimum [Member]	Dec. 31, 2013 Target Allocation [Member] Fixed Income Securities [Member] Maximum [Member]
Asset Category
Equity securities									100.00%	48.00%	54.00%	46.00%	52.00%
Actual Allocation, End of Year			100.00%	100.00%	54.00%	55.00%	46.00%	45.00%
Total	$ 593,000,000	$ 529,100,000	$ 1.00	$ 1.00
Target Allocation									100.00%	48.00%	54.00%	46.00%	52.00%
Asset Category
Equity securities									100.00%	48.00%	54.00%	46.00%	52.00%
Actual Allocation, End of Year			100.00%	100.00%	54.00%	55.00%	46.00%	45.00%
Total	$ 593,000,000	$ 529,100,000	$ 1.00	$ 1.00
Target Allocation									100.00%	48.00%	54.00%	46.00%	52.00%

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Long Term Debt - Additional Information (Detail) (USD $)	2 Months Ended	12 Months Ended			2 Months Ended	9 Months Ended	12 Months Ended				12 Months Ended	11 Months Ended	9 Months Ended	5 Months Ended	3 Months Ended		9 Months Ended	48 Months Ended	65 Months Ended	12 Months Ended	3 Months Ended		8 Months Ended	48 Months Ended	65 Months Ended	0 Months Ended	9 Months Ended		12 Months Ended	9 Months Ended		3 Months Ended
	Mar. 01, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 01, 2011 Tampa Electric Company [Member]	Sep. 28, 2012 Tampa Electric Company [Member]	Dec. 31, 2013 Tampa Electric Company [Member]	Dec. 31, 2012 Tampa Electric Company [Member]	Dec. 31, 2011 Tampa Electric Company [Member]	Oct. 02, 2012 Tampa Electric Company [Member]	Dec. 19, 2012 San Jose [Member]	Dec. 05, 2012 6.75% Notes due 2015 [Member]	Sep. 28, 2012 2.6% Notes [Member] Tampa Electric Company [Member]	Jun. 05, 2012 4.1% Notes [Member] Tampa Electric Company [Member]	Mar. 15, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Mar. 26, 2008 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Sep. 03, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Mar. 15, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Sep. 01, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member]	Dec. 31, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Held Bonds [Member]	Mar. 15, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Mar. 26, 2008 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Sep. 03, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Mar. 15, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Sep. 01, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member]	Oct. 02, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member] 2013 [Member]	Oct. 02, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member] 2013 [Member]	Oct. 02, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member] 2023 [Member]	Dec. 31, 2013 HCIDA Pollution Control Revenue Refunding Bonds [Member] Tampa Electric Company [Member] Held Bonds [Member]	Oct. 02, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Five Point One Percentage Refunding Bonds [Member] Tampa Electric Company [Member] 2013 [Member]	Oct. 02, 2012 HCIDA Pollution Control Revenue Refunding Bonds [Member] Five Point Five Percentage Refunding Bonds [Member] Tampa Electric Company [Member] 2023 [Member]	Mar. 01, 2011 PCIDA Bonds [Member]	Mar. 01, 2011 PCIDA Bonds [Member] Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount		$ 2,921,100,000	$ 2,972,700,000
Estimated fair value		3,184,100,000	3,442,200,000
Ownership of parent company		100.00%
Purchase in lieu of redemption	75,000,000	51,600,000	650,400,000	153,600,000	75,000,000		51,600,000	608,000,000	78,800,000		25,300,000				86,000,000	20,000,000	51,600,000			232,600,000	86,000,000	20,000,000	51,600,000						232,600,000	60,700,000	86,400,000
Interest at the initial term rate per annum													2.60%	4.10%				5.00%	5.15%					5.00%	5.15%		5.10%	5.50%				1.50%	1.50%
Principal amounts of notes redeemed										147,100,000		8,800,000
Redemption price of notes												1,141,860,000
Aggregate principal amount issued												1,000,000,000	250,000,000	300,000,000
Loss on debt extinguishment		0	(1,200,000)	0								1,200,000
Redeemable principal amount percentage																										100.00%
Issuance of notes, maturity year													Jan. 01, 2022	Jan. 01, 2042
Debt Instrument Principal amount Market Price Percentage													99.878%	99.724%
Proceeds from notes net of issuance													$ 247,700,000	$ 296,200,000
Libor interest rate						15								25

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Employee Postretirement Benefits - Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 32.7	$ 52.7
Prior service cost (credit)	0.4	0.4
Amount recognized	33.1	53.1
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	(23.8)	(17.2)
Prior service cost (credit)	(0.4)	(0.7)
Amount recognized	$ (24.2)	$ (17.9)

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Employee Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Primary provisions for pension benefits	First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%.
Percentage of qualified pension plan's actuarial value of assets		96.70%
Estimated percentage of qualified pension plan's actuarial value of assets	98.20%
Percentage of tax-free subsidy under prescription drug programs	28.00%
Amortization period of Regulatory Asset	12 years
Tax of premiums paid for retiree medical benefits plan	40.00%
Accumulated benefit obligation of defined benefit pension plans	$ 624.1	$ 664.7
Percentage of defined benefit plan actual return on plan assets	12.00%
Employer contributions	42.0	35.5
Employer contributions in next fiscal year	47.5
Defined contribution plan, maximum employer match percentage	6.00%
Description of defined contribution plan	Employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%.
Defined contribution plan cost recognized	11.3	7.0	9.0
Employer matching contribution percentage of eligible participant contribution	60.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	40.00%
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of qualified pension plan's actuarial value of assets		96.70%
Estimated percentage of qualified pension plan's actuarial value of assets	98.20%
Percentage of tax-free subsidy under prescription drug programs	28.00%
Tax of premiums paid for retiree medical benefits plan	40.00%
Employer contributions	33.5	27.9
Employer contributions in next fiscal year	38.4
Defined contribution plan cost recognized	9.1	6.0	5.8
TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of defined benefit plan actual return on plan assets	12.00%
TECO Coal [Member]
Defined Benefit Plan Disclosure [Line Items]
Black lung liability	24.5	27.1
Expenses related to black lung liability	2.2	1.8	1.7
Pre Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution	60.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	40.00%
Post Amendment [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution percentage of eligible participant contribution	65.00%
Defined benefit plan additional percentage of eligible compensation for matching contributions by employer	35.00%
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	4.0
Minimum [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	3.0
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	48.0
Maximum [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Range of estimated annual contributions	39.0
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	666.0	715.0	646.4
Estimated net loss amortization from AOCI into net periodic benefit cost related to defined benefit plan	2.5
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.1
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	10.5
Defined benefit plan prior service benefit that will be amortized from regulatory assets in next fiscal year	0.5
Employer contributions	45.9	36.8
Net periodic benefit cost	29.8	24.9	20.3
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan net loss that will be amortized from regulatory assets in next fiscal year	10.5
Defined benefit plan prior service benefit that will be amortized from regulatory assets in next fiscal year	0.5
Net periodic benefit cost	21.7	18.3	13.1
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	666.0	715.0	646.4
Employer contributions	45.9	36.8
Net periodic benefit cost	29.8	24.9	20.3
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	208.1	230.3	216.5
Estimated Prior service cost amortization from AOCI into net periodic benefit cost related to defined benefit plan	0.2
Other postretirement benefit plans, Net loss that will be amortized from regulatory assets in next fiscal year	0
Employer contributions	11.9	9.8
Employer contributions in next fiscal year	13.3
Net periodic benefit cost	12.4	15.2	16.4
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit plans, Net loss that will be amortized from regulatory assets in next fiscal year	0
Employer contributions in next fiscal year	10.8
Net periodic benefit cost	10.0	12.4	10.0
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation for other postretirement benefits	208.1	230.3	216.5
Employer contributions	11.9	9.8
Net periodic benefit cost	12.4	15.2	16.4
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	2.6	1.3
Employer contributions in next fiscal year	3.3
SERP [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	1.0	0.6
Employer contributions in next fiscal year	$ 0.9

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Related Parties

12 Months Ended

Dec. 31, 2013

Related Parties

13. Related Parties

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million, $1.3 million and $1.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively, to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2013, 2012 and 2011. No material balances were payable as of Dec. 31, 2013 or 2012.

Tampa Electric Company [Member]

Related Parties

10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:
(millions)	2013		2012		2011
Natural gas sales, net	$	18.3	$	11.7	$	0.0
Administrative and general, net	$	27.2	$	23.4	$	17.5

Amounts due from or to affiliates at Dec. 31,
(millions)	2013		2012
Accounts receivable (1)	$	1.3	$	4.7
Accounts payable (1)		9.8		7.9
Taxes receivable		54.9		22.1
Taxes payable		0.4		3.2

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

TEC had certain transactions, in the ordinary course of business, with entities in which directors of TEC had interests. TEC paid legal fees of $1.7 million, $1.2 million and $1.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively, to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Asset Retirement Obligations

Reconciliation of beginning and ending carrying amount of asset retirement obligations:
	Dec. 31,
(millions)	2013			2012
Beginning balance	$	28.6		$	53.8
Additional liabilities		0.1			0.7
Liabilities settled		(1.4	)		(29.1	)
Accretion expense		1.4			1.4
Revisions to estimated cash flows		(0.3	)		0.0
Other (1)		0.2			1.8
Ending balance	$	28.6		$	28.6

(1) Accretion recorded as a deferred regulatory asset.

Tampa Electric Company [Member]

Schedule of Asset Retirement Obligations

Reconciliation of beginning and ending carrying amount of asset retirement obligations:
	Dec. 31,
(millions)	2013			2012
Beginning balance	$	5.0		$	30.8
Additional liabilities		0.1			0.0
Liabilities settled		(0.2	)		(27.6	)
Revisions to estimated cash flows		(0.3	)		0.0
Other (1)		0.2			1.8
Ending balance	$	4.8		$	5.0

(1) Accretion recorded as a deferred regulatory asset.

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Employee Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Change in Benefit Obligation

Obligations and Funded Status	Pension Benefits						Other Benefits
(millions)	2013			2012			2013			2012
Change in benefit obligation
Net benefit obligation at beginning of year	$	715.0		$	646.4		$	230.3		$	216.5
Service cost		18.2			17.0			2.5			2.4
Interest cost		28.9			30.1			9.3			10.1
Plan participants’ contributions		0.0			0.0			2.9			3.7
Plan amendments		0.0			0.0			0.0			(5.2	)
Actuarial loss (gain)		(50.4	)		54.7			(22.1	)		16.3
Gross benefits paid		(43.1	)		(33.2	)		(15.0	)		(14.5	)
Settlements		(2.6	)		0.0			0.0			0.0
Federal subsidy on benefits paid		n/a			n/a			0.2			1.0
Net benefit obligation at end of year	$	666.0		$	715.0		$	208.1		$	230.3

Schedule of Change in Plan Assets

Change in plan assets
Fair value of plan assets at beginning of year	$	529.1		$	467.6		$	0.0		$	0.0
Actual return on plan assets		63.7			57.9			0.0			0.0
Employer contributions		45.9			36.8			11.9			9.8
Plan participants’ contributions		0.0			0.0			2.9			3.7
Settlements		(2.6	)		0.0			0.0			0.0
Net benefits paid		(43.1	)		(33.2	)		(14.8	)		(13.5	)
Fair value of plan assets at end of year	$	593.0		$	529.1		$	0.0		$	0.0

Schedule of Funded status

Funded status
Fair value of plan assets (1)	$	593.0		$	529.1		$	0.0		$	0.0
Less: Benefit obligation (PBO/APBO)		666.0			715.0			208.1			230.3
Funded status at end of year		(73.0	)		(185.9	)		(208.1	)		(230.3	)
Unrecognized net actuarial loss		173.1			270.3			19.7			42.7
Unrecognized prior service (benefit) cost		(0.4	)		(0.7	)		(0.7	)		(1.0	)
Net amount required to be recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

Schedule of Amount Recognized in Balance Sheet

Amounts recognized in balance sheet
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(3.3	)		(5.3	)		(13.3	)		(13.1	)
Deferred credits and other liabilities		(69.7	)		(180.6	)		(194.8	)		(217.2	)
Accumulated other comprehensive loss (income), pretax		33.1			53.1			(24.2	)		(17.9	)
Net amount recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

Schedule of Postretirement Benefit Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income

	Pension Benefits				Other Benefits
(millions)	2013		2012		2013			2012
Net actuarial loss (gain)	$	32.7	$	52.7	$	(23.8	)	$	(17.2	)
Prior service cost (credit)		0.4		0.4		(0.4	)		(0.7	)
Amount recognized	$	33.1	$	53.1	$	(24.2	)	$	(17.9	)

Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets

The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

	Pension Benefits									Other Benefits
Net periodic benefit cost
(millions)	2013			2012			2011			2013			2012			2011
Service cost	$	18.2		$	17.0		$	16.0		$	2.4		$	2.4		$	2.1
Interest cost		28.9			30.1			30.9			9.3			10.1			11.1
Expected return on plan assets		(38.4	)		(37.1	)		(38.4	)		0.0			0.0			0.0
Amortization of:
Actuarial loss		20.5			15.3			11.3			1.0			0.1			0.1
Prior service (benefit) cost		(0.4	)		(0.4	)		(0.4	)		(0.3	)		0.8			0.8
Transition obligation		0.0			0.0			0.0			0.0			1.8			2.3
Settlement loss		1.0			0.0			0.9			0.0			0.0			0.0
Net periodic benefit cost	$	29.8		$	24.9		$	20.3		$	12.4		$	15.2		$	16.4
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and regulatory assets
(millions)	2013			2012			2011			2013			2012			2011
Prior service cost	$	0.0		$	0.0		$	0.0		$	0.0		$	(5.2	)	$	0.0
Net loss (gain)		(75.7	)		34.0			43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)		(21.5	)		(15.3	)	$	(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost		0.4			0.4			0.4			0.3			(0.8	)		(0.8	)
Transition obligation		0.0			0.0			0.0			0.0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets	$	(96.8	)	$	19.1		$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(67.0	)	$	44.0		$	51.8		$	(3.9	)	$	23.6		$	5.7

Schedule of Pension Plan Assets

The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target Allocation	Actual Allocation, End of Year
Asset Category		2013			2012
Equity securities	48%-54%		54	%		55	%
Fixed income securities	46%-52%		46	%		45	%
Total	100%		100	%		100	%

Schedule of Fair Value Hierarchy Plan's Investments

The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and Dec. 31, 2012.

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2013
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	44.7		$	0.0		$	0.0	$	44.7
Accounts payable		(40.8	)		0.0			0.0		(40.8	)
Cash equivalents
Short term investment funds (STIFs)		7.9			0.0			0.0		7.9
Treasury bills (T bills)		0.0			0.3			0.0		0.3
Repurchase agreement		0.0			8.8			0.0		8.8
Commercial paper		0.0			0.4			0.0		0.4
Money markets		0.0			1.5			0.0		1.5
Total cash equivalents		7.9			11.0			0.0		18.9
Equity securities
Common stocks		91.6			0.0			0.0		91.6
American depository receipts (ADRs)		3.0			0.0			0.0		3.0
Real estate investment trusts (REITs)		1.7			0.0			0.0		1.7
Preferred stock		0.0			0.8			0.0		0.8
Mutual funds		172.6			0.0			0.0		172.6
Commingled fund		0.0			50.0			0.0		50.0
Total equity securities		268.9			50.8			0.0		319.7
Fixed income securities
Municipal bonds		0.0			7.3			0.0		7.3
Government bonds		0.0			35.7			0.0		35.7
Corporate bonds		0.0			19.6			0.0		19.6
Asset backed securities (ABS)		0.0			0.4			0.0		0.4
Mortgage-backed securities (MBS), net short sales		0.0			6.7			0.0		6.7
Collateralized mortgage obligations (CMOs)		0.0			2.3			0.0		2.3
Mutual fund		0.0			85.1			0.0		85.1
Commingled fund		0.0			94.1			0.0		94.1
Total fixed income securities		0.0			251.2			0.0		251.2
Derivatives
Short futures		0.0			0.2			0.0		0.2
Swaps		0.0			(0.9	)		0.0		(0.9	)
Purchased options (swaptions)		0.0			0.2			0.0		0.2
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.9	)		0.0		(0.9	)
Miscellaneous		0.0			0.2			0.0		0.2
Total	$	280.7		$	312.3		$	0.0	$	593.0

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2012
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	64.8		$	0.0		$	0.0	$	64.8
Accounts payable		(72.8	)		0.0			0.0		(72.8	)
Cash equivalents
STIFs		9.0			0.0			0.0		9.0
T bills		0.0			0.6			0.0		0.6
Repurchase agreements		0.0			23.1			0.0		23.1
CDs		0.0			1.1			0.0		1.1
Commercial paper		0.0			0.9			0.0		0.9
Money markets		0.0			0.6			0.0		0.6
Total cash equivalents		9.0			26.3			0.0		35.3
Equity securities
Common stocks		125.3			0.0			0.0		125.3
ADRs		6.2			0.0			0.0		6.2
REITs		2.0			0.0			0.0		2.0
Preferred stocks		0.0			0.8			0.0		0.8
Equity mutual funds		153.4			0.0			0.0		153.4
Total equity securities		286.9			0.8			0.0		287.7
Fixed income securities
Municipal bonds		0.0			8.0			0.0		8.0
Government bonds		0.0			53.0			0.0		53.0
Corporate bonds		0.0			19.8			0.0		19.8
ABS		0.0			0.5			0.0		0.5
MBS		0.0			17.6			0.0		17.6
CMBS		0.0			0.3			0.0		0.3
CMOs		0.0			2.5			0.0		2.5
Fixed income mutual fund		0.0			63.7			0.0		63.7
Fixed income commingled fund		0.0			49.4			0.0		49.4
Total fixed income securities		0.0			214.8			0.0		214.8
Derivatives
Swaps		0.0			(0.5	)		0.0		(0.5	)
Purchased options (swaptions)		0.0			0.1			0.0		0.1
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.8	)		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.1
Total	$	287.9		$	241.2		$	0.0	$	529.1

• The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.

• The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.

• The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.

• The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.

• T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.

• The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.

• The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.

• The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.

• The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

Schedule of Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments
(including projected service and net of employee contributions)
(millions)	Pension Benefits		Other Postretirement Benefits
2014	$	53.5	$	13.3
2015		50.9		13.9
2016		55.3		14.6
2017		55.9		15.2
2018		58.3		15.7
2019-2023		298.6		81.9

Benefit Obligations [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2013			2012			2013			2012
Discount rate		5.118	%		4.196	%		5.096	%		4.180	%
Rate of compensation increase - weighted		3.73	%		3.76	%		3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			7.25	%		7.50	%
Ultimate rate		n/a			n/a			4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			2025			2025

Schedule of One-Percentage-Point Change in Assumed Health Care Cost

A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:

(millions)	1% Increase		1% Decrease
Effect on postretirement benefit obligation	$	6.8	$	(6.1	)

Net Periodic Benefit Cost [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Discount rate		4.196	%		4.797	%		5.300	%		4.180	%		4.744	%		5.250	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.75	%		n/a			n/a			n/a
Rate of compensation increase		3.76	%		3.83	%		3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Initial rate		n/a			n/a			n/a			7.50	%		7.75	%		8.00	%
Ultimate rate		n/a			n/a			n/a			4.50	%		4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			n/a			2025			2025			2023

Schedule of One-Percentage-Point Change in Assumed Health Care Cost

A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:

(millions)	1% Increase		1% Decrease
Effect on periodic cost	$	0.3	$	(0.3	)

Tampa Electric Company [Member]

Schedule of Amount Recognized in Balance Sheet

Tampa Electric Company	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2013			2012			2013			2012
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(0.9	)		(0.9	)		(10.8	)		(10.6	)
Deferred credits and other liabilities		(50.1	)		(139.8	)		(158.3	)		(174.2	)
	$	88.6		$	75.8		$	(125.9	)	$	(125.2	)

Tampa Electric Company [Member] | Benefit Obligations [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2013			2012			2013			2012
Discount rate		5.118	%		4.196	%		5.096	%		4.180	%
Rate of compensation increase-weighted average		3.73	%		3.76	%		3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			7.25	%		7.50	%
Ultimate rate		n/a			n/a			4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			2025			2025

Schedule of One-Percentage-Point Change in Assumed Health Care Cost

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:

(millions)	1% Increase		1% Decrease
Effect on postretirement benefit obligation	$	5.6	$	(5.0	)

Tampa Electric Company [Member] | Net Periodic Benefit Cost [Member]

Schedule of Assumptions Used to Determine Benefit

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Discount rate		4.196	%		4.797	%		5.30	%		4.180	%		4.744	%		5.25	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.75	%		n/a			n/a			n/a
Rate of compensation increase		3.76	%		3.83	%		3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			n/a			7.50	%		7.75	%		8.00	%
Ultimate rate		n/a			n/a			n/a			4.50	%		4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			n/a			2025			2025			2023

Tampa Electric Company [Member] | Effect on Expenses [Member]

Schedule of One-Percentage-Point Change in Assumed Health Care Cost

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:

(millions)	1% Increase		1% Decrease
Effect on periodic cost	$	0.2	$	(0.2	)

TECO Energy [Member]

Schedule of Change in Benefit Obligation

TECO Energy	Pension Benefits						Other Benefits
Obligations and Funded Status
(millions)	2013			2012			2013			2012
Change in benefit obligation
Net benefit obligation at beginning of year	$	715.0		$	646.4		$	230.3		$	216.5
Service cost		18.2			17.0			2.5			2.4
Interest cost		28.9			30.1			9.3			10.1
Plan participants’ contributions		0.0			0.0			2.9			3.7
Plan amendments		0.0			0.0			0.0			(5.2	)
Actuarial loss (gain)		(50.4	)		54.7			(22.1	)		16.3
Gross benefits paid		(43.1	)		(33.2	)		(15.0	)		(14.5	)
Settlements		(2.6	)		0.0			0.0			0.0
Federal subsidy on benefits paid		n/a			n/a			0.2			1.0
Net benefit obligation at end of year	$	666.0		$	715.0		$	208.1		$	230.3

Schedule of Change in Plan Assets

Change in plan assets
Fair value of plan assets at beginning of year	$	529.1		$	467.6		$	0.0		$	0.0
Actual return on plan assets		63.7			57.9			0.0			0.0
Employer contributions		45.9			36.8			11.9			9.8
Plan participants’ contributions		0.0			0.0			2.9			3.7
Settlements		(2.6	)		0.0			0.0			0.0
Gross benefits paid		(43.1	)		(33.2	)		(14.8	)		(13.5	)
Fair value of plan assets at end of year	$	593.0		$	529.1		$	0.0		$	0.0

Schedule of Funded status

Funded status
Fair value of plan assets (1)	$	593.0		$	529.1		$	0.0		$	0.0
Less: Benefit obligation (PBO/APBO)		666.0			715.0			208.1			230.3
Funded status at end of year		(73.0	)		(185.9	)		(208.1	)		(230.3	)
Unrecognized net actuarial loss		173.1			270.3			19.7			42.7
Unrecognized prior service (benefit) cost		(0.4	)		(0.7	)		(0.7	)		(1.0	)
Unrecognized net transition obligation		0.0			0.0			0.0			0.0
Net amount required to be recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

Schedule of Amount Recognized in Balance Sheet

Amounts recognized in balance sheet
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(3.3	)		(5.3	)		(13.3	)		(13.1	)
Deferred credits and other liabilities		(69.7	)		(180.6	)		(194.8	)		(217.2	)
Accumulated other comprehensive loss (income), pretax		33.1			53.1			(24.2	)		(17.9	)
Net amount recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

TECO Energy [Member]

Schedule of Pension Plan Assets

TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target Allocation	Actual Allocation, End of Year
Asset Category		2013			2012
Equity securities	48%-54%		54	%		55	%
Fixed income securities	46%-52%		46	%		45	%
Total	100%		100	%		100	%

Schedule of Fair Value Hierarchy Plan's Investments

The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and 2012.

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2013
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	44.7		$	0.0		$	0.0	$	44.7
Accounts payable		(40.8	)		0.0			0.0		(40.8	)
Cash equivalents
STIFs		7.9			0.0			0.0		7.9
T bills		0.0			0.3			0.0		0.3
Repurchase agreements		0.0			8.8			0.0		8.8
Commercial paper		0.0			0.4			0.0		0.4
Money markets		0.0			1.5			0.0		1.5
Total cash equivalents		7.9			11.0			0.0		18.9
Equity securities
Common stocks		91.6			0.0			0.0		91.6
ADRs		3.0			0.0			0.0		3.0
REITs		1.7			0.0			0.0		1.7
Preferred stock		0.0			0.8			0.0		0.8
Mutual funds		172.6			0.0			0.0		172.6
Commingled fund		0.0			50.0			0.0		50.0
Total equity securities		268.9			50.8			0.0		319.7
Fixed income securities
Municipal bonds		0.0			7.3			0.0		7.3
Government bonds		0.0			35.7			0.0		35.7
Corporate bonds		0.0			19.6			0.0		19.6
ABS		0.0			0.4			0.0		0.4
MBS, net short sales		0.0			6.7			0.0		6.7
CMOs		0.0			2.3			0.0		2.3
Mutual funds		0.0			85.1			0.0		85.1
Commingled fund		0.0			94.1			0.0		94.1
Total fixed income securities		0.0			251.2			0.0		251.2
Derivatives
Short futures		0.0			0.2			0.0		0.2
Swaps		0.0			(0.9	)		0.0		(0.9	)
Purchased options (swaptions)		0.0			0.2			0.0		0.2
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.9	)		0.0		(0.9	)
Miscellaneous		0.0			0.2			0.0		0.2
Total	$	280.7		$	312.3		$	0.0	$	593.0

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2012
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	64.8		$	0.0		$	0.0	$	64.8
Accounts payable		(72.8	)		0.0			0.0		(72.8	)
Cash equivalents
STIFs		9.0			0.0			0.0		9.0
T bills		0.0			0.6			0.0		0.6
Repurchase agreements		0.0			23.1			0.0		23.1
CDs		0.0			1.1			0.0		1.1
Commercial paper		0.0			0.9			0.0		0.9
Money markets		0.0			0.6			0.0		0.6
Total cash equivalents		9.0			26.3			0.0		35.3
Equity securities
Common stocks		125.3			0.0			0.0		125.3
ADRs		6.2			0.0			0.0		6.2
REITs		2.0			0.0			0.0		2.0
Preferred stocks		0.0			0.8			0.0		0.8
Equity mutual funds		153.4			0.0			0.0		153.4
Total equity securities		286.9			0.8			0.0		287.7
Fixed income securities
Municipal bonds		0.0			8.0			0.0		8.0
Government bonds		0.0			53.0			0.0		53.0
Corporate bonds		0.0			19.8			0.0		19.8
ABS		0.0			0.5			0.0		0.5
MBS		0.0			17.6			0.0		17.6
CMBS		0.0			0.3			0.0		0.3
CMOs		0.0			2.5			0.0		2.5
Fixed income mutual fund		0.0			63.7			0.0		63.7
Fixed income commingled fund		0.0			49.4			0.0		49.4
Total fixed income securities		0.0			214.8			0.0		214.8
Derivatives
Swaps		0.0			(0.5	)		0.0		(0.5	)
Purchased options (swaptions)		0.0			0.1			0.0		0.1
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.8	)		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.1
Total	$	287.9		$	241.2		$	0.0	$	529.1

• The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.

• The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.

• The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.

• The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.

• T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.

• The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.

• The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.

• The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.

• The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

Schedule of Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments - TECO Energy
(including projected service and net of employee contributions)			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2014	$	53.5	$	13.3
2015		50.9		13.9
2016		55.3		14.6
2017		55.9		15.2
2018		58.3		15.7
2019-2023		298.6		81.9

Schedule of Net Periodic Benefit Cost

Components of TECO Energy Consolidated Net Periodic Benefit Cost

	Pension Benefits									Other Benefits
(millions)	2013			2012			2011			2013			2012		2011
Service cost	$	18.2		$	17.0		$	16.0		$	2.4		$	2.4	$	2.1
Interest cost		28.9			30.1			30.9			9.3			10.1		11.1
Expected return on plan assets		(38.4	)		(37.1	)		(38.4	)		0.0			0.0		0.0
Amortization of:
Actuarial loss		20.5			15.3			11.3			1.0			0.1		0.1
Prior service (benefit) cost		(0.4	)		(0.4	)		(0.4	)		(0.3	)		0.8		0.8
Transition obligation		0.0			0.0			0.0			0.0			1.8		2.3
Settlement loss		1.0			0.0			0.9			0.0			0.0		0.0
Net periodic benefit cost	$	29.8		$	24.9		$	20.3		$	12.4		$	15.2	$	16.4

Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets

(millions)	2013			2012			2011			2013			2012			2011
Prior service cost	$	0.0		$	0.0		$	0.0		$	0.0		$	(5.2	)	$	0.0
Net loss (gain)		(75.7	)		34.0			43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)		(21.5	)		(15.3	)		(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost		0.4			0.4			0.4			0.3			(0.8	)		(0.8	)
Transition obligation		0.0			0.0			0.0			0.0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets	$	(96.8	)	$	19.1		$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total Recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets	$	(67.0	)	$	44.0		$	51.8		$	(3.9	)	$	23.6		$	5.7

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Employee Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 139.6	$ 216.5
Accrued benefit costs and other current liabilities	(3.3)	(5.3)
Deferred credits and other liabilities	(69.7)	(180.6)
Accumulated other comprehensive loss (income), pretax	33.1	53.1
Net amount recognized at end of year	99.7	83.7
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	(13.3)	(13.1)
Deferred credits and other liabilities	(194.8)	(217.2)
Accumulated other comprehensive loss (income), pretax	(24.2)	(17.9)
Net amount recognized at end of year	(189.1)	(188.6)
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	139.6	216.5
Accrued benefit costs and other current liabilities	(3.3)	(5.3)
Deferred credits and other liabilities	(69.7)	(180.6)
Accumulated other comprehensive loss (income), pretax	33.1	53.1
Net amount recognized at end of year	99.7	83.7
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	(13.3)	(13.1)
Deferred credits and other liabilities	(194.8)	(217.2)
Accumulated other comprehensive loss (income), pretax	(24.2)	(17.9)
Net amount recognized at end of year	$ (189.1)	$ (188.6)

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Common Stock - Summary of Stock Option Transactions (Detail) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Schedule Of Stock Options [Line Items]
Outstanding balance at Dec. 31, 2013, Number of Shares	1,567
Outstanding balance at Dec. 31, 2013, Weighted Avg. Option Price (per share)	$ 15.62
Outstanding balance at Dec. 31, 2013, Weighted Avg. Remaining Contractual Term	2 years
Stock Options [Member]
Schedule Of Stock Options [Line Items]
Outstanding balance at Dec. 31, 2012, Number of Shares	2,087
Outstanding balance, Number of Shares	0
Exercised, Number of Shares	(507)
Cancelled, Number of Shares	(13)
Outstanding balance at Dec. 31, 2013, Number of Shares	1,567
Exercisable at Dec. 31, 2013, Number of Shares	1,567
Available for future grant at Dec. 31, 2013, Number of Shares	2,725
Outstanding balance at Dec. 31, 2012, Weighted Avg. Option Price (per share)	$ 15.05
Granted, Weighted Avg. Option Price	$ 0.00
Exercised, Weighted Avg. Option Price	$ 13.22
Cancelled, Weighted Avg. Option Price	$ 18.87
Outstanding balance at Dec. 31, 2013, Weighted Avg. Option Price (per share)	$ 15.62
Exercisable at Dec. 31, 2013, Weighted Avg. Option Price	$ 15.62
Outstanding balance at Dec. 31, 2013, Weighted Avg. Remaining Contractual Term	2 years
Exercisable at Dec. 31, 2013, Weighted Avg. Remaining Contractual Term	2 years
Outstanding balance at Dec. 31, 2013, Aggregate Intrinsic Value	$ 2.6
Exercisable at Dec. 31, 2013, Aggregate Intrinsic Value	$ 2.6

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Schedule II - Valuation and Qualifying Accounts and Reserves

12 Months Ended

Dec. 31, 2013

Valuation And Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts and Reserves

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TECO ENERGY, INC.

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended Dec. 31, 2013, 2012 and 2011

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions (1)		Period
Allowance for Uncollectible Accounts:
2013	$	4.2	$	3.3	$	0.0	$	2.8	$	4.7
2012	$	2.6	$	4.8	$	0.0	$	3.2	$	4.2
2011	$	4.5	$	3.8	$	0.0	$	5.7	$	2.6

(1) Write-off of individual bad debt accounts

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

TAMPA ELECTRIC COMPANY

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

For the Years Ended Dec. 31, 2013, 2012 and 2011

(millions)

	Balance at		Additions						Balance at
	Beginning		Charged to		Other		Payments &		End of
	of Period		Income		Charges		Deductions (1)		Period
Allowance for Uncollectible Accounts:
2013	$	1.5	$	3.3	$	0.0	$	2.8	$	2.0
2012	$	1.3	$	3.4	$	0.0	$	3.2	$	1.5
2011	$	3.2	$	3.8	$	0.0	$	5.7	$	1.3

(1) Write-off of individual bad debt accounts

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Recurring Fair Value Measurements

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

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

Tampa Electric Company [Member]

Schedule of Recurring Fair Value Measurements

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

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

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Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Statutory tax rate	35.00%	35.00%	35.00%
Tampa Electric Company [Member]
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Statutory tax rate	35.00%	35.00%	35.00%

XML

Segment Information - Additional Information (Detail)	Dec. 31, 2013 Customer
Tampa Electric [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	700,000
Tampa Electric [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Number of retail electric utility service customers in West Central Florida	700,000
PGS [Member] | Minimum [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	350,000
PGS [Member] | Minimum [Member] | Tampa Electric Company [Member]
Segment Reporting Information [Line Items]
Number of residential, commercial, industrial and power generation customers for natural gas purchase and distribution	350,000

XML

Regulatory - Schedule of Regulatory Assets and Regulatory Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory assets:
Regulatory assets	$ 327.4	$ 452.9
Less: Current portion	34.3	70.3
Long-term regulatory assets	293.1	382.6
Regulatory liabilities:
Less: Current portion	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Tampa Electric Company [Member]
Regulatory assets:
Regulatory assets	327.4	452.9
Less: Current portion	34.3	70.3
Long-term regulatory assets	293.1	382.6
Regulatory liabilities:
Regulatory liabilities	717.2	737.0
Less: Current portion	85.8	105.6
Long-term regulatory liabilities	631.4	631.4
Tampa Electric Company [Member] | Regulatory Tax Asset [Member]
Regulatory liabilities:
Regulatory liabilities	9.8	14.6
Tampa Electric Company [Member] | Cost-Recovery Clauses [Member]
Regulatory liabilities:
Regulatory liabilities	54.5	73.9
Tampa Electric Company [Member] | Transmission and Delivery Storm Reserve [Member]
Regulatory liabilities:
Regulatory liabilities	56.1	50.4
Tampa Electric Company [Member] | Deferred Gain on Property Sales [Member]
Regulatory liabilities:
Regulatory liabilities	2.0	3.4
Tampa Electric Company [Member] | Provision for Stipulation and Other [Member]
Regulatory liabilities:
Regulatory liabilities	0.8	1.0
Tampa Electric Company [Member] | Accumulated Reserve - Cost of Removal [Member]
Regulatory liabilities:
Regulatory liabilities	594.0	593.7
Tampa Electric Company [Member] | Total Other Regulatory Liabilities [Member]
Regulatory liabilities:
Regulatory liabilities	707.4	722.4
Tampa Electric Company [Member] | Regulatory Tax Asset [Member]
Regulatory assets:
Regulatory assets	67.4	67.2
Tampa Electric Company [Member] | Cost-Recovery Clauses [Member]
Regulatory assets:
Regulatory assets	6.1	42.9
Tampa Electric Company [Member] | Postretirement Benefit Costs [Member]
Regulatory assets:
Regulatory assets	182.7	276.1
Tampa Electric Company [Member] | Deferred Bond Refinancing Costs [Member]
Regulatory assets:
Regulatory assets	8.0	9.2
Tampa Electric Company [Member] | Environmental Remediation [Member]
Regulatory assets:
Regulatory assets	51.4	46.9
Tampa Electric Company [Member] | Competitive Rate Adjustment [Member]
Regulatory assets:
Regulatory assets	4.1	4.1
Tampa Electric Company [Member] | Other [Member]
Regulatory assets:
Regulatory assets	7.7	6.5
Tampa Electric Company [Member] | Total Other Regulatory Assets [Member]
Regulatory assets:
Regulatory assets	$ 260.0	$ 385.7

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share

(millions, except per share amounts)	2013			2012			2011 (1)
Basic earnings per share
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Amount allocated to nonvested participating shareholders		(0.6	)		(0.8	)		(1.3	)
Income before discontinued operations available to common shareholders - Basic	$	197.2		$	245.2		$	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
Amount allocated to nonvested participating shareholders		0.0			0.1			(0.1	)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic	($	0.1	)	($	33.2	)	$	21.7
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Amount allocated to nonvested participating shareholders		(0.6	)		(0.7	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	197.1		$	212.0		$	271.2
Average common shares outstanding - Basic		215.0			214.3			213.6
Earnings per share from continuing operations available to common shareholders - Basic	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.92		$	0.99		$	1.27
Diluted earnings per share
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Amount allocated to nonvested participating shareholders		(0.6	)		(0.8	)		(1.3	)
Income before discontinued operations available to common shareholders - Diluted	$	197.2		$	245.2		$	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
Amount allocated to nonvested participating shareholders		0.0			0.1			(0.1	)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	($	0.1	)	($	33.2	)	$	21.7
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Amount allocated to nonvested participating shareholders		(0.6	)		(0.7	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	197.1		$	212.0		$	271.2
Unadjusted average common shares outstanding - Diluted		215.0			214.3			213.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.7			1.5
Average common shares outstanding - Diluted		215.5			215.0			215.1
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.92		$	0.99		$	1.27
Anti-dilutive shares		0.0			0.4			1.7

(1) All prior periods presented reflect the classification of TECO Guatemala as discontinued operations (see Note 19).

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Consolidated Statements of Capital (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement Of Stockholders Equity [Abstract]
Common equity, shares authorized	400.0	400.0	400.0	400.0
Common equity, par value	$ 1	$ 1	$ 1	$ 1

XML

Employee Postretirement Benefits - Schedule of Amount Recognized in Balance Sheet (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 139.6	$ 216.5
Accrued benefit costs and other current liabilities	(3.3)	(5.3)
Deferred credits and other liabilities	(69.7)	(180.6)
Net amount recognized at end of year	99.7	83.7
Pension Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	139.6	216.5
Accrued benefit costs and other current liabilities	(0.9)	(0.9)
Deferred credits and other liabilities	(50.1)	(139.8)
Net amount recognized at end of year	88.6	75.8
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	(13.3)	(13.1)
Deferred credits and other liabilities	(194.8)	(217.2)
Net amount recognized at end of year	(189.1)	(188.6)
Other Postretirement Benefits [Member] | Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	43.2	59.6
Accrued benefit costs and other current liabilities	(10.8)	(10.6)
Deferred credits and other liabilities	(158.3)	(174.2)
Net amount recognized at end of year	$ (125.9)	$ (125.2)

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Accounting for Derivative Instruments and Hedging Activities - Gross Amounts of Derivatives and Their Related Offset Amounts (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	$ 10.5	$ 1.0
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	(0.8)	(16.0)
Derivative assets, Gross Amounts offset on the Balance Sheet	(0.5)	(0.8)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	0.5	0.8
Derivative assets, Net Amounts of Assets	10.0	0.2
Derivative assets, Net Amounts of Liabilities	(0.3)	(15.2)
Tampa Electric Company [Member]
Derivative [Line Items]
Derivative assets, Gross Amounts of Recognized Assets	10.3	1.0
Derivative liabilities, Gross Amounts of Recognized (Liabilities)	(0.7)	(15.1)
Derivative assets, Gross Amounts offset on the Balance Sheet	(0.5)	(0.8)
Derivative liabilities, Gross Amounts offset on the Balance Sheet	0.5	0.8
Derivative assets, Net Amounts of Assets	9.8	0.2
Derivative assets, Net Amounts of Liabilities	$ (0.2)	$ (14.3)

XML

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

XML

Goodwill and Asset Impairments - Changes in Carrying Amount of Goodwill (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Goodwill [Line Items]
Beginning Balance	$ 55.4
Impairment losses, pretax	(15.2)
Goodwill written off upon sale, pretax	(40.2)
Ending Balance	0
TPS GO [Member]
Goodwill [Line Items]
Beginning Balance	3.1
Impairment losses, pretax	(3.1)
Goodwill written off upon sale, pretax	0
Ending Balance	0
TPS SJI [Member]
Goodwill [Line Items]
Beginning Balance	52.3
Impairment losses, pretax	(12.1)
Goodwill written off upon sale, pretax	(40.2)
Ending Balance	$ 0

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Consolidated Statements of Capitalization - Long-Term Debt (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term debt, total	$ 2,923.8	$ 2,975.4
Long-term debt, carrying amount	2,921.1	2,972.7
Unamortized debt discount, net	(2.7)	(2.7)
Less amount due within one year	83.3	0
Total long-term debt	2,837.8	2,972.7
Long-Term Debt [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,880.8	1,932.6
Long-term debt, carrying amount	1,882.6	1,934.2
Total long-term debt	1,797.5	1,932.6
PGS [Member]
Debt Instrument [Line Items]
Long-term debt, total	231.7
PGS [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Long-term debt, total	231.7	231.7
6.1% Notes [Member] | PGS [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	50.0	50.0
5.4% Notes [Member] | PGS [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	46.7	46.7
2.6% Notes [Member] | PGS [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	25.0	25.0
6.15% Notes [Member] | PGS [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	60.0	60.0
4.1% Notes [Member]
Debt Instrument [Line Items]
Due	2042
4.1% Notes [Member] | PGS [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	50.0	50.0
Tampa Electric Company [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,650.9	1,702.5
Less amount due within one year	83.3	0
Total long-term debt	1,797.5	1,932.6
Tampa Electric Company [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Long-term debt, total	1,650.9	1,702.5
Unamortized debt discount, net	(1.8)	(1.6)
Less amount due within one year	83.3	0
Long-term debt, fair value	2,042.0	2,271.9
Tampa Electric Company [Member] | Long-Term Debt [Member] | Carrying Amount [Member]
Debt Instrument [Line Items]
Long-term debt, carrying amount	1,880.8	1,932.6
Tampa Electric Company [Member] | Variable rate bonds repurchased in 2008 Due To 2020 [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2020
Long-term debt, total	0	0
Tampa Electric Company [Member] | 5.65% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	54.2	54.2
Tampa Electric Company [Member] | 5.65% Refunding bonds [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	54.2	54.2
Tampa Electric Company [Member] | 5.15% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2025
Long-term debt, total	0	51.6
Tampa Electric Company [Member] | 5.15% Refunding bonds [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2025
Long-term debt, total	0	51.6
Tampa Electric Company [Member] | 1.5% term rate bonds repurchased in 2011 [Member]
Debt Instrument [Line Items]
Due	2030
Long-term debt, total	0	0
Tampa Electric Company [Member] | 1.5% term rate bonds repurchased in 2011 [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2030
Long-term debt, total	0	0
Tampa Electric Company [Member] | 5.0% Refunding bonds [Member]
Debt Instrument [Line Items]
Due	2034
Long-term debt, total	0	0
Tampa Electric Company [Member] | 5.0% Refunding bonds [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2034
Long-term debt, total	0	0
Tampa Electric Company [Member] | 6.25% Notes [Member]
Debt Instrument [Line Items]
Maturity range start	2014
Long-term debt, total	250.0	250.0
Tampa Electric Company [Member] | 6.25% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2016
Maturity range start	2014
Long-term debt, total	250.0	250.0
Tampa Electric Company [Member] | 6.1% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, total	200.0	200.0
Tampa Electric Company [Member] | 6.1% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2018
Long-term debt, total	200.0	200.0
Tampa Electric Company [Member] | 5.4% Notes [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	231.7	231.7
Tampa Electric Company [Member] | 5.4% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2021
Long-term debt, total	231.7	231.7
Tampa Electric Company [Member] | 2.6% Notes [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	225.0	225.0
Tampa Electric Company [Member] | 2.6% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2022
Long-term debt, total	225.0	225.0
Tampa Electric Company [Member] | 6.55% Notes [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	250.0	250.0
Tampa Electric Company [Member] | 6.55% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2036
Long-term debt, total	250.0	250.0
Tampa Electric Company [Member] | 6.15% Notes [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	190.0	190.0
Tampa Electric Company [Member] | 6.15% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2037
Long-term debt, total	190.0	190.0
Tampa Electric Company [Member] | 4.1% Notes [Member]
Debt Instrument [Line Items]
Long-term debt, total	250.0	250.0
Tampa Electric Company [Member] | 4.1% Notes [Member] | Long-Term Debt [Member]
Debt Instrument [Line Items]
Due	2042
Long-term debt, total	$ 250.0	$ 250.0

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Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Short-Term Debt Credit Facilities

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

Credit Facilities
	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	6.0	$	0.7	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		78.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	84.0	$	0.7	$	675.0	$	0.0	$	1.5

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

Credit Facilities
	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	6.0	$	0.7	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		78.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	84.0	$	0.7	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Measurements

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

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

Natural gas and diesel fuel swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of these swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 16).

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 Dec. 31, 2013, the fair value of derivatives was not materially affected by nonperformance risk. The company’s net positions with substantially all counterparties were asset positions. There were no Level 3 assets or liabilities during the 2013 or 2012 fiscal years.

Tampa Electric Company [Member]

Fair Value Measurements

14. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

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

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

Natural gas swaps are OTC swap instruments. The primary pricing inputs in determining the fair value of natural gas swaps are the NYMEX quoted closing prices of exchange-traded instruments. These prices are applied to the notional amounts of active positions to determine the reported fair value (see Note 13).

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 Dec. 31, 2013, the fair value of derivatives was not materially affected by nonperformance risk. TEC’s net positions with substantially all counterparties were liability positions. There were no Level 3 assets or liabilities during the 2013 or 2012 fiscal years.

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Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2013

Accounting for Derivative Instruments and Hedging Activities

16. 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. 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 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 (see Note 17). 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).

The 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 Dec. 31, 2013, all of the company’s physical contracts qualify for the NPNS exception.

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

Total Derivatives
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.7	$	0.0
Long-term assets		0.3		0.2
Total assets	$	10.0	$	0.2
Current liabilities	$	0.1	$	14.6
Long-term liabilities		0.2		0.6
Total liabilities	$	0.3	$	15.2

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

Offsetting of Derivative Assets and Liabilities (millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Dec. 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

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

Diesel Fuel Derivatives
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	0.2	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.2	$	0.0
Current liabilities	$	0.1	$	0.5
Long-term liabilities		0.0		0.4
Total liabilities	$	0.1	$	0.9

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

Natural Gas Derivatives (1)
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.5	$	0.0
Long-term assets		0.3		0.2
Total assets	$	9.8	$	0.2
Current liabilities	$	0.0	$	14.1
Long-term liabilities		0.2		0.2
Total liabilities	$	0.2	$	14.3

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

The ending balance in AOCI related to the cash flow hedges and previously settled interest rate swaps at Dec. 31, 2013 is a net loss of $7.8 million after tax and accumulated amortization. This compares to a net loss of $9.2 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

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

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

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

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

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

Based on the fair value of the instruments at Dec. 31, 2013, net pretax gains of $9.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31:

	Amount of Gain/(Loss) on Derivatives Recognized in			Location of Gain/(Loss) Reclassified From AOCI	Gain/(Loss) Reclassified From
(millions)	OCI			Into Income	AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)		Effective Portion (1)
2013
Interest rate contracts:	$	0.0		Interest expense	($	0.9	)
Commodity contracts:
Diesel fuel derivatives		0.6		Mining related costs		0.1
Total	$	0.6			($	0.8	)
2012
Interest rate contracts:	($	4.9	)	Interest expense	($	0.8	)
Commodity contracts:
Diesel fuel derivatives		0.3		Mining related costs		0.4
Total	($	4.6	)		($	0.4	)
2011
Interest rate contracts:	$	0.0		Interest expense	($	0.7	)
Commodity contracts:
Diesel fuel derivatives		1.2		Mining related costs		2.7
Total	$	1.2			$	2.0

(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 years ended Dec. 31, 2013, 2012 and 2011, all hedges were effective.

The following table presents the derivative activity for instruments classified as qualifying cash flow hedges for the years ended Dec. 31:

(millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income (1)
2013
Interest rate swaps	$	0.0		$	0.0		($	0.9	)
Diesel fuel derivatives		0.1			0.6			0.1
Total	$	0.1		$	0.6		($	0.8	)
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.8	)
Diesel fuel derivatives		(0.9	)		0.3			0.4
Total	($	0.9	)	($	4.6	)	($	0.4	)
2011
Interest rate swaps	$	0.0		$	0.0		($	0.7	)
Diesel fuel derivatives		(0.3	)		1.2			2.7
Total	($	0.3	)	$	1.2		$	2.0

(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, 2015 for financial natural gas contracts. The following table presents by commodity type the company’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		2.0		0.0		36.9
2015		0.0		0.0		0.0		7.6
Total		0.0		2.0		0.0		44.5

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 Dec. 31, 2013, 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 Dec. 31, 2013, substantially all positions with counterparties were net assets.

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

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

Contingent Features
(millions)	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	0.1	)	($	0.1	)	$	0.0

Tampa Electric Company [Member]

Accounting for Derivative Instruments and Hedging Activities

13. 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 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 (see Note 14). 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 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).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Dec. 31, 2013, all of TEC’s physical contracts qualify for the NPNS exception.

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

Natural Gas Derivatives (1)
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.5	$	0.0
Long-term assets		0.3		0.2
Total assets	$	9.8	$	0.2
Current liabilities	$	0.0	$	14.1
Long-term liabilities		0.2		0.2
Total liabilities	$	0.2	$	14.3

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

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

Offsetting of Derivative Assets and Liabilities (millions)
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset on the Balance Sheet			Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Dec. 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

The ending balance in AOCI related to previously settled interest rate swaps at Dec. 31, 2013 is a net loss of $7.8 million after tax and accumulated amortization. This compares to a net loss of $8.7 million in AOCI after tax and accumulated amortization at Dec. 31, 2012.

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

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

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

Based on the fair value of the instruments at Dec. 31, 2013, net pretax losses of $9.5 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31, 2013, 2012 and 2011:

(millions)	Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
For the years ended Dec. 31:		2013			2012			2011
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)
Interest rate contracts:	Interest expense	($	0.9	)	($	0.8	)	($	0.7	)
Total		($	0.9	)	($	0.8	)	($	0.7	)

(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 years ended Dec. 31, 2013, 2012 and 2011, all hedges were effective.

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

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2014		0.0		36.9
2015		0.0		7.6
Total		0.0		44.5

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

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Dec. 31, 2013, 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 Dec. 31, 2013, 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 Dec. 31, 2013 were asset positions.

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Other Comprehensive Income - Other Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	$ 1.0	$ (7.4)	$ 1.8
Reclassification from AOCI to net income, Gross	1.3	0.6	(3.1)
Gain (Loss) Gain on cash flow hedges, Gross	2.3	(6.8)	(1.3)
Amortization of unrecognized benefit costs and other, Gross	23.6	(4.8)	(7.9)
Recognized benefit costs due to settlement, Gross	2.6		0.9
Total other comprehensive (loss) income, Gross	28.5	(11.6)	(8.3)
Unrealized gain (loss) on cash flow hedges, Tax	(0.4)	2.8	(0.6)
Reclassification from AOCI to net income, Tax	(0.5)	(0.2)	1.1
Gain (Loss) on cash flow hedges, Tax	(0.9)	2.6	0.5
Amortization of unrecognized benefit costs and other, Tax	(8.8)	0	3.3
Recognized benefit costs due to settlement, Tax	(1.0)		(0.3)
Total other comprehensive (loss) income, Tax	(10.7)	2.6	3.5
Unrealized gain (loss) on cash flow hedges, Net	0.6	(4.6)	1.2
Reclassification from AOCI to net income, Net	0.8	0.4	(2.0)
Gain (Loss) on cash flow hedges, Net	1.4	(4.2)	(0.8)
Amortization of unrecognized benefit costs and other, Net	14.8	(4.8)	(4.6)
Recognized benefit costs due to settlement, Net	1.6		0.6
Other comprehensive income (loss), net of tax	17.8	(9.0)	(4.8)
Tampa Electric Company [Member]
Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) on cash flow hedges, Gross	0	(8.0)	0
Reclassification from AOCI to net income, Gross	1.4	1.4	1.2
Gain (Loss) Gain on cash flow hedges, Gross	1.4	(6.6)	1.2
Total other comprehensive (loss) income, Gross	1.4	(6.6)	1.2
Unrealized gain (loss) on cash flow hedges, Tax	0	3.1	0
Reclassification from AOCI to net income, Tax	(0.5)	(0.6)	(0.5)
Gain (Loss) on cash flow hedges, Tax	(0.5)	2.5	(0.5)
Total other comprehensive (loss) income, Tax	(0.5)	2.5	(0.5)
Unrealized gain (loss) on cash flow hedges, Net	0	(4.9)	0
Reclassification from AOCI to net income, Net	0.9	0.8	0.7
Gain (Loss) on cash flow hedges, Net	0.9	(4.1)	0.7
Other comprehensive income (loss), net of tax	$ 0.9	$ (4.1)	$ 0.7

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Related Parties (Tables) (Tampa Electric Company [Member])

12 Months Ended

Dec. 31, 2013

Tampa Electric Company [Member]

Schedule of Related Parties

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:
(millions)	2013		2012		2011
Natural gas sales, net	$	18.3	$	11.7	$	0.0
Administrative and general, net	$	27.2	$	23.4	$	17.5

Amounts due from or to affiliates at Dec. 31,
(millions)	2013		2012
Accounts receivable (1)	$	1.3	$	4.7
Accounts payable (1)		9.8		7.9
Taxes receivable		54.9		22.1
Taxes payable		0.4		3.2

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Maturities of Long-Term Debt

TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2014 through 2018 and thereafter are as follows:

Long-Term Debt Maturities
As of Dec. 31, 2013 (millions)	2014		2015		2016		2017		2018		Thereafter		Total Long-Term Debt
TECO Finance	$	0.0	$	191.2	$	250.0	$	300.0	$	0.0	$	300.0	$	1,041.2
Tampa Electric		83.3		83.3		83.4		0.0		254.2		1,146.7		1,650.9
PGS		0.0		0.0		0.0		0.0		50.0		181.7		231.7
Total long-term debt maturities	$	83.3	$	274.5	$	333.4	$	300.0	$	304.2	$	1,628.4	$	2,923.8

Schedule of Long-Term Debt Outstanding

At Dec. 31, 2013 and 2012, TECO Energy had the following long-term debt outstanding:

Long-Term Debt
(millions) Dec. 31,		Due	2013			2012
TECO Finance	Notes (1)(2)(3): 6.75% (effective rate of 6.9%)	2015	$	191.2		$	191.2
	4.0% (effective rate of 4.2%)	2016		250.0			250.0
	6.572% (effective rate of 7.3%)	2017		300.0			300.0
	5.15% (effective rate of 5.3%)	2020		300.0			300.0
Total long-term debt of TECO Finance				1,041.2			1,041.2
Tampa Electric	Installment contracts payable (4):
	5.65% Refunding bonds (effective rate of 5.9%)	2018		54.2			54.2
	Variable rate bonds repurchased in 2008 (5)	2020		0.0			0.0
	5.15% Refunding bonds repurchased in 2013 (effective rate of 5.4% for 2012) (6)	2025		0.0			51.6
	1.5% Term rate bonds repurchased in 2011 (7)	2030		0.0			0.0
	5.0% Refunding bonds repurchased in 2012 (8)	2034		0.0			0.0
	Notes (1): 6.25% (effective rate of 6.3%) (2)	2014-2016		250.0			250.0
	6.1% (effective rate of 6.0%)	2018		200.0			200.0
	5.4% (effective rate of 5.4%)	2021		231.7			231.7
	2.6% (effective rate of 2.7%)	2022		225.0			225.0
	6.55% (effective rate of 6.6%)	2036		250.0			250.0
	6.15% (effective rate of 6.2%)	2037		190.0			190.0
	4.1% (effective rate of 4.2%)	2042		250.0			250.0
Total long-term debt of Tampa Electric				1,650.9			1,702.5
PGS	Notes (1): 6.1% (effective rate of 7.0%)	2018		50.0			50.0
	5.4% (effective rate of 5.4%)	2021		46.7			46.7
	2.6% (effective rate of 2.7%)	2022		25.0			25.0
	6.15% (effective rate of 6.2%)	2037		60.0			60.0
	4.1% (effective rate of 4.2%)	2042		50.0			50.0
Total long-term debt of PGS				231.7			231.7
Total long-term debt of TECO Energy				2,923.8			2,975.4
Unamortized debt discount, net				(2.7	)		(2.7	)
Total carrying amount of long-term debt				2,921.1			2,972.7
Less amount due within one year				83.3			0.0
Total long-term debt			$	2,837.8		$	2,972.7

(1) These securities are subject to redemption in whole or in part, at any time, at the option of the company.

(2) These long-term debt agreements contain various restrictive financial covenants.

(3) Guaranteed by TECO Energy.

(4) Tax-exempt securities.

(5) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.

(6) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.

(7) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.

(8) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2013

Variable Interest Entities

18. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.1 million, $75.8 million and $81.2 million, under these PPAs for the three years ended Dec. 31, 2013, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $46.6 million and $34.4 million for the two years ended Dec. 31, 2012 and 2011, respectively. This PPA expired on Dec. 31, 2012.

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

Tampa Electric Company [Member]

Variable Interest Entities

15. Variable Interest Entities

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

TEC has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 370 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being VIEs. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. TEC has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, TEC is not required to consolidate any of these entities. TEC purchased $22.1 million, $75.8 million and $81.2 million, under these PPAs for the three years ended Dec. 31, 2013, 2012 and 2011, respectively.

In one instance, TEC’s agreement with an entity for 370 MW of capacity was entered into prior to Dec. 31, 2003, the effective date of these standards. Under these standards, TEC is required to make an exhaustive effort to obtain sufficient information to determine if this entity is a VIE and which holder of the variable interests is the primary beneficiary. The owners of this entity are not willing to provide the information necessary to make these determinations, have no obligation to do so and the information is not available publicly. As a result, TEC is unable to determine if this entity is a VIE and, if so, which variable interest holder, if any, is the primary beneficiary. TEC has no obligation to this entity beyond the purchase of capacity; therefore, the maximum exposure for TEC is the obligation to pay for such capacity under terms of the PPA at rates that could be unfavorable to the wholesale market. TEC purchased $46.6 million and $34.4 million for the two years ended Dec. 31, 2012 and 2011, respectively. This PPA expired on Dec. 31, 2012.

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

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Discontinued Operations

12 Months Ended

Dec. 31, 2013

Discontinued Operations And Disposal Groups [Abstract]

Discontinued Operations

19. Discontinued Operations

On Aug. 7, 2012, TECO Energy received an offer from Renewable Energy Investments Guatemala Limited (REIN), a wholly-owned subsidiary of Sur Eléctrica Holding Limited (SUR), to purchase the independent power projects in Guatemala and certain affiliated Guatemala companies. SUR and REIN are international business companies organized under the laws of the Commonwealth of the Bahamas. On Sept. 27, 2012, an indirect wholly-owned subsidiary of TECO Energy, Inc., TECO Guatemala Holdings II, LLC (TGH), entered into an equity purchase agreement with SUR, and two equity purchase agreements with REIN (the three equity purchase agreements are collectively referred to herein as the “PAs”). Pursuant to the PA with SUR, TGH agreed to sell all of its ownership interests in TPS Guatemala One, Ltd. (TPS GO) for $12.5 million, and pursuant to the PAs with REIN, it agreed to sell all of its ownership interests in (i) TPS San José International, Inc. (TPS SJI) for $213.5 million and (ii) TECO Guatemala Services, Ltd. (TGS) for $1.5 million (TPS GO, TPS SJI and TGS are collectively referred to herein as the Disposal Group). The companies in the Disposal Group are the ultimate parent companies of TCAE, CGESJ, TEMSA, and TPS Operaciones de Guatemala, Limitada (TPSO), the owner of certain local real estate assets and the employer of the local employees. The total purchase price for the Disposal Group under the PAs was $227.5 million.

The sale of TPS GO, which owns 96.06% of TCAE, closed on Sept. 27, 2012. An affiliate of the party that controlled the remaining interest in TCAE (the “noncontrolling interest holder”) held certain contractual rights with respect to TEMSA and CGESJ, including a right of first offer. The noncontrolling interest holder was also granted the opportunity to purchase TGS since the operations of TPSO are integral to the operations of TEMSA and CGESJ. The noncontrolling interest holder exercised the right of first offer for TPS SJI and elected to purchase TGS by executing PAs similar to the PAs with REIN on Oct. 17, 2012 and Oct. 26, 2012, respectively. The sales of TPS SJI and TGS to the noncontrolling interest holder closed on Dec. 19, 2012.

As a result of the PAs, the TECO Guatemala segment is accounted for as a discontinued operation at Dec. 31, 2013. The following table provides selected components of discontinued operations:

Components of income from discontinued operations attributable to TECO Energy	Twelve months ended Dec. 31,
(millions)	2013			2012			2011
Revenues	$	0.0		$	114.2		$	133.5
(Loss) income from operations		(0.2	)		27.7			33.7
Loss on assets sold, including transaction costs		0.0			(38.3	)		(0.4	)
Income (loss) from discontinued operations		(0.2	)		(10.6	)		33.3
Provision (benefit) for income taxes		(0.1	)		22.4			11.2
Income (loss) from discontinued operations, net		(0.1	)		(33.0	)		22.1
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.3			0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8

The provision for income taxes line item includes an after-tax charge of $22.9 million in 2012 associated with foreign tax credits. The 2012 charge is a result of the sales of the Disposal Group which eliminate future foreign source income that would be required to utilize these credits.

The PAs contain customary representations, warranties and covenants. The PAs also contain indemnification provisions subject to specified limitations as to time and amount, including an indemnification provision related to an uncertain tax position related to TCAE.

On Dec. 19, 2013, the ICSID tribunal hearing TGH’s arbitration claim against the Republic of Guatemala under DR-CAFTA issued an award in the case. The ICSID tribunal unanimously found in favor of TGH and awarded damages of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the prime rate plus 2%. In addition, the tribunal ruled that Guatemala must reimburse TGH for approximately $7.5 million of the costs it incurred in pursuing the arbitration.

The ICSID tribunal found that Guatemala breached its treaty obligation to grant TGH fair and equitable treatment under the terms of the DR-CAFTA, thereby causing damages to TGH for which it is entitled to compensation. In sum, the tribunal found that Guatemala’s repudiation of fundamental regulatory principles applying to the tariff review process was arbitrary and breached elementary standards of due process in administrative matters.

Each party has 120 days from the date of the award to seek annulment of the decision. Pending the outcome of a potential annulment filing, results in 2013 do not reflect any benefit of this decision.

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Consolidated Statements of Capital (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Beginning Balance	$ 2,291.8		$ 2,267.2		$ 2,170.6
Net income	197.7		213.0		272.9
Other comprehensive income, after tax	17.8		(9.0)		(4.8)
Common stock issued	5.9		(2.9)		1.0
Cash dividends declared	(191.2)		(190.4)		(183.2)
Stock compensation expense	13.5		12.0		9.1
Noncontrolling - dividends			(0.3)		(0.6)
Tax benefits - stock compensation			2.8		2.2
Ending Balance	2,333.7		2,291.8		2,267.2
Noncontrolling - sale of business			(0.6)
Restricted stock - dividends	1.1
Tax short fall - stock compensation	(2.9)
Common Stock [Member]
Beginning Balance	216.6		215.8		214.9
Beginning Balance, shares	216.6	[1]	215.8	[1]	214.9	[1]
Common stock issued	0.7		0.8		0.9
Common stock issued, shares	0.7	[1]	0.8	[1]	0.9	[1]
Ending Balance	217.3		216.6		215.8
Ending Balance, shares	217.3	[1]	216.6	[1]	215.8	[1]
Additional Paid-in Capital [Member]
Beginning Balance	1,564.5		1,553.4		1,542.0
Common stock issued	5.2		(3.7)		0.1
Stock compensation expense	13.5		12.0		9.1
Tax benefits - stock compensation			2.8		2.2
Ending Balance	1,581.3		1,564.5		1,553.4
Restricted stock - dividends	1.0
Tax short fall - stock compensation	(2.9)
Retained Earnings [Member]
Beginning Balance	541.7		519.4		430.0
Net income	197.7		212.7		272.6
Cash dividends declared	(191.2)		(190.4)		(183.2)
Ending Balance	548.3		541.7		519.4
Restricted stock - dividends	0.1
Accumulated Other Comprehensive Income (Loss) [Member]
Beginning Balance	(31.0)		(22.0)		(17.2)
Other comprehensive income, after tax	17.8		(9.0)		(4.8)
Ending Balance	(13.2)		(31.0)		(22.0)
Noncontrolling Interest [Member]
Beginning Balance			0.6		0.9
Net income			0.3		0.3
Noncontrolling - dividends			(0.3)		(0.6)
Ending Balance	0		0		0.6
Noncontrolling - sale of business			$ (0.6)

[1] (1) TECO Energy had a maximum of 400.0 million shares of $1 par value common stock authorized as of Dec. 31, 2013, 2012, 2011 and 2010.

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Goodwill and Asset Impairments

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Goodwill and Asset Impairments

20. Goodwill and Asset Impairments

Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill with an indefinite life is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. The goodwill formerly on the company’s balance sheet related to the TECO Guatemala segment and arose from the purchase of multiple entities as a result of the company’s investments in the Alborada (held by TPS GO) and San José (held by TPS SJI) power plants. Since these reporting units were one level below the operating segment level, discrete cash flow information was available, and management regularly reviewed their operating results separately, these were the reporting unit level at which potential impairment was tested.

Prior to the sales in 2012 (see Note 19), goodwill balances for the TPS GO and TPS SJI reporting units were written down to their implied fair value calculated using the offers from SUR and REIN. Although these were binding quoted prices, the fair value measurements were considered Level 2 measurements since the market was not active as defined by accounting standards (i.e. transactions for these assets were too infrequent to provide pricing information on an ongoing basis). Prior to receiving the offers from REIN and SUR, the fair values of TPS GO’s and TPS SJI’s goodwill amounts were calculated using the discounted cash flows appropriate for the business model of each reporting unit. Discounted cash flows were formerly the best estimates of fair value of the reporting units, since neither a sale nor a similar transaction was readily observed in the marketplace for many years due to an inactive market.

The changes in the carrying amount of goodwill for the year ended Dec. 31, 2012 are represented in the following table:

(millions)	TPS GO			TPS SJI			Total
Balance as of Jan. 1, 2012	$	3.1		$	52.3		$	55.4
Impairment losses, pretax		(3.1	)		(12.1	)		(15.2	)
Goodwill written off upon sale, pretax		0.0			(40.2	)		(40.2	)
Balance as of Dec. 31, 2012	$	0.0		$	0.0		$	0.0

The Impairment losses, pretax and Goodwill written off upon sale, pretax amounts from the table above are recorded in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012.

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.

Prior to the sale of TGS, the company recorded a long-lived asset pretax impairment charge of $2.0 million. This amount is recorded in the Income (loss) from discontinued operations line item in the Consolidated Statements of Income and the Loss (gain) on sales of business/assets, pretax line item in the Consolidated Statements of Cash Flows for the year ended Dec. 31, 2012. The fair value was calculated using the offer from REIN. Although it was a binding quoted price, the fair value measurement was considered a Level 2 measurement since the market was not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis).

Additionally, in both 2012 and 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in each fourth quarter on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that are recoverable; therefore, no impairment charge was deemed necessary. Additionally, the company performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable.

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Employee Postretirement Benefits - Schedule of Benefit Payments (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2014	$ 53.5
Expected Benefit Payments - 2015	50.9
Expected Benefit Payments - 2016	55.3
Expected Benefit Payments - 2017	55.9
Expected Benefit Payments - 2018	58.3
Expected Benefit Payments - 2019-2023	298.6
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2014	53.5
Expected Benefit Payments - 2015	50.9
Expected Benefit Payments - 2016	55.3
Expected Benefit Payments - 2017	55.9
Expected Benefit Payments - 2018	58.3
Expected Benefit Payments - 2019-2023	298.6
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2014	13.3
Expected Benefit Payments - 2015	13.9
Expected Benefit Payments - 2016	14.6
Expected Benefit Payments - 2017	15.2
Expected Benefit Payments - 2018	15.7
Expected Benefit Payments - 2019-2023	81.9
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected Benefit Payments - 2014	13.3
Expected Benefit Payments - 2015	13.9
Expected Benefit Payments - 2016	14.6
Expected Benefit Payments - 2017	15.2
Expected Benefit Payments - 2018	15.7
Expected Benefit Payments - 2019-2023	$ 81.9

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Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Current assets	$ 9.7	$ 0
Long-term assets	0.3	0.2
Total assets	10.0	0.2
Current liabilities	0.1	14.6
Long-term liabilities	0.2	0.6
Total liabilities	0.3	15.2
Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	9.5	0
Long-term assets	0.3	0.2
Current liabilities	0	14.1
Long-term liabilities	0.2	0.2
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	0.2	0
Long-term assets	0	0
Total assets	0.2	0
Current liabilities	0.1	0.5
Long-term liabilities	0	0.4
Total liabilities	0.1	0.9
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current assets	9.5	0
Long-term assets	0.3	0.2
Total assets	9.8	0.2
Current liabilities	0	14.1
Long-term liabilities	0.2	0.2
Total liabilities	0.2	14.3
Natural Gas Derivatives [Member] | Tampa Electric Company [Member]
Derivatives, Fair Value [Line Items]
Current assets	9.5	0
Long-term assets	0.3	0.2
Total assets	9.8	0.2
Current liabilities	0	14.1
Long-term liabilities	0.2	0.2
Total liabilities	$ 0.2	$ 14.3

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Regulatory (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Regulatory Assets and Regulatory Liabilities

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

Regulatory Assets and Liabilities
(millions)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.4	$	67.2
Other:
Cost-recovery clauses		6.1		42.9
Postretirement benefit asset		182.7		276.1
Deferred bond refinancing costs (2)		8.0		9.2
Environmental remediation		51.4		46.9
Competitive rate adjustment		4.1		4.1
Other		7.7		6.5
Total other regulatory assets		260.0		385.7
Total regulatory assets		327.4		452.9
Less: Current portion		34.3		70.3
Long-term regulatory assets	$	293.1	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	9.8	$	14.6
Other:
Cost-recovery clauses		54.5		73.9
Transmission and delivery storm reserve		56.1		50.4
Deferred gain on property sales (3)		2.0		3.4
Provision for stipulation and other		0.8		1.0
Accumulated reserve - cost of removal		594.0		593.7
Total other regulatory liabilities		707.4		722.4
Total regulatory liabilities		717.2		737.0
Less: Current portion		85.8		105.6
Long-term regulatory liabilities	$	631.4	$	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
(millions)	Dec. 31, 2013		Dec. 31, 2012
Clause recoverable (1)	$	10.2	$	47.0
Components of rate base (2)		185.6		279.1
Regulatory tax assets (3)		67.4		67.2
Capital structure and other (3)		64.2		59.6
Total	$	327.4	$	452.9

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

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

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

Tampa Electric Company [Member]

Schedule of Regulatory Assets and Regulatory Liabilities

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

Regulatory Assets and Liabilities
(millions)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.4	$	67.2
Other:
Cost-recovery clauses		6.1		42.9
Postretirement benefit asset		182.7		276.1
Deferred bond refinancing costs (2)		8.0		9.2
Environmental remediation		51.4		46.9
Competitive rate adjustment		4.1		4.1
Other		7.7		6.5
Total other regulatory assets		260.0		385.7
Total regulatory assets		327.4		452.9
Less: Current portion		34.3		70.3
Long-term regulatory assets	$	293.1	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	9.8	$	14.6
Other:
Cost-recovery clauses		54.5		73.9
Transmission and delivery storm reserve		56.1		50.4
Deferred gain on property sales (3)		2.0		3.4
Provision for stipulation and other		0.8		1.0
Accumulated reserve - cost of removal		594.0		593.7
Total other regulatory liabilities		707.4		722.4
Total regulatory liabilities		717.2		737.0
Less: Current portion		85.8		105.6
Long-term regulatory liabilities	$	631.4	$	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
(millions)	Dec. 31, 2013		Dec. 31, 2012
Clause recoverable (1)	$	10.2	$	47.0
Components of rate base (2)		185.6		279.1
Regulatory tax assets (3)		67.4		67.2
Capital structure and other (3)		64.2		59.6
Total	$	327.4	$	452.9

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

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

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

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

12 Months Ended

Dec. 31, 2013

TECO Guatemala [Member]

Components of Discontinued Operations

The following table provides selected components of discontinued operations:

Components of income from discontinued operations attributable to TECO Energy	Twelve months ended Dec. 31,
(millions)	2013			2012			2011
Revenues	$	0.0		$	114.2		$	133.5
(Loss) income from operations		(0.2	)		27.7			33.7
Loss on assets sold, including transaction costs		0.0			(38.3	)		(0.4	)
Income (loss) from discontinued operations		(0.2	)		(10.6	)		33.3
Provision (benefit) for income taxes		(0.1	)		22.4			11.2
Income (loss) from discontinued operations, net		(0.1	)		(33.0	)		22.1
Less: Income from discontinued operations attributable to noncontrolling interest		0.0			0.3			0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8

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Employee Postretirement Benefits - Schedule of Change in Benefit Obligation (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	$ 715.0	$ 646.4
Service cost	18.2	17.0	16.0
Interest cost	28.9	30.1	30.9
Plan participants' contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	(50.4)	54.7
Gross benefits paid	(43.1)	(33.2)
Settlements	(2.6)	0
Federal subsidy on benefits paid
Net benefit obligation at end of year	666.0	715.0	646.4
Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	230.3	216.5
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Plan participants' contributions	2.9	3.7
Plan amendments	0	(5.2)
Actuarial loss (gain)	(22.1)	16.3
Gross benefits paid	(15.0)	(14.5)
Settlements	0	0
Federal subsidy on benefits paid	0.2	1.0
Net benefit obligation at end of year	208.1	230.3	216.5
TECO Energy [Member] | Pension Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	715.0	646.4
Service cost	18.2	17.0	16.0
Interest cost	28.9	30.1	30.9
Plan participants' contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	(50.4)	54.7
Gross benefits paid	(43.1)	(33.2)
Settlements	(2.6)	0
Net benefit obligation at end of year	666.0	715.0	646.4
TECO Energy [Member] | Other Postretirement Benefits [Member]
Change in benefit obligation
Net benefit obligation at beginning of year	230.3	216.5
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Plan participants' contributions	2.9	3.7
Plan amendments	0	(5.2)
Actuarial loss (gain)	(22.1)	16.3
Gross benefits paid	(15.0)	(14.5)
Settlements	0	0
Federal subsidy on benefits paid	0.2	1.0
Net benefit obligation at end of year	$ 208.1	$ 230.3	$ 216.5

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 185.2	$ 200.5
Receivables, less allowance for uncollectibles	287.2	282.7
Inventories, at average cost
Derivative assets	9.7	0
Regulatory assets	34.3	70.3
Deferred income taxes	100.3	63.3
Prepayments and other current assets	34.9	33.9
Income tax receivables	1.5	0.4
Total current assets	857.7	856.8
Property, plant and equipment
Construction work in progress	386.7	336.1
Other property	448.3	443.8
Property, plant and equipment, at original costs	9,077.3	8,664.0
Accumulated depreciation	(2,907.2)	(2,695.5)
Total property, plant and equipment, net	6,170.1	5,968.5
Other assets
Regulatory assets	293.1	382.6
Derivative assets	0.3	0.2
Deferred charges and other assets	126.8	126.8
Total other assets	420.2	509.6
Total assets	7,448.0	7,334.9
Current liabilities
Long-term debt due within one year	83.3	0
Notes payable	84.0	0
Accounts payable	261.7	232.8
Customer deposits	164.5	162.9
Regulatory liabilities	85.8	105.6
Derivative liabilities	0.1	14.6
Interest accrued	31.9	33.2
Taxes accrued	34.6	32.1
Other	19.5	19.9
Total current liabilities	765.4	601.1
Other liabilities
Deferred income taxes	444.0	277.9
Investment tax credits	9.4	9.7
Regulatory liabilities	631.4	631.4
Derivative liabilities	0.2	0.6
Deferred credits and other liabilities	426.1	549.7
Long-term debt, less amount due within one year	2,837.8	2,972.7
Total other liabilities	4,348.9	4,442.0
Commitments and Contingencies
Capital
Common equity	217.3	216.6
Additional paid in capital	1,581.3	1,564.5
Retained earnings	548.3	541.7
Accumulated other comprehensive loss	(13.2)	(31.0)
Total capital	2,333.7	2,291.8
Total liabilities and capital	7,448.0	7,334.9
Fuel [Member]
Inventories, at average cost
Utility inventories	118.7	123.6
Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	85.9	82.1
Electric [Member]
Property, plant and equipment
Electric	6,934.0	6,655.8
Gas [Member]
Property, plant and equipment
Electric	1,308.3	1,228.3
Tampa Electric Company [Member]
Current assets
Cash and cash equivalents	9.8	45.2
Receivables, less allowance for uncollectibles	227.6	213.8
Inventories, at average cost
Derivative assets	9.5	0
Regulatory assets	34.3	70.3
Deferred income taxes	29.4	20.0
Prepayments and other current assets	12.5	11.5
Income tax receivables	54.9	22.1
Total current assets	548.5	544.4
Property, plant and equipment
Construction work in progress	385.3	335.0
Property, plant and equipment, at original costs	8,568.8	8,161.4
Accumulated depreciation	(2,562.6)	(2,373.6)
Public utilities, property, plant and equipment, net	6,006.2	5,787.8
Other property	8.3	7.3
Total property, plant and equipment, net	6,014.5	5,795.1
Other assets
Unamortized debt expense	14.8	16.1
Regulatory assets	293.1	382.6
Derivative assets	0.3	0.2
Other	4.6	6.2
Total other assets	312.8	405.1
Total assets	6,875.8	6,744.6
Current liabilities
Long-term debt due within one year	83.3	0
Notes payable	84.0	0
Accounts payable	226.0	188.6
Customer deposits	164.5	163.0
Regulatory liabilities	85.8	105.6
Derivative liabilities	0	14.1
Interest accrued	16.4	17.3
Taxes accrued	12.2	13.7
Other	12.0	11.8
Total current liabilities	684.2	514.1
Other liabilities
Deferred income taxes	1,114.3	980.9
Investment tax credits	9.4	9.7
Regulatory liabilities	631.4	631.4
Derivative liabilities	0.2	0.2
Other	308.1	409.4
Long-term debt, less amount due within one year	1,797.5	1,932.6
Total other liabilities	2,063.4	2,031.6
Commitments and Contingencies
Capital
Common equity	2,030.4	1,970.4
Retained earnings	308.1	304.6
Accumulated other comprehensive loss	(7.8)	(8.7)
Total capital	2,330.7	2,266.3
Total capitalization	4,128.2	4,198.9
Total liabilities and capital	6,857.8	6,744.6
Tampa Electric Company [Member] | Fuel [Member]
Inventories, at average cost
Utility inventories	93.7	89.1
Tampa Electric Company [Member] | Materials and Supplies [Member]
Inventories, at average cost
Utility inventories	76.8	72.4
Tampa Electric Company [Member] | Electric [Member]
Property, plant and equipment
Electric	6,934.0	6,654.5
Tampa Electric Company [Member] | Gas [Member]
Property, plant and equipment
Electric	$ 1,249.5	$ 1,171.9

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Common Stock (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Schedule of Assumptions Used to Determine Fair Value

Assumptions	2013			2012			2011
Assumptions applicable to performance-based restricted stock
Risk-free interest rate		0.41	%		0.38	%		0.96	%
Expected lives (in years)		3			3			3
Expected stock volatility		19.04	%		20.99	%		34.61	%
Dividend yield		4.83	%		4.78	%		4.48	%

Schedule of Additional Information on Compensation Costs and Income Tax Benefits and Excess Tax Benefits Related to Stock-Based Compensation Awards

The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.

(millions)	2013		2012		2011
Compensation costs (1)	$	13.5	$	12.0	$	9.1
Income tax benefits (1)		5.2		4.6		3.5
Excess tax benefits (2)		0.0		2.6		1.7

(1) Reflected on the Consolidated Statements of Income.

(2) Reflected as financing activities on the Consolidated Statements of Cash Flows.

Summary of Non-Vested Shares of Restricted Stock

A summary of non-vested shares of restricted stock is shown as follows:

Nonvested Restricted Stock
	Time-Based Restricted					Performance-Based
	Stock (1)					Restricted Stock (1)
	Number of Shares (thousands)			Weighted - Avg. Grant Date Fair Value (per share)		Number of Shares (thousands)			Weighted- Avg. Grant Date Fair Value (per share)
Nonvested balance at Dec. 31, 2012		592		$	18.04		1,490		$	17.13
Granted		237			17.92		496			16.87
Vested		(187	)		16.91		(434	)		17.20
Forfeited		(4	)		17.99		(47	)		16.82
Nonvested balance at Dec. 31, 2013		638		$	18.33		1,505		$	17.04

(1) The weighted-average remaining contractual term of restricted stock is two years.

Summary of Stock Option Transactions

Stock option transactions are summarized as follows:

Stock Options
	Number of Shares (thousands)			Weighted-Avg. Option Price (per share)		Weighted-Avg. Remaining Contractual Term (years)	Aggregate Intrinsic Value (millions)
Outstanding balance at Dec. 31, 2012		2,087		$	15.05
Granted		0			0.00
Exercised		(507	)		13.22
Cancelled		(13	)		18.87
Outstanding balance at Dec. 31, 2013 (1)		1,567		$	15.62	2	$	2.6
Exercisable at Dec. 31, 2013 (1)		1,567		$	15.62	2	$	2.6
Available for future grant at Dec. 31, 2013		2,725

(1) Option prices range from $12.01 to $19.01 per share.

Schedule of Option Outstanding and Exercisable

As of Dec. 31, 2013, the options outstanding and exercisable are summarized below:

Range of Option Prices (per share)	Option Shares (thousands)		Weighted-Avg. Option Price (per share)		Weighted-Avg. Remaining Contractual Life
$12.01 - $13.56		331	$	13.10	1 Years
$16.21 - $19.01		1,236	$	16.29	2 Years
Total		1,567	$	15.62	2 Years

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Common Stock - Summary of Non-Vested Shares of Restricted Stock (Parenthetical) (Detail) (Restricted Stock [Member])	12 Months Ended
	Dec. 31, 2013
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining contractual term of restricted stock, years	2 years

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Consolidated Statements of Capitalization - Capital Stock (Parenthetical) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Equity contributions made by TECO Energy	$ 60.0	$ 118.0
Preferred Stock Par Value [Member]
Preferred stock - par value	$ 1
Preferred stock, shares authorized	10.0
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preferred Stock Par Value [Member]
Preferred stock - par value	$ 100
Preferred stock, shares authorized	1.5
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preferred Stock No Par Value [Member]
Preferred stock, no par value
Preferred stock, shares authorized	2.5
Preferred stock, shares outstanding	0
Tampa Electric Company [Member] | Preference Stock No Par Value [Member]
Preferred stock, no par value
Preferred stock, shares authorized	2.5
Preferred stock, shares outstanding	0

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Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Line Items]
Beginning balance	$ 28.6	$ 53.8
Additional liabilities	0.1	0.7
Liabilities settled	(1.4)	(29.1)
Accretion expense	1.4	1.4	1.4
Revisions to estimated cash flows	(0.3)	0
Other	0.2	1.8
Ending balance	28.6	28.6	53.8
Tampa Electric Company [Member]
Asset Retirement Obligation [Line Items]
Beginning balance	5.0	30.8
Additional liabilities	0.1	0
Liabilities settled	(0.2)	(27.6)
Revisions to estimated cash flows	(0.3)	0
Other	0.2	1.8
Ending balance	$ 4.8	$ 5.0

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Income And Comprehensive Income [Abstract]
Net income attributable to TECO Energy	$ 197.7	$ 212.7	$ 272.6
Other comprehensive income (loss), net of tax
Net unrealized gains (losses) on cash flow hedges	1.4	(4.2)	(0.8)
Amortization of unrecognized benefit costs and other	14.8	(4.8)	(4.6)
Recognized benefit costs due to settlement	1.6	0	0.6
Other comprehensive income (loss), net of tax	17.8	(9.0)	(4.8)
Comprehensive income attributable to TECO Energy	$ 215.5	$ 203.7	$ 267.8

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Common Stock - Schedule of Additional Information on Compensation Costs and Income Tax Benefits and Excess Tax Benefits Related to Stock-Based Compensation Awards (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation costs	$ 13.5	$ 12.0	$ 9.1
Income tax benefits	5.2	4.6	3.5
Excess tax benefits	$ 0	$ 2.6	$ 1.7

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Consolidated Statements of Capitalization - Long-term Debt Maturities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Debt Instrument [Line Items]
Total long-term debt maturities	$ 2,923.8
Tampa Electric Company [Member]
Debt Instrument [Line Items]
2014	83.3
2015	83.3
2016	83.4
2017	0
2018	254.2
Thereafter	1,146.7
Total long-term debt maturities	1,650.9
Long Term Debt Maturities [Member]
Debt Instrument [Line Items]
2014	83.3
2015	83.3
2016	83.4
2017	0
2018	304.2
Thereafter	1,328.4
Total long-term debt maturities	1,882.6
PGS [Member]
Debt Instrument [Line Items]
2014	0
2015	0
2016	0
2017	0
2018	50.0
Thereafter	181.7
Total long-term debt maturities	$ 231.7

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Schedule II - Valuation and Qualifying Accounts and Reserves (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$ 4.2	$ 2.6	$ 4.5
Charged to Income	3.3	4.8	3.8
Other Charges	0	0	0
Payments & Deductions	2.8	3.2	5.7
Balance at End of Period	4.7	4.2	2.6
Tampa Electric Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	1.5	1.3	3.2
Charged to Income	3.3	3.4	3.8
Other Charges	0	0	0
Payments & Deductions	2.8	3.2	5.7
Balance at End of Period	$ 2.0	$ 1.5	$ 1.3

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Significant Accounting Policies - Schedule of Fuel Inventory (Detail) (Fuel [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory [Line Items]
Fuel inventory	$ 118.7	$ 123.6
Tampa Electric Company [Member]
Inventory [Line Items]
Fuel inventory	93.7	89.1
TECO Coal [Member]
Inventory [Line Items]
Fuel inventory	$ 25.0	$ 34.5

XML

Common Stock - Schedule of Option Outstanding and Exercisable (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Option Prices, Minimum	$ 12.01
Range of Option Prices, Maximum	$ 19.01
Option Shares	1,567
Weighted-Avg. Option Price	$ 15.62
Weighted-Avg. Remaining Contractual Life, Years	2 years
$12.01 - $13.56 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Option Prices, Minimum	$ 12.01
Range of Option Prices, Maximum	$ 13.56
Option Shares	331
Weighted-Avg. Option Price	$ 13.10
Weighted-Avg. Remaining Contractual Life, Years	1 year
$16.21 - $19.01 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Option Prices, Minimum	$ 16.21
Range of Option Prices, Maximum	$ 19.01
Option Shares	1,236
Weighted-Avg. Option Price	$ 16.29
Weighted-Avg. Remaining Contractual Life, Years	2 years

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Quarterly Data (unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly Data (unaudited)

23. Quarterly Data (unaudited)

Financial data by quarter is as follows:

(millions, except per share amounts) Quarter ended	Dec. 31		Sept. 30		June 30		March 31
2013
Revenues	$	688.4	$	765.9	$	735.9	$	661.1
Income from operations		99.6		140.5		119.5		104.1
Net income from continuing operations		42.1		62.9		51.6		41.2
Net income attributable to TECO Energy		42.0		62.8		51.4		41.5
EPS - Basic
From continuing operations	$	0.20	$	0.29	$	0.24	$	0.19
Attributable to TECO Energy		0.20		0.29		0.24		0.19
EPS - Diluted
From continuing operations	$	0.20	$	0.29	$	0.24	$	0.19
Attributable to TECO Energy		0.20		0.29		0.24		0.19
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220
Quarter ended	Dec. 31		Sept. 30		June 30		March 31
2012
Revenues (1)	$	688.4	$	858.6	$	752.5	$	697.1
Income from operations (1)		109.5		183.1		149.1		114.8
Net income from continuing operations (1)		45.6		90.2		65.6		44.6
Net income attributable to TECO Energy		45.1		44.0		73.1		50.5
EPS - Basic
From continuing operations (1)	$	0.21	$	0.42	$	0.30	$	0.21
Attributable to TECO Energy		0.21		0.20		0.34		0.24
EPS - Diluted
From continuing operations (1)	$	0.21	$	0.42	$	0.30	$	0.20
Attributable to TECO Energy		0.21		0.20		0.34		0.23
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220

(1) Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

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Pending Acquisition of New Mexico Gas Company - Additional Information (Detail) (USD $)	0 Months Ended			0 Months Ended		6 Months Ended	12 Months Ended			0 Months Ended
	May 25, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 17, 2013 Components of Rate Base [Member]	Dec. 17, 2013 London Interbank Offered Rate (LIBOR) [Member]	Jun. 24, 2013 Bridge Facility [Member]	Dec. 31, 2013 Bridge Facility [Member]	Dec. 31, 2013 Bridge Facility [Member] Minimum [Member]	Dec. 31, 2013 Bridge Facility [Member] Maximum [Member]	Dec. 17, 2013 Letters of Credit [Member] London Interbank Offered Rate (LIBOR) [Member]	Dec. 17, 2013 New Mexico Gas Company [Member]	Jun. 24, 2013 New Mexico Gas Company [Member] Bridge Facility [Member]
Loans At Acquisition Date [Line Items]
Aggregate Purchase Price	$ 950,000,000					$ 950,000,000
Senior Secured Notes at NMGC	200,000,000
Aggregate liability with respect to such indemnification obligations		30,000,000
Aggregate liability with respect to such indemnification obligations deductible		9,250,000
Bank credit facility		675,000,000	675,000,000			1,075,000,000					125,000,000	125,000,000
Maturity period							364 days
Interest rate margin				0.50%	1.00%			0.25%	2.00%
Increase on variable rate for each period that elapses after acquisition closing							0.25%
Period after which company is subject to an increase in variable rate							90 days
Total capitalization ratio							0.70
Normal capitalization ratio							0.65
Credit agreement maturity date											Dec. 17, 2018
Increase commitment under credit facility				$ 75,000,000						$ 40,000,000

XML

Income Taxes - Schedule of Income Tax Expense (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred income taxes
Total income tax expense	$ 108.8	$ 160.2	$ 153.9
Deferred income taxes
Amortization of investment tax credits	(0.3)	(0.3)	(0.4)
Income tax expense from continuing operations	108.9	137.8	142.7
Continuing Operations [Member]
Current income taxes
Current income taxes, Federal	2.2	15.7	0
Current income taxes, State	(3.5)	1.1	0.9
Deferred income taxes
Deferred income taxes, Federal	98.6	102.9	124.0
Deferred income taxes, State	11.9	18.4	18.2
Current income taxes
Current income taxes, Federal	2.2	15.7	0
Current income taxes, State	(3.5)	1.1	0.9
Deferred income taxes
Deferred income taxes, Federal	98.6	102.9	124.0
Deferred income taxes, State	11.9	18.4	18.2
Amortization of investment tax credits	(0.3)	(0.3)	(0.4)
Income tax expense from continuing operations	108.9	137.8	142.7
Discontinued Operations [Member]
Current income taxes
Current income taxes, Federal	0	0	0
Current income taxes, State	0	0	0
Deferred income taxes
Deferred income taxes, Federal	(0.1)	14.9	4.4
Deferred income taxes, State	0	0.7	(0.3)
Income tax expense from discontinued operations	(0.1)	22.4	11.2
Current income taxes
Current income taxes, Federal	0	0	0
Current income taxes, Foreign	0	6.8	7.4
Current income taxes, State	0	0	0
Deferred income taxes
Deferred income taxes, Federal	(0.1)	14.9	4.4
Deferred income taxes, State	0	0.7	(0.3)
Current income taxes, Foreign	0	0	(0.3)
Tampa Electric Company [Member]
Current income taxes
Current income taxes, Federal	19.4	(19.5)	(30.7)
Current income taxes, State	1.3	5.6	2.9
Deferred income taxes
Deferred income taxes, Federal	99.8	141.2	155.6
Deferred income taxes, State	18.6	14.7	18.0
Current income taxes
Current income taxes, Federal	19.4	(19.5)	(30.7)
Current income taxes, State	1.3	5.6	2.9
Deferred income taxes
Deferred income taxes, Federal	99.8	141.2	155.6
Deferred income taxes, State	18.6	14.7	18.0
Amortization of investment tax credits	(0.3)	(0.3)	(0.4)
Income tax expense from continuing operations	$ 138.8	$ 141.7	$ 145.4

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2013

Other Comprehensive Income

10. Other Comprehensive Income

TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s pension plans:

Other Comprehensive Income
(millions)	Gross			Tax			Net
2013
Unrealized gain (loss) on cash flow hedges	$	1.0		$	(0.4	)	$	0.6
Reclassification from AOCI to net income		1.3			(0.5	)		0.8
Gain (Loss) on cash flow hedges		2.3			(0.9	)		1.4
Amortization of unrecognized benefit costs and other		23.6			(8.8	)		14.8
Recognized benefit costs due to settlement		2.6			(1.0	)		1.6
Total other comprehensive income (loss)	$	28.5		$	(10.7	)	$	17.8
2012
Unrealized (loss) gain on cash flow hedges	$	(7.4	)	$	2.8		$	(4.6	)
Reclassification from AOCI to net income		0.6			(0.2	)		0.4
(Loss) Gain on cash flow hedges		(6.8	)		2.6			(4.2	)
Amortization of unrecognized benefit costs and other (1)		(4.8	)		0.0			(4.8	)
Total other comprehensive (loss) income	$	(11.6	)	$	2.6		$	(9.0	)
2011
Unrealized gain (loss) on cash flow hedges	$	1.8		$	(0.6	)	$	1.2
Reclassification from AOCI to net income		(3.1	)		1.1			(2.0	)
(Loss) Gain on cash flow hedges		(1.3	)		0.5			(0.8	)
Amortization of unrecognized benefit costs and other		(7.9	)		3.3			(4.6	)
Recognized benefit costs due to settlement		0.9			(0.3	)		0.6
Total other comprehensive (loss) income	$	(8.3	)	$	3.5		$	(4.8	)

Accumulated Other Comprehensive Loss
(millions) As of Dec. 31,	2013			2012
Unrecognized pension losses and prior service credits (2)	$	(20.5	)	$	(32.9	)
Unrecognized other benefit gains, prior service costs and transition obligations (3)		15.1			11.1
Net unrealized losses from cash flow hedges (4)		(7.8	)		(9.2	)
Total accumulated other comprehensive loss	$	(13.2	)	$	(31.0	)

(1) Tax amounts include adjustments made related to Medicare Part D and changes to retirement plan. See Note 5 for further discussion.

(2) Net of tax benefit of $12.6 million and $20.1 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

(3) Net of tax expense of $9.1 million and $6.7 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

(4) Net of tax benefit of $4.9 million and $5.8 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

Tampa Electric Company [Member]

Other Comprehensive Income

8. Other Comprehensive Income

TEC reported the following OCI (loss) for the years ended Dec. 31, 2013, 2012 and 2011, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income
(millions)	Gross			Tax			Net
2013
Unrealized gain (loss) on cash flow hedges	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		1.4			(0.5	)		0.9
Gain (Loss) on cash flow hedges		1.4			(0.5	)		0.9
Total other comprehensive income (loss)	$	1.4		($	0.5	)	$	0.9
2012
Unrealized (loss) gain on cash flow hedges	($	8.0	)	$	3.1		($	4.9	)
Reclassification from AOCI to net income		1.4			(0.6	)		0.8
(Loss) Gain on cash flow hedges		(6.6	)		2.5			(4.1	)
Total other comprehensive (loss) income	($	6.6	)	$	2.5		($	4.1	)
2011
Unrealized gain (loss) on cash flow hedges	$	0.0		$	0.0		$	0.0
Reclassification from AOCI to net income		1.2			(0.5	)		0.7
Gain (Loss) on cash flow hedges		1.2			(0.5	)		0.7
Total other comprehensive income (loss)	$	1.2		($	0.5	)	$	0.7

Accumulated Other Comprehensive Loss
(millions) As of Dec. 31,	2013			2012
Net unrealized losses from cash flow hedges (1)	($	7.8	)	($	8.7	)
Total accumulated other comprehensive loss	($	7.8	)	($	8.7	)

(1) Net of tax benefit of $4.9 million and $5.5 million as of Dec. 31, 2013 and Dec. 31, 2012, respectively.

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Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events

24. Subsequent Events

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]

Subsequent Events

16. Subsequent Events

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.

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Common Stock - Summary of Stock Option Transactions (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Range of Option Prices, Minimum	$ 12.01
Range of Option Prices, Maximum	$ 19.01

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Fair Value Measurements - Schedule of Recurring Fair Value Measurements (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	$ 10.0	$ 0.2
Total Swap Liabilities	0.3	15.2
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	10.0	0.2
Total Swap Liabilities	0.3	15.2
Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0.2	0
Total Swap Liabilities	0.1	0.9
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 1 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	10.0	0.2
Total Swap Liabilities	0.3	15.2
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	9.8	0.2
Total Swap Liabilities	0.2	14.3
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	0.2	0
Total Swap Liabilities	0.1	0.9
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Level 3 [Member] | Diesel Fuel Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
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	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Level 2 [Member] | Natural Gas Derivatives [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	9.8	0.2
Total Swap Liabilities	0.2	14.3
Tampa Electric Company [Member] | Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Total Swap Assets	0	0
Total Swap Liabilities	0	0
Tampa Electric Company [Member] | Level 3 [Member] | 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

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

12. 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. In December 2010, two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim against PGS. The Court’s order is now final and not appealable. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

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

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

Environmental Protection Agency Section 114 Letter

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

Environmental Protection Agency Administrative Order

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Long-Term Commitments

TECO Energy has commitments under long-term leases, primarily for building space, capacity payments, office equipment and heavy equipment. Total rental expense for these leases, included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense – Mining related costs” and “Operation & maintenance other expense – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011, totaled $7.6 million, $8.1 million and $10.2 million, respectively. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:

Future Minimum Lease and Capacity Payments
(millions)	Capacity Payments		Operating Leases		Total
Year ended Dec. 31:
2014	$	14.8	$	5.0	$	19.8
2015		14.9		3.9		18.8
2016		14.6		2.6		17.2
2017		9.9		2.4		12.3
2018		10.1		2.2		12.3
Thereafter		0.0		13.4		13.4
Total future minimum payments	$	64.3	$	29.5	$	93.8

Guarantees and Letters of Credit

TECO Energy accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:

• Initial recognition and initial measurement of a liability, and/or

• Disclosure of specific details of the guarantee.

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

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

Guarantees-TECO Energy
(millions)					After (1)				Liabilities Recognized
Guarantees for the Benefit of:	2014		2015-2018		2018		Total		at Dec. 31, 2013
TECO Coal
Fuel purchase related (2)	$	0.8	$	0.7	$	4.0	$	5.5	$	1.5
Other subsidiaries
Guaranty under sale agreement (3)		0.0		5.0		0.0		5.0		5.0
Fuel sales and transportation (2)		10.0		0.0		91.8		101.8		0.1
Total	$	10.8	$	5.7	$	95.8	$	112.3	$	6.6
Letters of Credit-Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2014		2015-2018		2018		Total		at Dec. 31, 2013
Tampa Electric (2)	$	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 Dec. 31, 2013. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.

(3) The liability recognized relates to an indemnification provision for an uncertain tax position at TCAE that was provided for in the purchase agreement. See Note 19 for additional information.

Financial Covenants

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 Dec. 31, 2013, TECO Energy, TECO Finance, TEC, and the other operating companies were in compliance with all required financial covenants.

Tampa Electric Company [Member]

Commitments and Contingencies

9. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on 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. In December 2010, two commercial PGS customers filed a purported class action in Lee County Circuit Court, Florida against PGS on behalf of PGS commercial customers affected by the outage, seeking damages for loss of revenue and other costs related to the gas outage. Posen Construction, Inc., the company conducting construction at the site where the incident occurred, is also a defendant in the action. In June 2013, the court denied the plaintiffs’ motion for class certification and dismissed the plaintiffs’ underlying claim against PGS. The Court’s order is now final and not appealable. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS, Posen Construction, Inc. and a PGS contractor involved in the project, seeking damages for his injuries, also remains pending.

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

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

Environmental Protection Agency Section 114 Letter

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

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

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

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

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

Long-Term Commitments

TEC has commitments under long-term leases, primarily for building space, capacity payments, office equipment and heavy equipment. Total rental expense for these leases, included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2013, 2012 and 2011, totaled $2.3 million, $2.2 million and $2.2 million, respectively. The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year and capacity payments under PPAs at Dec. 31, 2013:

Future Minimum Lease and Capacity Payments
(millions)	Capacity Payments		Operating Leases		Total
Year ended Dec. 31:
2014	$	14.8	$	2.3	$	17.1
2015		14.9		2.3		17.2
2016		14.6		2.2		16.8
2017		9.9		2.2		12.1
2018		10.1		2.2		12.3
Thereafter		0.0		13.4		13.4
Total future minimum payments	$	64.3	$	24.6	$	88.9

Guarantees and Letters of Credit

TEC accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:

• Initial recognition and initial measurement of a liability, and/or

• Disclosure of specific details of the guarantee.

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

At Dec. 31, 2013, TEC was not obligated under guarantees, but had $0.7 million of letters of credit outstanding.

Letters of Credit - Tampa Electric Company
(millions) Letters of Credit for the Benefit of:	2014		2015-2018		After (1) 2018		Total		Liabilities Recognized at Dec. 31, 2013
Tampa Electric (2)
Letters of credit	$	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 Dec. 31, 2013. The obligations under these letters of credit include net accounts payable and net derivative liabilities.

Financial Covenants

In order to utilize their respective bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2013, TEC was in compliance with all required financial covenants.

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Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred tax liabilities
Property related	$ 1,164.2	$ 1,023.3
Deferred fuel	1.6	11.3
Pension	52.8	43.0
Total deferred tax liabilities	1,218.6	1,077.6
Deferred tax assets
Alternative minimum tax credit carryforward	213.0	211.8
Loss and credit carryforwards	479.8	473.2
Other postretirement benefits	68.9	68.0
Other	113.2	113.0
Total deferred tax assets	874.9	866.0
Valuation allowance	0	(3.0)
Total deferred tax assets, net of valuation allowance	874.9	863.0
Total deferred tax liability, net	343.7	214.6
Less: Current portion of deferred tax asset	(100.3)	(63.3)
Long-term portion of deferred tax liability, net	444.0	277.9
Tampa Electric Company [Member]
Deferred tax liabilities
Property related	1,166.4	1,016.2
Deferred fuel	1.6	11.3
Pension	43.2	36.7
Total deferred tax liabilities	1,281.7	1,193.0
Pension and postretirement benefits	70.5	106.6
Other	0	22.2
Deferred tax assets
Other	4.4	0
Total deferred tax assets	196.8	232.1
Medical benefits	50.9	49.0
Insurance reserves	29.1	31.1
Investment tax credits	5.3	5.5
Hedging activities	4.9	5.5
Pension and postretirement benefits	70.5	106.6
Unbilled revenue	12.1	14.8
Capitalized energy conservation assistance costs	19.6	19.6
Total deferred tax liability, net	1,084.9	960.9
Less: Current portion of deferred tax asset	(29.4)	(20.0)
Long-term portion of deferred tax liability, net	$ 1,114.3	$ 980.9

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Related Parties - Schedule of Related Parties (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Natural gas sales, net	$ 18.3	$ 11.7	$ 0
Administrative and general, net	27.2	23.4	17.5
Tampa Electric Company [Member]
Related Party Transaction [Line Items]
Accounts receivable	1.3	4.7
Accounts payable	9.8	7.9
Taxes receivable	54.9	22.1
Taxes payable	$ 0.4	$ 3.2

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities
Net income	$ 197.7	$ 212.7	$ 272.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	329.5	337.7	324.6
Deferred income taxes	110.4	136.9	146.0
Investment tax credits	(0.3)	(0.3)	(0.4)
Allowance for other funds used during construction	(6.3)	(2.6)	(1.0)
Non-cash stock compensation	13.5	12.0	9.1
(Gain) loss on sales of business/assets, pretax	(1.6)	18.5	(0.5)
Deferred recovery clauses	(6.2)	(8.9)	(9.0)
Asset impairment, pretax	0	17.2	0
Receivables, less allowance for uncollectibles	(4.5)	37.7	5.7
Inventories	1.1	(2.4)	23.5
Prepayments and other current assets	(2.2)	(2.0)	(2.8)
Taxes accrued	1.4	12.1	(5.7)
Interest accrued	(1.3)	(5.9)	0.3
Accounts payable	35.9	(1.3)	(42.6)
Other	(8.5)	(4.7)	34.3
Cash flows from operating activities	658.6	756.7	754.1
Cash flows from investing activities
Capital expenditures	(532.4)	(505.1)	(454.1)
Allowance for other funds used during construction	6.3	2.6	1.0
Net proceeds from sales of business/assets	4.3	194.4	3.5
Restricted cash	0	8.9	0
Other investing activities	0	0	14.4
Cash flows used in investing activities	(521.8)	(299.2)	(435.2)
Cash flows from financing activities
Dividends	(191.2)	(190.4)	(183.2)
Proceeds from the sale of common stock	6.7	3.9	7.0
Proceeds from long-term debt issuance	0	538.1	0
Repayment of long-term debt/Purchase in lieu of redemption	(51.6)	(650.4)	(153.6)
Change in short-term debt	84.0	0	(12.0)
Other financing activities	0	(2.2)	(0.6)
Cash flows used in financing activities	(152.1)	(301.0)	(342.4)
Net (decrease) increase in cash and cash equivalents	(15.3)	156.5	(23.5)
Cash and cash equivalents at beginning of the year	200.5	44.0	67.5
Cash and cash equivalents at end of the year	185.2	200.5	44.0
Supplemental disclosure of cash flow information
Interest	161.0	188.4	191.6
Income taxes paid	1.8	7.2	9.4
Tampa Electric Company [Member]
Cash flows from operating activities
Net income	225.6	227.2	235.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	290.3	288.2	270.5
Deferred income taxes	118.4	155.9	173.6
Investment tax credits	(0.3)	(0.3)	(0.4)
Allowance for other funds used during construction	(6.3)	(2.6)	(1.0)
(Gain) loss on sales of business/assets, pretax	0	(0.2)	(0.3)
Deferred recovery clauses	(6.2)	(8.9)	(9.0)
Receivables, less allowance for uncollectibles	(13.8)	1.6	47.8
Inventories	(9.0)	4.1	12.6
Prepayments	(1.0)	(1.0)	(0.5)
Taxes accrued	(34.3)	(5.7)	7.9
Interest accrued	(0.9)	(8.3)	1.0
Accounts payable	34.8	12.4	(42.2)
Other	(1.8)	5.2	29.4
Cash flows from operating activities	595.5	667.6	724.7
Cash flows from investing activities
Capital expenditures	(507.6)	(459.0)	(386.8)
Allowance for other funds used during construction	6.3	2.6	1.0
Net proceeds from sale of assets	0.1	0.3	2.8
Cash flows used in investing activities	(501.2)	(456.1)	(383.0)
Cash flows from financing activities
Dividends	(222.1)	(228.3)	(240.7)
Proceeds from the sale of common stock	60.0	118.0	0
Proceeds from long-term debt issuance	0	538.1	0
Repayment of long-term debt/Purchase in lieu of redemption	(51.6)	(608.0)	(78.8)
Change in short-term debt	84.0	0	(12.0)
Cash flows used in financing activities	(129.7)	(180.2)	(331.5)
Net (decrease) increase in cash and cash equivalents	(35.4)	31.3	10.2
Cash and cash equivalents at beginning of the year	45.2	13.9	3.7
Cash and cash equivalents at end of the year	9.8	45.2	13.9
Supplemental disclosure of cash flow information
Interest	102.4	128.1	129.0
Income taxes paid	$ 56.4	$ (9.7)	$ (31.1)

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Allowance for uncollectibles	$ 4.7	$ 4.2
Common equity, shares authorized	400,000,000	400,000,000
Common equity, par value	$ 1	$ 1
Common equity, shares outstanding	217,300,000	216,600,000
Tampa Electric Company [Member]
Allowance for uncollectibles	$ 2.0	$ 1.5
Common equity, shares authorized	25,000,000	25,000,000
Common equity, shares outstanding	10	10

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Employee Postretirement Benefits

12 Months Ended

Dec. 31, 2013

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Pension Benefits

TECO Energy has a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In July 2012, the President signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under MAP-21.

The qualified pension plan’s actuarial value of assets, including credit balance, was 96.7% of the Pension Protection Act funded target as of Jan. 1, 2013 and is estimated at 98.2% of the Pension Protection Act funded target as of Jan. 1, 2014.

Amounts disclosed for pension benefits also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2012. TEC is amortizing the regulatory asset over the remaining average service life of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. Prior to this, the company received subsidy payments under Medicare Part D for its post-65 retiree prescription drug plan.

Obligations and Funded Status

TECO Energy recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC. The results of operations are not impacted. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in the Consolidated Balance Sheets for 2013 and 2012.

Obligations and Funded Status	Pension Benefits						Other Benefits
(millions)	2013			2012			2013			2012
Change in benefit obligation
Net benefit obligation at beginning of year	$	715.0		$	646.4		$	230.3		$	216.5
Service cost		18.2			17.0			2.5			2.4
Interest cost		28.9			30.1			9.3			10.1
Plan participants’ contributions		0.0			0.0			2.9			3.7
Plan amendments		0.0			0.0			0.0			(5.2	)
Actuarial loss (gain)		(50.4	)		54.7			(22.1	)		16.3
Gross benefits paid		(43.1	)		(33.2	)		(15.0	)		(14.5	)
Settlements		(2.6	)		0.0			0.0			0.0
Federal subsidy on benefits paid		n/a			n/a			0.2			1.0
Net benefit obligation at end of year	$	666.0		$	715.0		$	208.1		$	230.3
Change in plan assets
Fair value of plan assets at beginning of year	$	529.1		$	467.6		$	0.0		$	0.0
Actual return on plan assets		63.7			57.9			0.0			0.0
Employer contributions		45.9			36.8			11.9			9.8
Plan participants’ contributions		0.0			0.0			2.9			3.7
Settlements		(2.6	)		0.0			0.0			0.0
Net benefits paid		(43.1	)		(33.2	)		(14.8	)		(13.5	)
Fair value of plan assets at end of year	$	593.0		$	529.1		$	0.0		$	0.0
Funded status
Fair value of plan assets (1)	$	593.0		$	529.1		$	0.0		$	0.0
Less: Benefit obligation (PBO/APBO)		666.0			715.0			208.1			230.3
Funded status at end of year		(73.0	)		(185.9	)		(208.1	)		(230.3	)
Unrecognized net actuarial loss		173.1			270.3			19.7			42.7
Unrecognized prior service (benefit) cost		(0.4	)		(0.7	)		(0.7	)		(1.0	)
Net amount required to be recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)
Amounts recognized in balance sheet
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(3.3	)		(5.3	)		(13.3	)		(13.1	)
Deferred credits and other liabilities		(69.7	)		(180.6	)		(194.8	)		(217.2	)
Accumulated other comprehensive loss (income), pretax		33.1			53.1			(24.2	)		(17.9	)
Net amount recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

Amounts recognized in accumulated other comprehensive income

	Pension Benefits				Other Benefits
(millions)	2013		2012		2013			2012
Net actuarial loss (gain)	$	32.7	$	52.7	$	(23.8	)	$	(17.2	)
Prior service cost (credit)		0.4		0.4		(0.4	)		(0.7	)
Amount recognized	$	33.1	$	53.1	$	(24.2	)	$	(17.9	)

The accumulated benefit obligation for all defined benefit pension plans was $624.1 million at Dec. 31, 2013 and $664.7 million at Dec. 31, 2012. The projected benefit obligation for the other postretirement benefits plan was $208.1 million at Dec. 31, 2013 and $230.3 million at Dec. 31, 2012.

Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2013			2012			2013			2012
Discount rate		5.118	%		4.196	%		5.096	%		4.180	%
Rate of compensation increase - weighted		3.73	%		3.76	%		3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			7.25	%		7.50	%
Ultimate rate		n/a			n/a			4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			2025			2025

A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:

(millions)	1% Increase		1% Decrease
Effect on postretirement benefit obligation	$	6.8	$	(6.1	)

The discount rate assumption used to determine the Dec. 31, 2013 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

	Pension Benefits									Other Benefits
Net periodic benefit cost
(millions)	2013			2012			2011			2013			2012			2011
Service cost	$	18.2		$	17.0		$	16.0		$	2.4		$	2.4		$	2.1
Interest cost		28.9			30.1			30.9			9.3			10.1			11.1
Expected return on plan assets		(38.4	)		(37.1	)		(38.4	)		0.0			0.0			0.0
Amortization of:
Actuarial loss		20.5			15.3			11.3			1.0			0.1			0.1
Prior service (benefit) cost		(0.4	)		(0.4	)		(0.4	)		(0.3	)		0.8			0.8
Transition obligation		0.0			0.0			0.0			0.0			1.8			2.3
Settlement loss		1.0			0.0			0.9			0.0			0.0			0.0
Net periodic benefit cost	$	29.8		$	24.9		$	20.3		$	12.4		$	15.2		$	16.4
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and regulatory assets
(millions)	2013			2012			2011			2013			2012			2011
Prior service cost	$	0.0		$	0.0		$	0.0		$	0.0		$	(5.2	)	$	0.0
Net loss (gain)		(75.7	)		34.0			43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)		(21.5	)		(15.3	)	$	(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost		0.4			0.4			0.4			0.3			(0.8	)		(0.8	)
Transition obligation		0.0			0.0			0.0			0.0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets	$	(96.8	)	$	19.1		$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	(67.0	)	$	44.0		$	51.8		$	(3.9	)	$	23.6		$	5.7

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $2.5 million and $0.1 million, respectively. The estimated prior service credit for the other postretirement benefit plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.2 million.

In addition, the estimated net loss and prior service credit for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $10.5 million and $0.5 million, respectively. There will be no remaining net loss for the other postretirement benefit plan that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Discount rate		4.196	%		4.797	%		5.300	%		4.180	%		4.744	%		5.250	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.75	%		n/a			n/a			n/a
Rate of compensation increase		3.76	%		3.83	%		3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Initial rate		n/a			n/a			n/a			7.50	%		7.75	%		8.00	%
Ultimate rate		n/a			n/a			n/a			4.50	%		4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			n/a			2025			2025			2023

The discount rate assumption used to determine the 2013 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2013, TECO Energy’s pension plan experienced actual asset returns of approximately 12%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:

(millions)	1% Increase		1% Decrease
Effect on periodic cost	$	0.3	$	(0.3	)

Pension Plan Assets

Pension plan assets (plan assets) are primarily invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target Allocation	Actual Allocation, End of Year
Asset Category		2013			2012
Equity securities	48%-54%		54	%		55	%
Fixed income securities	46%-52%		46	%		45	%
Total	100%		100	%		100	%

The company reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company expects to take additional steps to more closely match plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and Dec. 31, 2012.

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2013
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	44.7		$	0.0		$	0.0	$	44.7
Accounts payable		(40.8	)		0.0			0.0		(40.8	)
Cash equivalents
Short term investment funds (STIFs)		7.9			0.0			0.0		7.9
Treasury bills (T bills)		0.0			0.3			0.0		0.3
Repurchase agreement		0.0			8.8			0.0		8.8
Commercial paper		0.0			0.4			0.0		0.4
Money markets		0.0			1.5			0.0		1.5
Total cash equivalents		7.9			11.0			0.0		18.9
Equity securities
Common stocks		91.6			0.0			0.0		91.6
American depository receipts (ADRs)		3.0			0.0			0.0		3.0
Real estate investment trusts (REITs)		1.7			0.0			0.0		1.7
Preferred stock		0.0			0.8			0.0		0.8
Mutual funds		172.6			0.0			0.0		172.6
Commingled fund		0.0			50.0			0.0		50.0
Total equity securities		268.9			50.8			0.0		319.7
Fixed income securities
Municipal bonds		0.0			7.3			0.0		7.3
Government bonds		0.0			35.7			0.0		35.7
Corporate bonds		0.0			19.6			0.0		19.6
Asset backed securities (ABS)		0.0			0.4			0.0		0.4
Mortgage-backed securities (MBS), net short sales		0.0			6.7			0.0		6.7
Collateralized mortgage obligations (CMOs)		0.0			2.3			0.0		2.3
Mutual fund		0.0			85.1			0.0		85.1
Commingled fund		0.0			94.1			0.0		94.1
Total fixed income securities		0.0			251.2			0.0		251.2
Derivatives
Short futures		0.0			0.2			0.0		0.2
Swaps		0.0			(0.9	)		0.0		(0.9	)
Purchased options (swaptions)		0.0			0.2			0.0		0.2
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.9	)		0.0		(0.9	)
Miscellaneous		0.0			0.2			0.0		0.2
Total	$	280.7		$	312.3		$	0.0	$	593.0

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2012
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	64.8		$	0.0		$	0.0	$	64.8
Accounts payable		(72.8	)		0.0			0.0		(72.8	)
Cash equivalents
STIFs		9.0			0.0			0.0		9.0
T bills		0.0			0.6			0.0		0.6
Repurchase agreements		0.0			23.1			0.0		23.1
CDs		0.0			1.1			0.0		1.1
Commercial paper		0.0			0.9			0.0		0.9
Money markets		0.0			0.6			0.0		0.6
Total cash equivalents		9.0			26.3			0.0		35.3
Equity securities
Common stocks		125.3			0.0			0.0		125.3
ADRs		6.2			0.0			0.0		6.2
REITs		2.0			0.0			0.0		2.0
Preferred stocks		0.0			0.8			0.0		0.8
Equity mutual funds		153.4			0.0			0.0		153.4
Total equity securities		286.9			0.8			0.0		287.7
Fixed income securities
Municipal bonds		0.0			8.0			0.0		8.0
Government bonds		0.0			53.0			0.0		53.0
Corporate bonds		0.0			19.8			0.0		19.8
ABS		0.0			0.5			0.0		0.5
MBS		0.0			17.6			0.0		17.6
CMBS		0.0			0.3			0.0		0.3
CMOs		0.0			2.5			0.0		2.5
Fixed income mutual fund		0.0			63.7			0.0		63.7
Fixed income commingled fund		0.0			49.4			0.0		49.4
Total fixed income securities		0.0			214.8			0.0		214.8
Derivatives
Swaps		0.0			(0.5	)		0.0		(0.5	)
Purchased options (swaptions)		0.0			0.1			0.0		0.1
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.8	)		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.1
Total	$	287.9		$	241.2		$	0.0	$	529.1

• The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.

• The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.

• The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.

• The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.

• T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.

• The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.

• The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.

• The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.

• The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

Other Postretirement Benefit Plan Assets

There are no assets associated with the company’s other postretirement benefits plan.

Contributions

The company’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $42.0 million and $35.5 million of contributions to this plan in 2013 and 2012, respectively, which met the minimum funding requirements for both 2013 and 2012. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2014 to be $47.5 million and expects to make contributions from 2015 to 2018 in the range of $4.0 to $48.0 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.

The SERP is funded annually to meet the benefit obligations. The company made contributions of $2.6 million and $1.3 million to this plan in 2013 and 2012, respectively. In 2014, the company expects to make a contribution of about $3.3 million to this plan.

The other postretirement benefits are funded annually to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2014, the company expects to make a contribution of about $13.3 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments
(including projected service and net of employee contributions)
(millions)	Pension Benefits		Other Postretirement Benefits
2014	$	53.5	$	13.3
2015		50.9		13.9
2016		55.3		14.6
2017		55.9		15.2
2018		58.3		15.7
2019-2023		298.6		81.9

Defined Contribution Plan

The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective April 2013, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31, 2013, 2012 and 2011, the company and its subsidiaries recognized expense totaling $11.3 million, $7.0 million and $9.0 million, respectively, related to the matching contributions made to this plan.

Black Lung Liability

TECO Coal is required by federal and state statutes to provide benefits to terminated, retired or (under state statutes) qualifying active employees for benefits related to black lung disease. TECO Coal is self-insured for black lung related claims. Annual expense is recorded for black lung obligations as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee’s applicable term of service. At Dec. 31, 2013 and 2012, TECO Coal had an actuarially-determined black lung liability of $24.5 million and $27.1 million, respectively. TECO Coal recognized expense related to the black lung liability of $2.2 million, $1.8 million, and $1.7 million for 2013, 2012 and 2011, respectively.

Tampa Electric Company [Member]

Employee Postretirement Benefits

5. Employee Postretirement Benefits

Pension Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy, including a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2012, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In July 2012, the President signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under MAP-21.

The qualified pension plan’s actuarial value of assets, including credit balance, was 96.7% of the Pension Protection Act funded target as of Jan. 1, 2013 and is estimated at 98.2% of the Pension Protection Act funded target as of Jan. 1, 2014.

Amounts disclosed for pension benefits also include the unfunded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. This amount was trued up in 2012. TEC is amortizing the regulatory asset over the remaining average service life of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts. Prior to this, the company received subsidy payments under Medicare Part D for its post-65 retiree prescription drug plan.

Obligations and Funded Status

TEC recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted. Below is the detail of the change in benefit obligations, change in plan assets, unfunded liability and amounts recognized in TECO Energy’s Consolidated Balance Sheets for 2013 and 2012.

TECO Energy	Pension Benefits						Other Benefits
Obligations and Funded Status
(millions)	2013			2012			2013			2012
Change in benefit obligation
Net benefit obligation at beginning of year	$	715.0		$	646.4		$	230.3		$	216.5
Service cost		18.2			17.0			2.5			2.4
Interest cost		28.9			30.1			9.3			10.1
Plan participants’ contributions		0.0			0.0			2.9			3.7
Plan amendments		0.0			0.0			0.0			(5.2	)
Actuarial loss (gain)		(50.4	)		54.7			(22.1	)		16.3
Gross benefits paid		(43.1	)		(33.2	)		(15.0	)		(14.5	)
Settlements		(2.6	)		0.0			0.0			0.0
Federal subsidy on benefits paid		n/a			n/a			0.2			1.0
Net benefit obligation at end of year	$	666.0		$	715.0		$	208.1		$	230.3
Change in plan assets
Fair value of plan assets at beginning of year	$	529.1		$	467.6		$	0.0		$	0.0
Actual return on plan assets		63.7			57.9			0.0			0.0
Employer contributions		45.9			36.8			11.9			9.8
Plan participants’ contributions		0.0			0.0			2.9			3.7
Settlements		(2.6	)		0.0			0.0			0.0
Gross benefits paid		(43.1	)		(33.2	)		(14.8	)		(13.5	)
Fair value of plan assets at end of year	$	593.0		$	529.1		$	0.0		$	0.0
Funded status
Fair value of plan assets (1)	$	593.0		$	529.1		$	0.0		$	0.0
Less: Benefit obligation (PBO/APBO)		666.0			715.0			208.1			230.3
Funded status at end of year		(73.0	)		(185.9	)		(208.1	)		(230.3	)
Unrecognized net actuarial loss		173.1			270.3			19.7			42.7
Unrecognized prior service (benefit) cost		(0.4	)		(0.7	)		(0.7	)		(1.0	)
Unrecognized net transition obligation		0.0			0.0			0.0			0.0
Net amount required to be recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)
Amounts recognized in balance sheet
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(3.3	)		(5.3	)		(13.3	)		(13.1	)
Deferred credits and other liabilities		(69.7	)		(180.6	)		(194.8	)		(217.2	)
Accumulated other comprehensive loss (income), pretax		33.1			53.1			(24.2	)		(17.9	)
Net amount recognized at end of year	$	99.7		$	83.7		($	189.1	)	($	188.6	)

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

Tampa Electric Company	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2013			2012			2013			2012
Regulatory assets	$	139.6		$	216.5		$	43.2		$	59.6
Accrued benefit costs and other current liabilities		(0.9	)		(0.9	)		(10.8	)		(10.6	)
Deferred credits and other liabilities		(50.1	)		(139.8	)		(158.3	)		(174.2	)
	$	88.6		$	75.8		$	(125.9	)	$	(125.2	)

The accumulated benefit obligation for TECO Energy Consolidated defined benefit pension plans was $624.1 million at Dec. 31, 2013 and $664.7 million at Dec. 31, 2012. The projected benefit obligation for the other postretirement benefits plan was $208.1 million at Dec. 31, 2013 and $230.3 million at Dec. 31, 2012.

Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2013			2012			2013			2012
Discount rate		5.118	%		4.196	%		5.096	%		4.180	%
Rate of compensation increase-weighted average		3.73	%		3.76	%		3.71	%		3.74	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			7.25	%		7.50	%
Ultimate rate		n/a			n/a			4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			2025			2025

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:

(millions)	1% Increase		1% Decrease
Effect on postretirement benefit obligation	$	5.6	$	(5.0	)

The discount rate assumption used to determine the Dec. 31, 2013 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

Components of TECO Energy Consolidated Net Periodic Benefit Cost

	Pension Benefits									Other Benefits
(millions)	2013			2012			2011			2013			2012		2011
Service cost	$	18.2		$	17.0		$	16.0		$	2.4		$	2.4	$	2.1
Interest cost		28.9			30.1			30.9			9.3			10.1		11.1
Expected return on plan assets		(38.4	)		(37.1	)		(38.4	)		0.0			0.0		0.0
Amortization of:
Actuarial loss		20.5			15.3			11.3			1.0			0.1		0.1
Prior service (benefit) cost		(0.4	)		(0.4	)		(0.4	)		(0.3	)		0.8		0.8
Transition obligation		0.0			0.0			0.0			0.0			1.8		2.3
Settlement loss		1.0			0.0			0.9			0.0			0.0		0.0
Net periodic benefit cost	$	29.8		$	24.9		$	20.3		$	12.4		$	15.2	$	16.4

Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets

(millions)	2013			2012			2011			2013			2012			2011
Prior service cost	$	0.0		$	0.0		$	0.0		$	0.0		$	(5.2	)	$	0.0
Net loss (gain)		(75.7	)		34.0			43.3			(15.6	)		16.3			(7.4	)
Amortization of:
Actuarial gain (loss)		(21.5	)		(15.3	)		(12.2	)		(1.0	)		(0.1	)		(0.1	)
Prior service (benefit) cost		0.4			0.4			0.4			0.3			(0.8	)		(0.8	)
Transition obligation		0.0			0.0			0.0			0.0			(1.8	)		(2.4	)
Total recognized in OCI and regulatory assets	$	(96.8	)	$	19.1		$	31.5		$	(16.3	)	$	8.4		$	(10.7	)
Total Recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets	$	(67.0	)	$	44.0		$	51.8		$	(3.9	)	$	23.6		$	5.7

TEC’s portion of the net periodic benefit costs for pension benefits was $21.7 million, $18.3 million and $13.1 million for 2013, 2012 and 2011, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $10.0 million, $12.4 million and $10.0 million for 2013, 2012 and 2011, respectively.

The estimated net loss and prior service credit for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year are $10.5 million and $0.5 million, respectively. There will be no remaining net loss for the other postretirement benefit plan that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2013			2012			2011			2013			2012			2011
Discount rate		4.196	%		4.797	%		5.30	%		4.180	%		4.744	%		5.25	%
Expected long-term return on plan assets		7.50	%		7.50	%		7.75	%		n/a			n/a			n/a
Rate of compensation increase		3.76	%		3.83	%		3.88	%		3.74	%		3.82	%		3.87	%
Healthcare cost trend rate
Immediate rate		n/a			n/a			n/a			7.50	%		7.75	%		8.00	%
Ultimate rate		n/a			n/a			n/a			4.50	%		4.50	%		4.50	%
Year rate reaches ultimate		n/a			n/a			n/a			2025			2025			2023

The discount rate assumption used to determine the 2013 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2013, TECO Energy’s pension plan experienced actual asset returns of approximately 12%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:

(millions)	1% Increase		1% Decrease
Effect on periodic cost	$	0.2	$	(0.2	)

Pension Plan Assets

Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target Allocation	Actual Allocation, End of Year
Asset Category		2013			2012
Equity securities	48%-54%		54	%		55	%
Fixed income securities	46%-52%		46	%		45	%
Total	100%		100	%		100	%

TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy, Inc. expects to take additional steps to more closely match plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). JP Morgan measures fair value using the procedures set forth below for all investments. When available, JP Morgan uses quoted market prices on investments traded on an exchange to determine fair value and classifies such items as Level 1. In some cases where a market exchange price is available, but the investments are traded in a secondary market, JP Morgan makes use of acceptable practical expedients to calculate fair value, and the company classifies these items as Level 2.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’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 cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2013 and 2012.

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2013
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	44.7		$	0.0		$	0.0	$	44.7
Accounts payable		(40.8	)		0.0			0.0		(40.8	)
Cash equivalents
STIFs		7.9			0.0			0.0		7.9
T bills		0.0			0.3			0.0		0.3
Repurchase agreements		0.0			8.8			0.0		8.8
Commercial paper		0.0			0.4			0.0		0.4
Money markets		0.0			1.5			0.0		1.5
Total cash equivalents		7.9			11.0			0.0		18.9
Equity securities
Common stocks		91.6			0.0			0.0		91.6
ADRs		3.0			0.0			0.0		3.0
REITs		1.7			0.0			0.0		1.7
Preferred stock		0.0			0.8			0.0		0.8
Mutual funds		172.6			0.0			0.0		172.6
Commingled fund		0.0			50.0			0.0		50.0
Total equity securities		268.9			50.8			0.0		319.7
Fixed income securities
Municipal bonds		0.0			7.3			0.0		7.3
Government bonds		0.0			35.7			0.0		35.7
Corporate bonds		0.0			19.6			0.0		19.6
ABS		0.0			0.4			0.0		0.4
MBS, net short sales		0.0			6.7			0.0		6.7
CMOs		0.0			2.3			0.0		2.3
Mutual funds		0.0			85.1			0.0		85.1
Commingled fund		0.0			94.1			0.0		94.1
Total fixed income securities		0.0			251.2			0.0		251.2
Derivatives
Short futures		0.0			0.2			0.0		0.2
Swaps		0.0			(0.9	)		0.0		(0.9	)
Purchased options (swaptions)		0.0			0.2			0.0		0.2
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.9	)		0.0		(0.9	)
Miscellaneous		0.0			0.2			0.0		0.2
Total	$	280.7		$	312.3		$	0.0	$	593.0

Pension Plan Investments
(millions)	At Fair Value as of Dec. 31, 2012
	Level 1			Level 2			Level 3		Total
Accounts receivable	$	64.8		$	0.0		$	0.0	$	64.8
Accounts payable		(72.8	)		0.0			0.0		(72.8	)
Cash equivalents
STIFs		9.0			0.0			0.0		9.0
T bills		0.0			0.6			0.0		0.6
Repurchase agreements		0.0			23.1			0.0		23.1
CDs		0.0			1.1			0.0		1.1
Commercial paper		0.0			0.9			0.0		0.9
Money markets		0.0			0.6			0.0		0.6
Total cash equivalents		9.0			26.3			0.0		35.3
Equity securities
Common stocks		125.3			0.0			0.0		125.3
ADRs		6.2			0.0			0.0		6.2
REITs		2.0			0.0			0.0		2.0
Preferred stocks		0.0			0.8			0.0		0.8
Equity mutual funds		153.4			0.0			0.0		153.4
Total equity securities		286.9			0.8			0.0		287.7
Fixed income securities
Municipal bonds		0.0			8.0			0.0		8.0
Government bonds		0.0			53.0			0.0		53.0
Corporate bonds		0.0			19.8			0.0		19.8
ABS		0.0			0.5			0.0		0.5
MBS		0.0			17.6			0.0		17.6
CMBS		0.0			0.3			0.0		0.3
CMOs		0.0			2.5			0.0		2.5
Fixed income mutual fund		0.0			63.7			0.0		63.7
Fixed income commingled fund		0.0			49.4			0.0		49.4
Total fixed income securities		0.0			214.8			0.0		214.8
Derivatives
Swaps		0.0			(0.5	)		0.0		(0.5	)
Purchased options (swaptions)		0.0			0.1			0.0		0.1
Written options (swaptions)		0.0			(0.4	)		0.0		(0.4	)
Total derivatives		0.0			(0.8	)		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.1
Total	$	287.9		$	241.2		$	0.0	$	529.1

• The primary pricing inputs in determining the fair value of the Level 1 assets, excluding the mutual funds and STIF, are closing quoted prices in active markets.

• The STIF is valued at net asset value (NAV) as determined by JP Morgan. Shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV, making this a Level 1 asset.

• The primary pricing inputs in determining the Level 1 mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV, making these Level 1 assets.

• The repurchase agreements and money markets are valued at cost due to their short term nature. Additionally, repurchase agreements are backed by collateral.

• T bills and commercial paper are valued using benchmark yields, reported trades, broker dealer quotes, and benchmark securities.

• The primary pricing inputs in determining the fair value of the preferred stock is the price of underlying and common stock of the same issuer, average life, and benchmark yields.

• The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes. The fund holds primarily international equity securities that are actively traded in OTC markets. The fund honors subscription and redemption activity on an “as of” basis.

• The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. Treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMOs are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. Commercial MBS are priced using payment information and yields.

• The primary pricing input in determining the fair value of the Level 2 mutual fund is its NAV. However, since this mutual fund is an unregistered open-ended mutual fund, it is a Level 2 asset.

• The fixed income commingled fund is a private fund valued at NAV as determined by a third party at year end. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

• Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

• Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

• Options are valued using the bid-ask spread and the last price.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s other postretirement benefits plan.

Contributions

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy made $42.0 million of contributions to this plan in 2013 and $35.5 million in 2012, which met the minimum funding requirements for both 2013 and 2012. TEC’s portion of the contribution in 2013 was $33.5 million and in 2012 was $27.9 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TECO Energy estimates its contribution in 2014 to be $47.5 million, with TEC’s portion being $38.4 million. TECO Energy estimates it will make annual contributions from 2015 to 2018 ranging from $4.0 to $48.0 million per year based on current assumptions, with TEC’s portion to range from $3 million to $39 million. These amounts are in excess of the minimum funding required under ERISA guidelines.

The SERP is funded annually to meet the benefit obligations. TECO Energy made contributions of $2.6 million and $1.3 million to this plan in 2013 and 2012, respectively. TEC’s portion of the contributions in 2013 and 2012 were $1.0 million and $0.6 million, respectively. In 2014, TECO Energy expects to make a contribution of about $3.3 million to this plan. TEC’s portion of the expected contribution is about $0.9 million.

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2014, TECO Energy expects to make a contribution of about $13.3 million. TEC’s portion of the expected contribution is $10.8 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments - TECO Energy
(including projected service and net of employee contributions)			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2014	$	53.5	$	13.3
2015		50.9		13.9
2016		55.3		14.6
2017		55.9		15.2
2018		58.3		15.7
2019-2023		298.6		81.9

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Employer matching contributions are 60% of eligible participant contributions with additional incentive match of up to 40% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended Dec. 31, 2013, 2012 and 2011, TECO Energy and its subsidiaries recognized expense totaling $11.3 million, $7.0 million and $9.0 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled $9.1 million, $6.0 million and $5.8 million for 2013, 2012 and 2011, respectively.

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Earnings Per Share - Schedule of Earnings Per Share (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basic earnings per share
Net income from continuing operations	$ 42.1	$ 62.9	$ 51.6	$ 41.2	$ 45.6	$ 90.2	$ 65.6	$ 44.6	$ 197.8	$ 246.0	$ 250.8
Amount allocated to nonvested participating shareholders									(0.6)	(0.8)	(1.3)
Income before discontinued operations available to common shareholders - Basic									197.2	245.2	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net									(0.1)	(33.3)	21.8
Amount allocated to nonvested participating shareholders									0	0.1	(0.1)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic									(0.1)	(33.2)	21.7
Net income attributable to TECO Energy	42.0	62.8	51.4	41.5	45.1	44.0	73.1	50.5	197.7	212.7	272.6
Amount allocated to nonvested participating shareholders									(0.6)	(0.7)	(1.4)
Net income attributable to TECO Energy available to common shareholders - Basic									197.1	212.0	271.2
Average common shares outstanding - Basic									215.0	214.3	213.6
Earnings per share from continuing operations available to common shareholders - Basic	$ 0.20	$ 0.29	$ 0.24	$ 0.19	$ 0.21	$ 0.42	$ 0.30	$ 0.21	$ 0.92	$ 1.14	$ 1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic									$ 0.00	$ (0.15)	$ 0.10
Earnings per share attributable to TECO Energy available to common shareholders - Basic									$ 0.92	$ 0.99	$ 1.27
Diluted earnings per share
Net income from continuing operations	42.1	62.9	51.6	41.2	45.6	90.2	65.6	44.6	197.8	246.0	250.8
Amount allocated to nonvested participating shareholders									(0.6)	(0.8)	(1.3)
Income before discontinued operations available to common shareholders - Diluted									197.2	245.2	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net									(0.1)	(33.3)	21.8
Amount allocated to nonvested participating shareholders									0	0.1	(0.1)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted									(0.1)	(33.2)	21.7
Net income attributable to TECO Energy	42.0	62.8	51.4	41.5	45.1	44.0	73.1	50.5	197.7	212.7	272.6
Amount allocated to nonvested participating shareholders									(0.6)	(0.7)	(1.4)
Net income attributable to TECO Energy available to common shareholders - Diluted									$ 197.1	$ 212.0	$ 271.2
Unadjusted average common shares outstanding - Diluted									215.0	214.3	213.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net									0.5	0.7	1.5
Average common shares outstanding - Diluted									215.5	215.0	215.1
Earnings per share from continuing operations available to common shareholders - Diluted	$ 0.20	$ 0.29	$ 0.24	$ 0.19	$ 0.21	$ 0.42	$ 0.30	$ 0.20	$ 0.92	$ 1.14	$ 1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted									$ 0.00	$ (0.15)	$ 0.10
Earnings per share attributable to TECO Energy available to common shareholders - Diluted									$ 0.92	$ 0.99	$ 1.27
Anti-dilutive shares									0	0.4	1.7

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Common Stock - Schedule of Assumptions Used to Determine Fair Value (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Risk-free interest rate	0.41%	0.38%	0.96%
Expected lives (in years)	3 years	3 years	3 years
Expected stock volatility	19.04%	20.99%	34.61%
Dividend yield	4.83%	4.78%	4.48%

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Preferred Stock - Additional Information (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013
Preferred Stock Par Value [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, par value	$ 1
Preferred stock, shares authorized	10.0
Preferred stock, shares outstanding	0
Preferred Stock Par Value [Member] | Tampa Electric Company [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, par value	$ 100
Preferred stock, shares authorized	1.5
Preferred stock, shares outstanding	0
Preferred Stock No Par Value [Member] | Tampa Electric Company [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, no par value
Preferred stock, shares authorized	2.5
Preferred stock, shares outstanding	0
Preference Stock (Subordinated Preferred Stock) Of Tampa Electric - No Par [Member] | Tampa Electric Company [Member]
Authorized Classes Of Cumulative Preferred And Preference Stocks [Line Items]
Preferred stock, no par value
Preferred stock, shares authorized	2.5
Preferred stock, shares outstanding	0

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Accounting for Derivative Instruments and Hedging Activities - Fair Value of Overall Contractual Contingent Liability Positions (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair Value Asset/ (Liability)	$ (0.1)
Derivative Exposure Asset/ (Liability)	(0.1)
Posted Collateral	$ 0

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Quarterly Data - Schedule of Financial Data by Quarter (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Data [Line Items]
Revenues	$ 688.4	$ 765.9	$ 735.9	$ 661.1	$ 688.4	$ 858.6	$ 752.5	$ 697.1	$ 2,851.3	$ 2,996.6	$ 3,209.9
Income from operations	99.6	140.5	119.5	104.1	109.5	183.1	149.1	114.8	463.7	556.5	583.2
Net income from continuing operations	42.1	62.9	51.6	41.2	45.6	90.2	65.6	44.6	197.8	246.0	250.8
Net income attributable to TECO Energy	$ 42.0	$ 62.8	$ 51.4	$ 41.5	$ 45.1	$ 44.0	$ 73.1	$ 50.5	$ 197.7	$ 212.7	$ 272.6
EPS - Basic
From continuing operations	$ 0.20	$ 0.29	$ 0.24	$ 0.19	$ 0.21	$ 0.42	$ 0.30	$ 0.21	$ 0.92	$ 1.14	$ 1.17
Attributable to TECO Energy									$ 0.92	$ 0.99	$ 1.27
EPS - Diluted
From continuing operations	$ 0.20	$ 0.29	$ 0.24	$ 0.19	$ 0.21	$ 0.42	$ 0.30	$ 0.20	$ 0.92	$ 1.14	$ 1.17
Attributable to TECO Energy									$ 0.92	$ 0.99	$ 1.27
Dividends paid per common share outstanding	$ 0.220	$ 0.220	$ 0.220	$ 0.220	$ 0.220	$ 0.220	$ 0.220	$ 0.220	$ 0.88	$ 0.88	$ 0.85
TECO Energy [Member]
EPS - Basic
Attributable to TECO Energy	$ 0.20	$ 0.29	$ 0.24	$ 0.19	$ 0.21	$ 0.20	$ 0.34	$ 0.24
EPS - Diluted
Attributable to TECO Energy	$ 0.20	$ 0.29	$ 0.24	$ 0.19	$ 0.21	$ 0.20	$ 0.34	$ 0.23

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Accounting for Derivative Instruments and Hedging Activities - Effect of Hedging Instruments on Other Comprehensive Income and Income (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	$ 0.6	$ (4.6)	$ 1.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.8)	(0.4)	2.0
Tampa Electric Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.9)	(0.8)	(0.7)
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0.6	0.3	1.2
Location of Gain/(Loss) Reclassified From AOCI Into Income	Mining related costs	Mining related costs	Mining related costs
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0.1	0.4	2.7
Interest rate contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) on Derivatives Recognized in OCI	0	(4.9)	0
Location of Gain/(Loss) Reclassified From AOCI Into Income	Interest expense	Interest expense	Interest expense
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.9)	(0.8)	(0.7)
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
Amount of Gain/(Loss) Reclassified From AOCI Into Income	$ (0.9)	$ (0.8)	$ (0.7)

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Feb. 13, 2014	Jun. 28, 2013
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Entity Registrant Name	TECO ENERGY INC
Entity Central Index Key	0000350563
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		218,067,617
Entity Public Float			$ 3.69
Tampa Electric Company [Member]
Document Information [Line Items]
Entity Registrant Name	TAMPA ELECTRIC CO
Entity Central Index Key	0000096271
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		10
Entity Public Float			$ 0

XML

Variable Interest Entities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 64.7	$ 105.3	$ 125.9
Agreement's expiration	Dec. 31, 2012
Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	64.7	105.3	125.9
Agreement's expiration	Dec. 31, 2012
Power Purchase Agreements [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power		46.6	34.4
Power Purchase Agreements [Member] | Variable Interest Entities [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	22.1	75.8	81.2
Power Purchase Agreements [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power		46.6	34.4
Power Purchase Agreements [Member] | Tampa Electric Company [Member] | Variable Interest Entities [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 22.1	$ 75.8	$ 81.2
Minimum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	117
Minimum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	117
Maximum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	370
Maximum [Member] | Tampa Electric Company [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Multiple PPAs range	370

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Short-Term Debt

12 Months Ended

Dec. 31, 2013

Short-Term Debt

6. Short-Term Debt

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

Credit Facilities
	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	6.0	$	0.7	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		78.0		0.0		150.0		0.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(3)		200.0		0.0		0.0		200.0		0.0		0.0
Total	$	675.0	$	84.0	$	0.7	$	675.0	$	0.0	$	1.5

(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 Dec. 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 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 Dec. 31, 2012.

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., Inc. as Program Agent. The amendment extends the maturity date to Feb. 13, 2015 and makes certain other technical changes. Please refer to Note 24 for additional information.

Amendments of TECO Energy/TECO Finance Credit Facility

On Dec. 17, 2013, TECO Energy amended and restated its $200 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility). The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues with TECO Energy as Guarantor and its wholly-owned subsidiary, TECO Finance, as Borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (ix) makes other technical changes.

The Fourth Amended and Restated Credit Agreement includes the changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. The Amendment was entered into to accommodate the acquisition of NMGI, as described in Note 22 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closes, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changing the definition of Permitted Liens as defined in the TECO Credit Facility to permit the acquisition of a significant subsidiary that carries secured debt and making other changes matching the corresponding covenant in the Bridge Facility, as described in Note 22 herein.

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

Tampa Electric Company [Member]

Short-Term Debt

6. Short-Term Debt

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

Credit Facilities
	Dec. 31, 2013						Dec. 31, 2012
(millions)	Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding		Credit Facilities		Borrowings Outstanding (1)		Letters of Credit Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	6.0	$	0.7	$	325.0	$	0.0	$	1.5
1-year accounts receivable facility		150.0		78.0		0.0		150.0		0.0		0.0
Total	$	475.0	$	84.0	$	0.7	$	475.0	$	0.0	$	1.5

(1) Borrowings outstanding are reported as notes payable.

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

At Dec. 31, 2013, these credit facilities require commitment fees ranging from 12.5 to 25.0 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 Dec. 31, 2012.

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., Inc. as Program Agent. The amendment extends the maturity date to Feb. 13, 2015 and makes certain other technical changes. Please refer to Note 16 for additional information.

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extends the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

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Employee Postretirement Benefits - Schedule of Net Periodic Benefit Cost (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 18.2	$ 17.0	$ 16.0
Interest cost	28.9	30.1	30.9
Expected return on plan assets	(38.4)	(37.1)	(38.4)
Amortization of:
Actuarial loss	20.5	15.3	11.3
Prior service (benefit) cost	(0.4)	(0.4)	(0.4)
Transition obligation	0	0	0
Settlement loss	1.0	0	0.9
Net periodic benefit cost	29.8	24.9	20.3
Prior service cost	0	0	0
Net loss (gain)	(75.7)	34.0	43.3
Amortization of:
Actuarial gain (loss)	(21.5)	(15.3)	(12.2)
Prior service (benefit) cost	0.4	0.4	0.4
Transition obligation	0	0	0
Total recognized in OCI and regulatory assets	(96.8)	19.1	31.5
Total recognized in net periodic benefit cost, OCI and regulatory assets	(67.0)	44.0	51.8
Pension Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	18.2	17.0	16.0
Interest cost	28.9	30.1	30.9
Expected return on plan assets	(38.4)	(37.1)	(38.4)
Amortization of:
Actuarial loss	20.5	15.3	11.3
Prior service (benefit) cost	(0.4)	(0.4)	(0.4)
Transition obligation	0	0	0
Settlement loss	1.0	0	0.9
Net periodic benefit cost	29.8	24.9	20.3
Prior service cost	0	0	0
Net loss (gain)	(75.7)	34.0	43.3
Amortization of:
Actuarial gain (loss)	(21.5)	(15.3)	(12.2)
Prior service (benefit) cost	0.4	0.4	0.4
Transition obligation	0	0	0
Total recognized in OCI and regulatory assets	(96.8)	19.1	31.5
Total recognized in net periodic benefit cost, OCI and regulatory assets	(67.0)	44.0	51.8
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Expected return on plan assets	0	0	0
Amortization of:
Actuarial loss	1.0	0.1	0.1
Prior service (benefit) cost	(0.3)	0.8	0.8
Transition obligation	0	1.8	2.3
Settlement loss	0	0	0
Net periodic benefit cost	12.4	15.2	16.4
Prior service cost	0	(5.2)	0
Net loss (gain)	(15.6)	16.3	(7.4)
Amortization of:
Actuarial gain (loss)	(1.0)	(0.1)	(0.1)
Prior service (benefit) cost	0.3	(0.8)	(0.8)
Transition obligation	0	(1.8)	(2.4)
Total recognized in OCI and regulatory assets	(16.3)	8.4	(10.7)
Total recognized in net periodic benefit cost, OCI and regulatory assets	(3.9)	23.6	5.7
Other Postretirement Benefits [Member] | TECO Energy [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2.5	2.4	2.1
Interest cost	9.3	10.1	11.1
Expected return on plan assets	0	0	0
Amortization of:
Actuarial loss	1.0	0.1	0.1
Prior service (benefit) cost	(0.3)	0.8	0.8
Transition obligation	0	1.8	2.3
Settlement loss	0	0	0
Net periodic benefit cost	12.4	15.2	16.4
Prior service cost	0	(5.2)	0
Net loss (gain)	(15.6)	16.3	(7.4)
Amortization of:
Actuarial gain (loss)	(1.0)	(0.1)	(0.1)
Prior service (benefit) cost	0.3	(0.8)	(0.8)
Transition obligation	0	(1.8)	(2.4)
Total recognized in OCI and regulatory assets	(16.3)	8.4	(10.7)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$ (3.9)	$ 23.6	$ 5.7

XML

Long Term Debt - Schedule of Long Term Debt Outstanding (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2008 Tampa Electric Company [Member] Variable Rate Bonds Repurchased In 2008 [Member]	Sep. 30, 2013 Tampa Electric Company [Member] Refunding Bonds Repurchased In 2013 [Member]	Mar. 31, 2011 Tampa Electric Company [Member] Term Rate Bonds Repurchased In 2012 [Member]	Mar. 31, 2012 Tampa Electric Company [Member] Refunding Bonds Repurchased In 2012 [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 5.65% Refunding bonds [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 5.15% Refunding bonds [Member]	Dec. 31, 2012 Tampa Electric Company [Member] 5.15% Refunding bonds [Member]	Sep. 30, 2012 Tampa Electric Company [Member] 5.15% Refunding bonds [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 1.5% term rate bonds repurchased in 2011 [Member]	Mar. 31, 2011 Tampa Electric Company [Member] 1.5% term rate bonds repurchased in 2011 [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 5.0% Refunding bonds [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 6.25% Notes [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 6.1% Notes [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 5.4% Notes [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 2.6% Notes [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 6.55% Notes [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 6.15% Notes [Member]	Dec. 31, 2013 Tampa Electric Company [Member] 4.1% Notes [Member]	Dec. 31, 2013 TECO Finance [Member] 6.75% Notes [Member]	Dec. 31, 2013 TECO Finance [Member] 4.00% Notes [Member]	Dec. 31, 2013 TECO Finance [Member] 6.752% Notes [Member]	Dec. 31, 2013 TECO Finance [Member] 5.15% Notes [Member]	Dec. 31, 2013 PGS [Member] 6.1% Notes [Member]	Dec. 31, 2013 PGS [Member] 5.4% Notes [Member]	Dec. 31, 2013 PGS [Member] 2.6% Notes [Member]	Dec. 31, 2013 PGS [Member] 6.15% Notes [Member]	Dec. 31, 2013 PGS [Member] 4.1% Notes [Member]
Debt Instrument [Line Items]
Effective interest rate					5.90%		5.40%				0.00%	6.30%	6.00%	5.40%	2.70%	6.60%	6.20%	4.20%	6.90%	4.20%	7.30%	5.30%	7.00%	5.40%	2.70%	6.20%	4.20%
Stated interest rate					5.65%	5.15%			1.50%		5.00%	6.25%	6.10%	5.40%	2.60%	6.55%	6.15%	4.10%	6.75%	4.00%	6.572%	5.15%	6.10%	5.40%	2.60%	6.15%	4.10%
Repurchased bonds, par amount	$ 20.0	$ 51.6	$ 75.0	$ 86.0				$ 51.6		$ 75.0

XML

Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues
Regulated electric and gas (includes franchise fees and gross receipts taxes of $108.5 in 2013, $111.5 in 2012 and $109.3 in 2011)	$ 2,342.5	$ 2,377.4	$ 2,469.8
Unregulated	508.8	619.2	740.1
Total revenues	2,851.3	2,996.6	3,209.9
Expenses
Fuel	680.2	694.7	731.4
Purchased power	64.7	105.3	125.9
Cost of natural gas sold	142.2	155.7	210.4
Other	524.4	462.5	436.9
Operation and maintenance other expense
Mining related costs	419.0	461.1	574.1
Other	12.5	7.9	7.1
Depreciation and amortization	329.5	330.6	317.2
Taxes, other than income	215.1	222.3	223.7
Total expenses	2,387.6	2,440.1	2,626.7
Income from operations	463.7	556.5	583.2
Other income (expense)
Allowance for other funds used during construction	6.3	2.6	1.0
Other income	3.6	9.4	6.7
Loss on debt extinguishment	0	(1.2)	0
Total other income	9.9	10.8	7.7
Interest charges
Interest expense	170.5	185.0	198.0
Allowance for borrowed funds used during construction	(3.6)	(1.5)	(0.6)
Total interest charges	166.9	183.5	197.4
Income from continuing operations before provision for income taxes	306.7	383.8	393.5
Provision for income taxes	108.9	137.8	142.7
Net income from continuing operations	197.8	246.0	250.8
Discontinued operations
Income (loss) from discontinued operations	(0.2)	(10.6)	33.3
Provision for income taxes	(0.1)	22.4	11.2
Income (loss) from discontinued operations, net	(0.1)	(33.0)	22.1
Less: Income from discontinued operations attributable to noncontrolling interest	0	0.3	0.3
Income (loss) from discontinued operations attributable to TECO Energy, net	(0.1)	(33.3)	21.8
Net income attributable to TECO Energy	$ 197.7	$ 212.7	$ 272.6
Average common shares outstanding - Basic	215.0	214.3	213.6
Average common shares outstanding - Diluted	215.5	215.0	215.1
Earnings per share from continuing operations - Basic	$ 0.92	$ 1.14	$ 1.17
Earnings per share from continuing operations - Diluted	$ 0.92	$ 1.14	$ 1.17
Earnings per share from discontinued operations attributable to TECO Energy - Basic	$ 0.00	$ (0.15)	$ 0.10
Earnings per share from discontinued operations attributable to TECO Energy - Diluted	$ 0.00	$ (0.15)	$ 0.10
Earnings per share attributable to TECO Energy - Basic	$ 0.92	$ 0.99	$ 1.27
Earnings per share attributable to TECO Energy - Diluted	$ 0.92	$ 0.99	$ 1.27
Dividends paid per common share outstanding	$ 0.88	$ 0.88	$ 0.85

XML

Consolidated Statements of Retained Earnings (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Beginning Balance	$ 541.7
Add: Net income	197.7	212.7	272.6
Deduct: Cash dividends on capital stock - common	191.2	190.4	183.2
Ending Balance	548.3	541.7
Tampa Electric Company [Member]
Beginning Balance	304.6	305.7	311.1
Add: Net income	225.6	227.2	235.3
Retained Earning, Gross	530.2	532.9	546.4
Deduct: Cash dividends on capital stock - common	222.1	228.3	240.7
Ending Balance	$ 308.1	$ 304.6	$ 305.7

XML

Consolidated Statements of Income and Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Franchise fees and gross receipts taxes	$ 108.5	$ 111.5	$ 109.3
Tampa Electric Company [Member]
Franchise fees and gross receipts taxes	108.5	111.5	109.3
Tampa Electric Company [Member] | Electric [Member]
Franchise fees and gross receipts taxes	88.0	91.1	85.6
Tampa Electric Company [Member] | Gas [Member]
Franchise fees and gross receipts taxes	$ 20.5	$ 20.4	$ 23.7

XML

Earnings Per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

11. Earnings Per Share

In accordance with accounting standards for the calculation of EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method.

The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.

(millions, except per share amounts)	2013			2012			2011 (1)
Basic earnings per share
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Amount allocated to nonvested participating shareholders		(0.6	)		(0.8	)		(1.3	)
Income before discontinued operations available to common shareholders - Basic	$	197.2		$	245.2		$	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
Amount allocated to nonvested participating shareholders		0.0			0.1			(0.1	)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Basic	($	0.1	)	($	33.2	)	$	21.7
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Amount allocated to nonvested participating shareholders		(0.6	)		(0.7	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - Basic	$	197.1		$	212.0		$	271.2
Average common shares outstanding - Basic		215.0			214.3			213.6
Earnings per share from continuing operations available to common shareholders - Basic	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Basic	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy available to common shareholders - Basic	$	0.92		$	0.99		$	1.27
Diluted earnings per share
Net income from continuing operations	$	197.8		$	246.0		$	250.8
Amount allocated to nonvested participating shareholders		(0.6	)		(0.8	)		(1.3	)
Income before discontinued operations available to common shareholders - Diluted	$	197.2		$	245.2		$	249.5
Income (loss) from discontinued operations attributable to TECO Energy, net	($	0.1	)	($	33.3	)	$	21.8
Amount allocated to nonvested participating shareholders		0.0			0.1			(0.1	)
Income (loss) from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	($	0.1	)	($	33.2	)	$	21.7
Net income attributable to TECO Energy	$	197.7		$	212.7		$	272.6
Amount allocated to nonvested participating shareholders		(0.6	)		(0.7	)		(1.4	)
Net income attributable to TECO Energy available to common shareholders - Diluted	$	197.1		$	212.0		$	271.2
Unadjusted average common shares outstanding - Diluted		215.0			214.3			213.6
Assumed conversion of stock options, unvested restricted stock and contingent performance shares, net		0.5			0.7			1.5
Average common shares outstanding - Diluted		215.5			215.0			215.1
Earnings per share from continuing operations available to common shareholders - Diluted	$	0.92		$	1.14		$	1.17
Earnings per share from discontinued operations attributable to TECO Energy available to common shareholders - Diluted	$	0.00		($	0.15	)	$	0.10
Earnings per share attributable to TECO Energy available to common shareholders - Diluted	$	0.92		$	0.99		$	1.27
Anti-dilutive shares		0.0			0.4			1.7

(1) All prior periods presented reflect the classification of TECO Guatemala as discontinued operations (see Note 19).

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Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-Term Debt

7. Long-Term Debt

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. At Dec. 31, 2012, total long-term debt had a carrying amount of $2,972.7 million and an estimated fair market value of $3,442.2 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.

TECO Finance is a 100% owned subsidiary of TECO Energy. TECO Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no other subsidiaries of TECO Energy guarantee TECO Finance’s securities.

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2014 through 2018 and thereafter are as follows:

Long-Term Debt Maturities
As of Dec. 31, 2013 (millions)	2014		2015		2016		2017		2018		Thereafter		Total Long-Term Debt
TECO Finance	$	0.0	$	191.2	$	250.0	$	300.0	$	0.0	$	300.0	$	1,041.2
Tampa Electric		83.3		83.3		83.4		0.0		254.2		1,146.7		1,650.9
PGS		0.0		0.0		0.0		0.0		50.0		181.7		231.7
Total long-term debt maturities	$	83.3	$	274.5	$	333.4	$	300.0	$	304.2	$	1,628.4	$	2,923.8

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

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

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

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

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

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Dec. 31, 2013 to provide an opportunity to evaluate refinancing alternatives.

Redemption of TECO Energy, Inc. 6.75% Notes due 2015

On Dec. 5, 2012, TECO Energy redeemed $8.8 million of 6.75% Notes due May 15, 2015. The redemption price was equal to $1,141.86 per $1,000.00 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $1.2 million of premiums were expensed, and are included in “Loss on debt extinguishment” on the Consolidated Statements of Income and as part of the “Cash flows from operating activities” in the Consolidated Statements of Cash Flows for the twelve months ended Dec. 31, 2012.

Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002

On Oct. 1, 2012, TEC redeemed $147.1 million of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, $60.7 million of the 2002 Bonds due Oct. 1, 2013 bore interest at 5.1% and $86.4 million of the 2002 Bonds due Oct. 1, 2023 bore interest at 5.5%.

Issuance of Tampa Electric Company 2.60% Notes due 2022

On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022 (the 2022 Notes). The 2022 Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2022 Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the 2022 Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, 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 June 15, 2022, TEC may at its option redeem the 2022 Notes, in whole or in part, at 100% of the principal amount of the 2022 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of Tampa Electric Company 4.10% Notes due 2042

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the 2042 Notes). The 2042 Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 2042 Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2042 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 2042 Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 2042 Notes, in whole or in part, at 100% of the principal amount of the 2042 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Redemption of TECO Guatemala San José Project Notes

On Dec. 19, 2012, in conjunction with the closing on the sale of its equity interests in the San José Power Station, TECO Energy utilized $25.3 million of the sale proceeds to repay the San José project notes.

At Dec. 31, 2013 and 2012, TECO Energy had the following long-term debt outstanding:

Long-Term Debt
(millions) Dec. 31,		Due	2013			2012
TECO Finance	Notes (1)(2)(3): 6.75% (effective rate of 6.9%)	2015	$	191.2		$	191.2
	4.0% (effective rate of 4.2%)	2016		250.0			250.0
	6.572% (effective rate of 7.3%)	2017		300.0			300.0
	5.15% (effective rate of 5.3%)	2020		300.0			300.0
Total long-term debt of TECO Finance				1,041.2			1,041.2
Tampa Electric	Installment contracts payable (4):
	5.65% Refunding bonds (effective rate of 5.9%)	2018		54.2			54.2
	Variable rate bonds repurchased in 2008 (5)	2020		0.0			0.0
	5.15% Refunding bonds repurchased in 2013 (effective rate of 5.4% for 2012) (6)	2025		0.0			51.6
	1.5% Term rate bonds repurchased in 2011 (7)	2030		0.0			0.0
	5.0% Refunding bonds repurchased in 2012 (8)	2034		0.0			0.0
	Notes (1): 6.25% (effective rate of 6.3%) (2)	2014-2016		250.0			250.0
	6.1% (effective rate of 6.0%)	2018		200.0			200.0
	5.4% (effective rate of 5.4%)	2021		231.7			231.7
	2.6% (effective rate of 2.7%)	2022		225.0			225.0
	6.55% (effective rate of 6.6%)	2036		250.0			250.0
	6.15% (effective rate of 6.2%)	2037		190.0			190.0
	4.1% (effective rate of 4.2%)	2042		250.0			250.0
Total long-term debt of Tampa Electric				1,650.9			1,702.5
PGS	Notes (1): 6.1% (effective rate of 7.0%)	2018		50.0			50.0
	5.4% (effective rate of 5.4%)	2021		46.7			46.7
	2.6% (effective rate of 2.7%)	2022		25.0			25.0
	6.15% (effective rate of 6.2%)	2037		60.0			60.0
	4.1% (effective rate of 4.2%)	2042		50.0			50.0
Total long-term debt of PGS				231.7			231.7
Total long-term debt of TECO Energy				2,923.8			2,975.4
Unamortized debt discount, net				(2.7	)		(2.7	)
Total carrying amount of long-term debt				2,921.1			2,972.7
Less amount due within one year				83.3			0.0
Total long-term debt			$	2,837.8		$	2,972.7

(1) These securities are subject to redemption in whole or in part, at any time, at the option of the company.

(2) These long-term debt agreements contain various restrictive financial covenants.

(3) Guaranteed by TECO Energy.

(4) Tax-exempt securities.

(5) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.

(6) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.

(7) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.

(8) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

Tampa Electric Company [Member]

Long-Term Debt

7. Long-Term Debt

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

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

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

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

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

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

After the Sept. 3, 2013 purchase of the Series 2007 B HCIDA Bonds, $232.6 million in bonds purchased in lieu of redemption were held by the trustee at the direction of TEC as of Dec. 31, 2013 to provide an opportunity to evaluate refinancing alternatives.

Redemption of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002

On Oct. 1, 2012, TEC redeemed $147.1 million of Hillsborough County Industrial Development Authority Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2002 due Oct. 1, 2013 and Oct. 1, 2023 (the 2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, $60.7 million of the 2002 Bonds due Oct. 1, 2013 bore interest at 5.1% and $86.4 million of the 2002 Bonds due Oct. 1, 2023 bore interest at 5.5%.

Issuance of Tampa Electric Company 2.60% Notes due 2022

On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022 (the 2022 Notes). The 2022 Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes. At any time prior to June 15, 2022, TEC may redeem all or any part of the 2022 Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and interest on the 2022 Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, 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 June 15, 2022, TEC may at its option redeem the 2022 Notes, in whole or in part, at 100% of the principal amount of the 2022 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of Tampa Electric Company 4.10% Notes due 2042

On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042 (the 2042 Notes). The 2042 Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 2042 Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the 2042 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 2042 Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 2042 Notes, in whole or in part, at 100% of the principal amount of the 2042 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

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Short-Term Debt - Credit Facilities (Detail) (USD $)	Dec. 31, 2013	Dec. 17, 2013	Dec. 31, 2012
Line of Credit Facility [Line Items]
Credit Facilities	$ 675,000,000		$ 675,000,000
Borrowings Outstanding	84,000,000		0
Letters of Credit Outstanding	700,000		1,500,000
Tampa Electric Company [Member]
Line of Credit Facility [Line Items]
Credit Facilities	475,000,000	200,000,000	475,000,000
Borrowings Outstanding	84,000,000		0
Letters of Credit Outstanding	700,000		1,500,000
Tampa Electric Company [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	325,000,000		325,000,000
Borrowings Outstanding	6,000,000		0
Letters of Credit Outstanding	700,000		1,500,000
Tampa Electric Company [Member] | 1-year Accounts Receivable Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	150,000,000		150,000,000
Borrowings Outstanding	78,000,000		0
Letters of Credit Outstanding	0		0
TECO Energy [Member] | 5-year Facility [Member]
Line of Credit Facility [Line Items]
Credit Facilities	200,000,000		200,000,000
Borrowings Outstanding	0		0
Letters of Credit Outstanding	$ 0		$ 0

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Regulatory

12 Months Ended

Dec. 31, 2013

Regulatory

3. Regulatory

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

Base Rates-Tampa Electric

Tampa Electric’s results for the first ten months of 2013, and all of 2012 and 2011, reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

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

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

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

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

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Storm Damage Cost Recovery

Prior to the above mentioned stipulation and settlement agreement, 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. Tampa Electric’s storm reserve was $56.1 million and $50.4 million as of Dec. 31, 2013 and 2012, respectively. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to the level as of Oct. 31, 2013.

Regulatory Assets and Liabilities

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

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

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

Regulatory Assets and Liabilities
(millions)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.4	$	67.2
Other:
Cost-recovery clauses		6.1		42.9
Postretirement benefit asset		182.7		276.1
Deferred bond refinancing costs (2)		8.0		9.2
Environmental remediation		51.4		46.9
Competitive rate adjustment		4.1		4.1
Other		7.7		6.5
Total other regulatory assets		260.0		385.7
Total regulatory assets		327.4		452.9
Less: Current portion		34.3		70.3
Long-term regulatory assets	$	293.1	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	9.8	$	14.6
Other:
Cost-recovery clauses		54.5		73.9
Transmission and delivery storm reserve		56.1		50.4
Deferred gain on property sales (3)		2.0		3.4
Provision for stipulation and other		0.8		1.0
Accumulated reserve - cost of removal		594.0		593.7
Total other regulatory liabilities		707.4		722.4
Total regulatory liabilities		717.2		737.0
Less: Current portion		85.8		105.6
Long-term regulatory liabilities	$	631.4	$	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
(millions)	Dec. 31, 2013		Dec. 31, 2012
Clause recoverable (1)	$	10.2	$	47.0
Components of rate base (2)		185.6		279.1
Regulatory tax assets (3)		67.4		67.2
Capital structure and other (3)		64.2		59.6
Total	$	327.4	$	452.9

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

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

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

Tampa Electric Company [Member]

Regulatory

3. Regulatory

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

Base Rates-Tampa Electric

Tampa Electric’s results for the first ten months of 2013, and all of 2012 and 2011, reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

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

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

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

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

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Storm Damage Cost Recovery

Prior to the above mentioned stipulation and settlement agreement, 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. Tampa Electric’s storm reserve was $56.1 million and $50.4 million as of Dec. 31, 2013 and 2012, respectively. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to the level as of Oct. 31, 2013.

Regulatory Assets and Liabilities

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

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

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

Regulatory Assets and Liabilities
(millions)	Dec. 31, 2013		Dec. 31, 2012
Regulatory assets:
Regulatory tax asset (1)	$	67.4	$	67.2
Other:
Cost-recovery clauses		6.1		42.9
Postretirement benefit asset		182.7		276.1
Deferred bond refinancing costs (2)		8.0		9.2
Environmental remediation		51.4		46.9
Competitive rate adjustment		4.1		4.1
Other		7.7		6.5
Total other regulatory assets		260.0		385.7
Total regulatory assets		327.4		452.9
Less: Current portion		34.3		70.3
Long-term regulatory assets	$	293.1	$	382.6
Regulatory liabilities:
Regulatory tax liability (1)	$	9.8	$	14.6
Other:
Cost-recovery clauses		54.5		73.9
Transmission and delivery storm reserve		56.1		50.4
Deferred gain on property sales (3)		2.0		3.4
Provision for stipulation and other		0.8		1.0
Accumulated reserve - cost of removal		594.0		593.7
Total other regulatory liabilities		707.4		722.4
Total regulatory liabilities		717.2		737.0
Less: Current portion		85.8		105.6
Long-term regulatory liabilities	$	631.4	$	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
(millions)	Dec. 31, 2013		Dec. 31, 2012
Clause recoverable (1)	$	10.2	$	47.0
Components of rate base (2)		185.6		279.1
Regulatory tax assets (3)		67.4		67.2
Capital structure and other (3)		64.2		59.6
Total	$	327.4	$	452.9

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

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

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

XML

Regulatory - Additional Information (Detail) (Tampa Electric Company [Member], USD $)	0 Months Ended	12 Months Ended
	Feb. 04, 2013	Dec. 31, 2013	Apr. 05, 2013	Dec. 31, 2012
Percentage of return on equity	11.25%	11.25%
Allowed equity in the capital structure		54.00%
Period of average base rate		13 months
Revenue due to average base rate		$ 3,400,000,000
Increase in revenue by modification in base rate		33,500,000
Additional Revenue generated from increase in service charge			134,800,000
Potential increase in ROE		10.25%
Return on equity range		Range of plus or minus 1%
Amortization period for computer software under regulatory requirement description		Tampa Electric will begin using a 15-year amortization period for all computer software
Annual accrual storm damage reserve		8,000,000
Storm damage reserve		56,100,000		50,400,000
Condition One [Member]
ROE lower range limit		11.25%
ROE upper range limit		9.25%
Condition Two [Member]
ROE lower range limit		11.50%
ROE upper range limit		9.50%
Transmission and Delivery Storm Reserve [Member]
Storm damage cost recovery period		12 months
November 1, 2013 [Member]
Additional Revenue generated from increase in service charge		57,500,000
November 1, 2014 [Member]
Additional Revenue generated from increase in service charge		7,500,000
November 1, 2015 [Member]
Additional Revenue generated from increase in service charge		5,000,000
January 1,2017 [Member]
Additional Revenue generated from increase in service charge		110,000,000
Maximum [Member]
Higher Revenue Requirements		$ 104,000,000
Return on equity	12.25%
Potential increase in ROE		10.50%
Minimum [Member]
Return on equity	10.25%

XML

Segment Information - Schedule of Segment Information (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting [Abstract]
Internally allocated interest costs, pre tax rate	6.00%	6.00%	6.25%
Capital structure assumption, debt to equity ratio	50.00%
Mineral rights	$ 12.1	$ 13.4	$ 15.0

XML

Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Significant Accounting Policies

1. Significant Accounting Policies

The significant accounting policies for both utility and diversified operations are as follows:

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiaries do not have majority ownership or exercise control.

For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).

Use of Estimates

The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.

Restricted Cash

Restricted cash of $8.7 million related to cash held in escrow for the 2003 sale of HPP, was released from escrow in 2012 upon maturity of debt financing that was held by the purchaser of HPP. There was no restricted cash at Dec. 31, 2013.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Planned Major Maintenance

Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.

Tampa Electric and PGS expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:

Asset	Estimated Useful Lives
Building and improvements	5 - 40 years
Office equipment and furniture	3 - 30 years
Vehicles, mining and other equipment	2 - 15 years
Coal processing facilities	7 - 20 years
Computer software	2 - 15 years

Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $316.5 million, $309.3 million and $306.6 million, respectively.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis.

Fuel Inventory (millions)	Dec. 31, 2013		Dec. 31, 2012
TEC	$	93.7	$	89.1
TECO Coal		25.0		34.5
Total	$	118.7	$	123.6

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).

Deferred Income Taxes

TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Revenue Recognition

TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer.

Revenues for energy marketing operations at TECO Energy Source are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2013, 2012 and 2011 were $23.1 million, $13.8 million and $2.5 million, respectively.

Shipping and Handling

TECO Coal includes the costs to ship product to customers in “Operation & maintenance other expense - Mining related costs” on the Consolidated Statements of Income which for the years ended Dec. 31, 2013, 2012 and 2011 were $8.2 million, $9.0 million and $16.6 million, respectively.

Cash Flows Related to Derivatives and Hedging Activities

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

Revenues and Cost Recovery

Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.

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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of mining development costs amortized on a per ton basis and offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2013 and 2012 ranged from 3.51% to 4.86% and 2.60% to 4.00%, respectively.

Stock-Based Compensation

TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.

Receivables and Allowance for Uncollectible Accounts

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on Tampa Electric’s and PGS’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. TECO Coal’s receivables consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.

Reclassifications

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

Tampa Electric Company [Member]

Significant Accounting Policies

1. Significant Accounting Policies

The significant accounting policies are as follows:

Basis of Accounting

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with GAAP in all material respects.

The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance.

TEC’s retail and wholesale businesses are regulated by the FPSC and related FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Principles of Consolidation

TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.

For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).

Planned Major Maintenance

Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $284.2 million, $275.1 million and $263.7 million, respectively.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 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, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

Revenue Recognition

TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TEC is 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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.

Reclassifications

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

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New Accounting Pronouncements

12 Months Ended

Dec. 31, 2013

New Accounting Pronouncements

2. New Accounting Pronouncements

Unrecognized Tax Benefits

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

Comprehensive Income

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

Offsetting Assets and Liabilities

In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. The company has adopted this guidance as required. It had no effect on the company’s results of operations, financial position or cash flows.

Tampa Electric Company [Member]

New Accounting Pronouncements

2. New Accounting Pronouncements

Comprehensive Income

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

Offsetting Assets and Liabilities

In December 2011, the FASB issued guidance enhancing disclosures of financial instruments and derivative instruments that are offset in the statement of financial position or subject to enforceable master netting agreements. The guidance is effective for interim and annual reporting periods beginning on or after Jan. 1, 2013. TEC has adopted this guidance as required. It had no effect on TEC’s results of operations, financial position or cash flows.

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Consolidated Statements of Capitalization - Long-Term Debt (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 PGS [Member] 6.1% Notes [Member]	Dec. 31, 2013 PGS [Member] 5.4% Notes [Member]	Dec. 31, 2013 PGS [Member] 2.6% Notes [Member]	Dec. 31, 2013 PGS [Member] 6.15% Notes [Member]	Dec. 31, 2013 PGS [Member] 4.1% Notes [Member]	Mar. 31, 2008 Tampa Electric Company [Member] Variable rate bonds repurchased in 2008 Due To 2020 [Member]	Mar. 31, 2012 Tampa Electric Company [Member] Variable Rate Bonds [Member]	Dec. 31, 2013 Tampa Electric [Member] 5.65% Refunding bonds [Member]	Dec. 31, 2013 Tampa Electric [Member] 5.15% Refunding bonds [Member]	Dec. 31, 2013 Tampa Electric [Member] 1.5% term rate bonds repurchased in 2011 [Member]	Dec. 31, 2013 Tampa Electric [Member] 5.0% Refunding bonds [Member]	Dec. 31, 2013 Tampa Electric [Member] 6.25% Notes [Member]	Dec. 31, 2013 Tampa Electric [Member] 6.1% Notes [Member]	Dec. 31, 2013 Tampa Electric [Member] 5.4% Notes [Member]	Dec. 31, 2013 Tampa Electric [Member] 2.6% Notes [Member]	Dec. 31, 2013 Tampa Electric [Member] 6.55% Notes [Member]	Dec. 31, 2013 Tampa Electric [Member] 6.15% Notes [Member]	Dec. 31, 2013 Tampa Electric [Member] 4.1% Notes [Member]
Debt Instrument [Line Items]
Effective interest rate	7.00%	5.40%	2.70%	6.20%	4.20%
Stated interest rate	6.10%	5.40%	2.60%	6.15%	4.10%			5.65%	5.15%	1.50%	5.00%	6.25%	6.10%	5.40%	2.60%	6.55%	6.15%	4.10%
Variable rate bonds, par amounts						$ 20.0	$ 86.0

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Taxes

4. Income Taxes

In 2013, 2012 and 2011, TECO Energy recorded net tax provisions of $108.8 million, $160.2 million and $153.9 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes paid for income taxes as required for the alternative minimum tax, state income taxes, foreign income taxes and prior year audits in 2013, 2012 and 2011 were $1.8 million, $7.2 million and $9.4 million, respectively.

Income tax expense consists of the following:

Income Tax Expense (Benefit)
(millions) For the year ended Dec. 31,	2013			2012			2011
Continuing Operations
Current income taxes
Federal	$	2.2		$	15.7		$	0.0
State		(3.5	)		1.1			0.9
Deferred income taxes
Federal		98.6			102.9			124.0
State		11.9			18.4			18.2
Amortization of investment tax credits		(0.3	)		(0.3	)		(0.4	)
Income tax expense from continuing operations	$	108.9		$	137.8		$	142.7
Discontinued Operations
Current income taxes
Federal	$	0.0		$	0.0		$	0.0
Foreign		0.0			6.8			7.4
State		0.0			0.0			0.0
Deferred income taxes
Federal		(0.1	)		14.9			4.4
Foreign		0.0			0.0			(0.3	)
State		0.0			0.7			(0.3	)
Income tax expense from discontinued operations		(0.1	)		22.4			11.2
Total income tax expense	$	108.8		$	160.2		$	153.9

During 2013, TECO Energy increased its net operating loss carryforward. Total current income tax expense for the years ended Dec. 31, 2012 and 2011 was reduced by $13.6 million and $32.1 million, respectively, to reflect the benefits of operating loss carryforwards.

The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:

Effective Income Tax Rate
(millions) For the year ended Dec. 31,	2013			2012			2011
Income tax expense at the federal statutory rate of 35%	$	107.3		$	134.3		$	137.7
Increase (decrease) due to:
State income tax, net of federal income tax		5.5			12.7			12.4
Equity portion of AFUDC		(2.2	)		(0.9	)		(0.4	)
Valuation allowance		0.0			1.1			0.0
Depletion		(3.7	)		(8.5	)		(9.1	)
Other		2.0			(0.9	)		2.1
Total income tax expense from continuing operations	$	108.9		$	137.8		$	142.7
Income tax expense as a percent of income from continuing operations, before income taxes		35.5	%		35.9	%		36.3	%

For the three years presented, the overall effective tax rate on continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes offset by depletion.

As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2013 will be realized in future periods.

The major components of the company’s deferred tax assets and liabilities recognized are as follows:

Deferred Income Taxes
(millions)
As of Dec. 31,	2013			2012
Deferred tax liabilities (1)
Property related	$	1,164.2		$	1,023.3
Deferred fuel		1.6			11.3
Pension		52.8			43.0
Total deferred tax liabilities		1,218.6			1,077.6
Deferred tax assets (1)
Alternative minimum tax credit carryforward		213.0			211.8
Loss and credit carryforwards (2)		479.8			473.2
Other postretirement benefits		68.9			68.0
Other		113.2			113.0
Total deferred tax assets		874.9			866.0
Valuation allowance		0.0			(3.0	)
Total deferred tax assets, net of valuation allowance		874.9			863.0
Total deferred tax liability, net		343.7			214.6
Less: Current portion of deferred tax asset		(100.3	)		(63.3	)
Long-term portion of deferred tax liability, net	$	444.0		$	277.9

(1) Certain property related assets and liabilities have been netted.

(2) As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2013 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.

At Dec. 31, 2013, the company had cumulative unused federal and state (Florida) NOLs for income tax purposes of $1,321.9 million and $392.6 million, respectively, expiring at various times between 2025 and 2028. In addition, the company has unused general business credits of $3.9 million expiring between 2026 and 2032. Due to the sale of the company’s remaining Guatemalan operations, unused foreign tax credits of $38.5 million have been reclassed to net operating loss. During 2013, the company’s available alternative minimum tax credit carryforward for tax purposes increased from $211.8 million to $213.0 million, reflecting the future AMT payable for the amendment of prior years’ federal income tax returns to claim a deduction for foreign tax paid. The alternative minimum tax credit may be used indefinitely to reduce federal income taxes.

The company’s consolidated balance sheet reflects loss carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through a reduction in income taxes payable.

The company establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. A state capital loss carryforward valuation allowance of $3.0 million was recorded as of Dec. 31, 2012. For the year ended Dec. 31, 2013, the company recorded a full valuation allowance release of $3.0 million due to the expiration of the state capital loss carryforward.

The company accounts for uncertain tax positions in accordance with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Unrecognized Tax Benefits
(millions)	2013			2012
Balance at Jan. 1,	$	2.9		$	4.1
Decreases due to tax positions related to prior years		0.0			0.0
Decreases due to settlements with taxing authorities		0.0			0.0
Decreases due to expiration of statute of limitations		(2.9	)		0.0
Dispositions		0.0			(1.2	)
Balance at Dec. 31,	$	0.0		$	2.9

The company recognizes interest and penalties associated with uncertain tax positions in “Operation other expense – Other” in the Consolidated Statements of Income. In 2013, 2012 and 2011, the company recognized $(0.9) million, $0.3 million and $0.2 million, respectively, of pretax charges (benefits) for interest only. Additionally, the company had $0.0 million of interest accrued at Dec. 31, 2013 and $0.9 million of interest accrued at Dec. 31, 2012. No amounts have been recorded for penalties. As a result of the 2012 sale of TCAE, interest and penalties recorded on TCAE’s books for an uncertain tax position have been removed from the company’s unrecognized tax benefits (see Note 19).

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 the year 2010 and forward. The federal income tax return for calendar year 2013 is part of the IRS’s Compliance Assurance Program. As a result, the IRS audit of such return is expected to be completed in 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 taxing authorities in major state jurisdictions include 2010 and forward. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

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. For the three years presented, TEC’s effective tax rate differs from the statutory rate principally due to state income taxes, domestic production deduction and AFUDC equity benefit. The decrease in the 2013 effective tax rate compared to 2012 is principally due to equity portion of AFUDC.

Income tax expense consists of the following components:

Income Tax Expense (Benefit)
(millions) For the year ending Dec. 31,	2013			2012			2011
Current income taxes
Federal	$	19.4		$	(19.5	)	$	(30.7	)
State		1.3			5.6			2.9
Deferred income taxes
Federal		99.8			141.2			155.6
State		18.6			14.7			18.0
Amortization of investment tax credits		(0.3	)		(0.3	)		(0.4	)
Total income tax expense	$	138.8		$	141.7		$	145.4

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:

Effective Income Tax Rate
(millions) For the years ended Dec. 31,	2013			2012			2011
Income tax expense at the federal statutory rate of 35%	$	127.5		$	129.1		$	133.2
Increase (decrease) due to
State income tax, net of federal income tax		13.0			13.2			13.6
Equity portion of AFUDC		(2.2	)		(0.9	)		(0.4	)
Domestic production deduction		(0.6	)		(0.4	)		(1.5	)
Other		1.1			0.7			0.5
Total income tax expense on consolidated statements of income	$	138.8		$	141.7		$	145.4
Income tax expense as a percent of income from continuing operations, before income taxes		38.1	%		38.4	%		38.2	%

Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

Deferred Income Taxes
(millions) As of Dec. 31,	2013			2012
Deferred tax liabilities (1)
Property related	$	1,166.4		$	1,016.2
Deferred fuel		1.6			11.3
Pension and postretirement benefits		70.5			106.6
Pension		43.2			36.7
Other		0.0			22.2
Total deferred tax liabilities		1,281.7			1,193.0
Deferred tax assets (1)
Medical benefits		50.9			49.0
Insurance reserves		29.1			31.1
Investment tax credits		5.3			5.5
Hedging activities		4.9			5.5
Pension and postretirement benefits		70.5			106.6
Unbilled revenue		12.1			14.8
Capitalized energy conservation assistance costs		19.6			19.6
Other		4.4			0.0
Total deferred tax assets		196.8			232.1
Total deferred tax liability, net		1,084.9			960.9
Less: Current portion of deferred tax asset		(29.4	)		(20.0	)
Long-term portion of deferred tax liability, net	$	1,114.3		$	980.9

(1) Certain property related assets and liabilities have been netted.

TEC accounts for uncertain tax positions as required by FASB accounting guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, TEC may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

As of Dec. 31, 2013 and 2012, TEC did not have a liability for unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2014. As of Dec. 31, 2013, TEC does not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

The IRS concluded its examination of federal income tax returns for the year 2012 in January 2014. The U.S. federal statute of limitations remains open for the year 2010 and onward. The federal income tax return for calendar year 2013 is part of the IRS’s Compliance Assurance Program. As a result, the IRS audit of such return is expected to be completed in 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 onward. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

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Income Taxes - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]
Income Tax Expense Benefit	$ 108.8	$ 160.2	$ 153.9
Cash paid for income taxes	1.8	7.2	9.4
Use of operating loss carryforward		13.6	32.1
Effective tax rate	35.00%	35.00%	35.00%
Federal and state (Florida) net operating losses (NOL's) carry forward	1,321.9
Deferred tax assets expiration date	2025 and 2028
General business credit	3.9
Deferred tax general business credits expiration date	2026 and 2032
Foreign tax credits	38.5
Tax credit carry forwards	213.0	211.8
Valuation allowance release	3.0
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%
Interest charges associated with uncertain tax positions	(0.9)	0.3	0.2
Interest accrued	0	0.9
Penalties	0
Income tax examination period	1 year
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Federal and state (Florida) net operating losses (NOL's) carry forward	392.6
Capital loss carryforward valuation allowance		3.0
Minimum [Member]
Income Taxes [Line Items]
Effective tax rate	35.00%
Tax credit carry forwards	211.8
Statutes of limitations	3 years
Maximum [Member]
Income Taxes [Line Items]
Tax credit carry forwards	213.0
Statutes of limitations	4 years
Tampa Electric Company [Member]
Income Taxes [Line Items]
Cash paid for income taxes	$ 56.4	$ (9.7)	$ (31.1)
Effective tax rate	35.00%	35.00%	35.00%
Tax benefits, likelihood of being realized upon ultimate settlement	50.00%
Statutes of limitations	3 years
Income tax examination period	1 year

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Accounting for Derivative Instruments and Hedging Activities - Derivative Activity for Instruments Classified as Qualifying Cash Flow Hedges (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	$ 0.1	$ (0.9)	$ (0.3)
Amount of Gain/(Loss) Recognized in OCI	0.6	(4.6)	1.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	(0.8)	(0.4)	2.0
Diesel Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0.1	(0.9)	(0.3)
Amount of Gain/(Loss) Recognized in OCI	0.6	0.3	1.2
Amount of Gain/(Loss) Reclassified From AOCI Into Income	0.1	0.4	2.7
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value Asset/(Liability)	0	0	0
Amount of Gain/(Loss) Recognized in OCI	0	(4.9)	0
Amount of Gain/(Loss) Reclassified From AOCI Into Income	$ (0.9)	$ (0.8)	$ (0.7)

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

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Income Taxes - Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Income tax expense at the federal statutory rate of 35%	$ 107.3	$ 134.3	$ 137.7
State income tax, net of federal income tax	5.5	12.7	12.4
Equity portion of AFUDC	(2.2)	(0.9)	(0.4)
Valuation allowance	0	1.1	0
Depletion	(3.7)	(8.5)	(9.1)
Other	2.0	(0.9)	2.1
Income tax expense from continuing operations	108.9	137.8	142.7
Income tax expense as a percent of income from continuing operations, before income taxes	35.50%	35.90%	36.30%
Tampa Electric Company [Member]
Schedule Of Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Line Items]
Income tax expense at the federal statutory rate of 35%	127.5	129.1	133.2
State income tax, net of federal income tax	13.0	13.2	13.6
Equity portion of AFUDC	(2.2)	(0.9)	(0.4)
Domestic production deduction	(0.6)	(0.4)	(1.5)
Other	1.1	0.7	0.5
Income tax expense from continuing operations	$ 138.8	$ 141.7	$ 145.4
Income tax expense as a percent of income from continuing operations, before income taxes	38.10%	38.40%	38.20%

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 4.9	$ 5.8
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other benefit gain (loss), prior service cost (credit) and transition obligation, tax expense (benefit)	12.6	20.1
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other benefit gain (loss), prior service cost (credit) and transition obligation, tax expense (benefit)	9.1	6.7
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges, tax benefit	$ 4.9	$ 5.5

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Regulatory - Regulatory Assets and Related Recovery Periods (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory assets	$ 327.4	$ 452.9
Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	327.4	452.9
Clause Recoverable [Member]
Regulatory Assets [Line Items]
Regulatory assets	10.2	47.0
Clause Recoverable [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	10.2	47.0
Components of Rate Base [Member]
Regulatory Assets [Line Items]
Regulatory assets	185.6	279.1
Components of Rate Base [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	185.6	279.1
Regulatory Tax Asset [Member]
Regulatory Assets [Line Items]
Regulatory assets	67.4	67.2
Regulatory Tax Asset [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	67.4	67.2
Capital Structure and Other [Member]
Regulatory Assets [Line Items]
Regulatory assets	64.2	59.6
Capital Structure and Other [Member] | Tampa Electric Company [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 64.2	$ 59.6

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Common Stock - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested awards compensation costs, period for recognition	2 years
Actual restricted shares granted	700,000	1,000,000	800,000
Granted, weighted average grant date fair value	$ 17.21	$ 15.96	$ 18.44
Total fair market value of awards vesting	$ 3.5	$ 14.3	$ 13.4
Unrecognized compensation cost related to all non-vested awards	15.5
Aggregate intrinsic value of stock options exercised	2.4	0.3	1.5
Cash received from all option exercises	6.7	1.1	5.0
Income tax benefit realized from stock option exercises	$ 0.8	$ 0.1	$ 0.6
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of performance based grants can vest	150.00%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of performance based grants can vest	0.00%
2010 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reduction in number of shares of common stock subject to grants	3,000,000
Common stock subject to grant	4,000,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested awards compensation costs, period for recognition	3 years
Director Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Time-vested restricted stock granted to directors, vesting period	1 year

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Goodwill and Asset Impairments - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill And Long Lived Asset Impairment [Line Items]
Impairment charge	$ 0	$ 17.2	$ 0
TGS [Member]
Goodwill And Long Lived Asset Impairment [Line Items]
Long-lived asset pretax impairment charge	2.0
TECO Coal [Member]
Goodwill And Long Lived Asset Impairment [Line Items]
Impairment charge	$ 0
Effects of inflation rate	1.00%	1.00%

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Pending Acquisition of New Mexico Gas Company

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Pending Acquisition of New Mexico Gas Company

22. Pending Acquisition of New Mexico Gas Company

Stock Purchase Agreement

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

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

As previously reported, the company must obtain regulatory approvals from the NMPRC prior to consummating the pending acquisition of NMGC. On Jan. 10, 2014 a meeting was held with the joint applicants, hearing examiner, the NMPRC staff, and intervenors to establish an updated schedule. Based on this schedule, Staff and intervenor testimony is expected to occur on Feb. 28, with hearings to follow on March 24 – 28. The date for a final decision is yet to be determined. The company has indicated that the closing is likely to occur in the third quarter of 2014.

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

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

TECO Finance Bridge Facility

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

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

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

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

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

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

TECO Energy Credit Agreement to be Assigned to and Assumed by NMGC

In connection with the pending Acquisition, on Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility, pursuant to which it is the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy has no rights or obligations to borrow under the NMGC Credit Agreement, which it has entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, upon such closing, TECO Energy will designate NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder and Release Agreement duly executed by TECO Energy and NMGC, whereupon and upon the satisfaction of the other conditions precedent set forth in the NMGC Credit Agreement, (i) NMGC shall automatically become the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy shall cease to be a party to the NMGC Credit Agreement and shall have no further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) will allow NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, will allow NMGC to borrow funds at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) will allow NMGC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) will allow NMGC to request the lenders to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2013

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

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

Total Derivatives
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.7	$	0.0
Long-term assets		0.3		0.2
Total assets	$	10.0	$	0.2
Current liabilities	$	0.1	$	14.6
Long-term liabilities		0.2		0.6
Total liabilities	$	0.3	$	15.2

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

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
Dec. 31, 2013
Description
Derivative assets	$	10.5		$	(0.5	)	$	10.0
Derivative liabilities	$	(0.8	)	$	0.5		$	(0.3	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(16.0	)	$	0.8		$	(15.2	)

Effect of Hedging Instruments on OCI and Income

The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31:

	Amount of Gain/(Loss) on Derivatives Recognized in			Location of Gain/(Loss) Reclassified From AOCI	Gain/(Loss) Reclassified From
(millions)	OCI			Into Income	AOCI Into Income
Derivatives in Cash Flow Hedging Relationships		Effective Portion (1)		Effective Portion (1)
2013
Interest rate contracts:	$	0.0		Interest expense	($	0.9	)
Commodity contracts:
Diesel fuel derivatives		0.6		Mining related costs		0.1
Total	$	0.6			($	0.8	)
2012
Interest rate contracts:	($	4.9	)	Interest expense	($	0.8	)
Commodity contracts:
Diesel fuel derivatives		0.3		Mining related costs		0.4
Total	($	4.6	)		($	0.4	)
2011
Interest rate contracts:	$	0.0		Interest expense	($	0.7	)
Commodity contracts:
Diesel fuel derivatives		1.2		Mining related costs		2.7
Total	$	1.2			$	2.0

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

 

(millions)	Fair Value Asset/(Liability)			Amount of Gain/(Loss) Recognized in OCI (1)			Amount of Gain/(Loss) Reclassified From AOCI Into Income (1)
2013
Interest rate swaps	$	0.0		$	0.0		($	0.9	)
Diesel fuel derivatives		0.1			0.6			0.1
Total	$	0.1		$	0.6		($	0.8	)
2012
Interest rate swaps	$	0.0		($	4.9	)	($	0.8	)
Diesel fuel derivatives		(0.9	)		0.3			0.4
Total	($	0.9	)	($	4.6	)	($	0.4	)
2011
Interest rate swaps	$	0.0		$	0.0		($	0.7	)
Diesel fuel derivatives		(0.3	)		1.2			2.7
Total	($	0.3	)	$	1.2		$	2.0

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

Derivative Volumes Expected to Settle

The following table presents by commodity type the company’s derivative volumes that, as of Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:

	Diesel Fuel Contracts				Natural Gas Contracts
(millions)	(Gallons)				(MMBTUs)
Year	Physical		Financial		Physical		Financial
2014		0.0		2.0		0.0		36.9
2015		0.0		0.0		0.0		7.6
Total		0.0		2.0		0.0		44.5

Fair Value of Overall Contractual Contingent Liability Positions

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

Contingent Features
(millions)	Fair Value Asset/ (Liability)			Derivative Exposure Asset/ (Liability)			Posted Collateral
Credit Rating	($	0.1	)	($	0.1	)	$	0.0

Derivatives Designated as Hedging Instruments [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

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

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

Diesel Fuel Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

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

Diesel Fuel Derivatives
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	0.2	$	0.0
Long-term assets		0.0		0.0
Total assets	$	0.2	$	0.0
Current liabilities	$	0.1	$	0.5
Long-term liabilities		0.0		0.4
Total liabilities	$	0.1	$	0.9

Natural Gas Derivatives [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

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

Natural Gas Derivatives (1)
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.5	$	0.0
Long-term assets		0.3		0.2
Total assets	$	9.8	$	0.2
Current liabilities	$	0.0	$	14.1
Long-term liabilities		0.2		0.2
Total liabilities	$	0.2	$	14.3

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

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 on the Consolidated Balance Sheets as of Dec. 31, 2013 and 2012:

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

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

Tampa Electric Company [Member]

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

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

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

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

Gross Amounts of Derivatives and Their Related Offset Amounts

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements at Dec. 31, 2013 and Dec. 31, 2012.

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
Dec. 31, 2013
Description
Derivative assets	$	10.3		$	(0.5	)	$	9.8
Derivative liabilities	$	(0.7	)	$	0.5		$	(0.2	)
Dec. 31, 2012
Description
Derivative assets	$	1.0		$	(0.8	)	$	0.2
Derivative liabilities	$	(15.1	)	$	0.8		$	(14.3	)

Effect of Hedging Instruments on OCI and Income

The following table presents the effect of hedging instruments on OCI and income for the years ended Dec. 31, 2013, 2012 and 2011:

(millions)	Location of Gain/(Loss) Reclassified From AOCI Into Income	Amount of Gain/(Loss) Reclassified From AOCI Into Income
For the years ended Dec. 31:		2013			2012			2011
Derivatives in Cash Flow Hedging Relationships	Effective Portion (1)
Interest rate contracts:	Interest expense	($	0.9	)	($	0.8	)	($	0.7	)
Total		($	0.9	)	($	0.8	)	($	0.7	)

(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 Dec. 31, 2013, are expected to settle during the 2014 and 2015 fiscal years:

(millions)	Natural Gas Contracts (MMBTUs)
Year	Physical		Financial
2014		0.0		36.9
2015		0.0		7.6
Total		0.0		44.5

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

Fair Values and Locations of Derivative Instruments Recorded on Balance Sheet

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

Natural Gas Derivatives (1)
(millions)	Dec. 31, 2013		Dec. 31, 2012
Current assets	$	9.5	$	0.0
Long-term assets		0.3		0.2
Total assets	$	9.8	$	0.2
Current liabilities	$	0.0	$	14.1
Long-term liabilities		0.2		0.2
Total liabilities	$	0.2	$	14.3

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

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Common Stock

12 Months Ended

Dec. 31, 2013

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Common Stock

9. Common Stock

Stock-Based Compensation

On May 5, 2010, the shareholders approved the 2010 Equity Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors.

The 2010 Plan amended the 2004 Plan to reduce the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), remove the cap on shares available for stock grant, place various limitations on the terms of awards granted under the 2010 Plan, remove the ability to make awards to consultants of the company and reapprove the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code.

The types of awards that can be granted under the 2010 Plan include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest between 0% and 150% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant.

The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.

The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.

Assumptions	2013			2012			2011
Assumptions applicable to performance-based restricted stock
Risk-free interest rate		0.41	%		0.38	%		0.96	%
Expected lives (in years)		3			3			3
Expected stock volatility		19.04	%		20.99	%		34.61	%
Dividend yield		4.83	%		4.78	%		4.48	%

In 2013, 2012 and 2011, 0.7 million, 1.0 million and 0.8 million shares of restricted stock were granted, respectively, with weighted-average fair values per share of $17.21, $15.96 and $18.44 , respectively. The total fair market value of awards vesting during 2013, 2012 and 2011 was $3.5 million, $14.3 million and $13.4 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2013, there was $15.5 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted-average period of two years.

The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.

(millions)	2013		2012		2011
Compensation costs (1)	$	13.5	$	12.0	$	9.1
Income tax benefits (1)		5.2		4.6		3.5
Excess tax benefits (2)		0.0		2.6		1.7

(1) Reflected on the Consolidated Statements of Income.

(2) Reflected as financing activities on the Consolidated Statements of Cash Flows.

The aggregate intrinsic value of stock options exercised was $2.4 million, $0.3 million and $1.5 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively. Cash received from option exercises under all share-based payment arrangements was $6.7 million, $1.1 million and $5.0 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively. The income tax benefit realized from stock option exercises was $0.8 million, $0.1 million and $0.6 million for the periods ended Dec. 31, 2013, 2012 and 2011, respectively.

A summary of non-vested shares of restricted stock is shown as follows:

Nonvested Restricted Stock
	Time-Based Restricted					Performance-Based
	Stock (1)					Restricted Stock (1)
	Number of Shares (thousands)			Weighted - Avg. Grant Date Fair Value (per share)		Number of Shares (thousands)			Weighted- Avg. Grant Date Fair Value (per share)
Nonvested balance at Dec. 31, 2012		592		$	18.04		1,490		$	17.13
Granted		237			17.92		496			16.87
Vested		(187	)		16.91		(434	)		17.20
Forfeited		(4	)		17.99		(47	)		16.82
Nonvested balance at Dec. 31, 2013		638		$	18.33		1,505		$	17.04

(1) The weighted-average remaining contractual term of restricted stock is two years.

Stock option transactions are summarized as follows:

Stock Options
	Number of Shares (thousands)			Weighted-Avg. Option Price (per share)		Weighted-Avg. Remaining Contractual Term (years)	Aggregate Intrinsic Value (millions)
Outstanding balance at Dec. 31, 2012		2,087		$	15.05
Granted		0			0.00
Exercised		(507	)		13.22
Cancelled		(13	)		18.87
Outstanding balance at Dec. 31, 2013 (1)		1,567		$	15.62	2	$	2.6
Exercisable at Dec. 31, 2013 (1)		1,567		$	15.62	2	$	2.6
Available for future grant at Dec. 31, 2013		2,725

(1) Option prices range from $12.01 to $19.01 per share.

As of Dec. 31, 2013, the options outstanding and exercisable are summarized below:

Range of Option Prices (per share)	Option Shares (thousands)		Weighted-Avg. Option Price (per share)		Weighted-Avg. Remaining Contractual Life
$12.01 - $13.56		331	$	13.10	1 Years
$16.21 - $19.01		1,236	$	16.29	2 Years
Total		1,567	$	15.62	2 Years

Dividend Reinvestment Plan

In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2013, 2012 and 2011, resulting in no increase in equity.

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Accounting for Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Collateral posted with or received from any counterparties	$ 0	$ 0
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.8	9.2
Net pretax losses expected to be reclassified from regulatory assets or liabilities	9.5
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, 2015
Tampa Electric Company [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	7.8	8.7
Net pretax losses expected to be reclassified from regulatory assets or liabilities	9.5
Interest Rate Swap [Member]
Derivative [Line Items]
Net loss related to cash flow hedges and interest rate swaps in AOCI, after tax	$ 7.8	$ 9.2

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Segment Information

12 Months Ended

Dec. 31, 2013

Segment Information

14. Segment Information

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

Segment Information
(millions)	Tampa Electric		PGS		TECO Coal			TECO Guatemala			Other & Eliminations			TECO Energy
2013
Revenues - external	$	1,949.6	$	392.7	$	496.2		$	0.0		$	12.8		$	2,851.3
Sales to affiliates		0.9		0.8		0.0			0.0			(1.7	)		0.0
Total revenues		1,950.5		393.5		496.2			0.0			11.1			2,851.3
Depreciation and amortization		238.8		51.5		37.7			0.0			1.5			329.5
Total interest charges (1)		91.8		13.5		5.5			0.0			56.1			166.9
Internally allocated interest (1)		0.0		0.0		6.4			0.0			(6.4	)		0.0
Provision for income taxes		116.9		21.9		(3.6	)		0.0			(26.3	)		108.9
Net income from continuing operations		190.9		34.7		9.0			0.0			(36.8	)		197.8
Discontinued operations attributable to TECO, net of tax		0.0		0.0		0.0			0.0			(0.1	)		(0.1	)
Net income attributable to TECO Energy		190.9		34.7		9.0			0.0			(36.9	)		197.7
Total assets		6,126.9		1,021.2		316.3	(3)		0.0			(16.4	)		7,448.0
Capital expenditures		428.6		79.0		22.4			0.0			2.4			532.4
2012
Revenues - external	$	1,980.7	$	396.6	$	608.9		$	0.0		$	10.4		$	2,996.6
Sales to affiliates		0.6		2.3		0.0			0.0			(2.9	)		0.0
Total revenues		1,981.3		398.9		608.9			0.0			7.5			2,996.6
Depreciation and amortization		237.6		50.6		41.0			0.0			1.4			330.6
Total interest charges (1)		109.8		16.0		7.1			0.0			50.6			183.5
Internally allocated interest (1)		0.0		0.0		6.8			0.0			(6.8	)		0.0
Provision for income taxes		120.2		21.5		15.7			0.0			(19.6	)		137.8
Net income from continuing operations		193.1		34.1		50.2			0.0			(31.4	)		246.0
Discontinued operations attributable to TECO, net of tax		0.0		0.0		0.0			(29.3	)		(4.0	)		(33.3	)
Net income attributable to TECO Energy		193.1		34.1		50.2			(29.3	)		(35.4	)		212.7
Total assets		6,042.3		1,009.9		356.6	(3)		164.9			(238.8	)		7,334.9
Capital expenditures		361.7		97.3		36.3			8.6			1.2			505.1
2011
Revenues - external	$	2,019.3	$	450.5	$	733.0		$	0.0		$	7.1		$	3,209.9
Sales to affiliates		1.3		3.0		0.0			0.0			(4.3	)		0.0
Total revenues		2,020.6		453.5		733.0			0.0			2.8			3,209.9
Depreciation and amortization		222.1		48.4		45.3			0.0			1.4			317.2
Total interest charges (1)		121.8		17.7		6.9			0.0			51.0			197.4
Internally allocated interest (1)		0.0		0.0		6.7			0.0			(6.7	)		0.0
Provision for income taxes		124.8		20.6		15.4			0.0			(18.1	)		142.7
Net income from continuing operations		202.7		32.6		51.5			0.0			(36.0	)		250.8
Discontinued operations attributable to TECO, net of tax (2)		0.0		0.0		0.0			22.4			(0.6	)		21.8
Net income attributable to TECO Energy		202.7		32.6		51.5			22.4			(36.6	)		272.6
Goodwill		0.0		0.0		0.0			55.4			0.0			55.4
Total assets		5,925.9		932.0		385.2	(3)		304.1			(240.0	)		7,307.2
Capital expenditures		314.9		71.9		56.6			7.2			3.5			454.1

(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 2013 and 2012 were at a pretax rate of 6.00%, and for 2011 were at a pretax rate of 6.25%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. See Note 19.

(3) The carrying value of mineral rights as of Dec. 31, 2013, 2012 and 2011 was $12.1 million, $13.4 million and $15.0 million, respectively.

Tampa Electric provides retail electric utility services to almost 700,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for almost 350,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

TECO Coal, through its wholly-owned subsidiaries, owns mineral rights and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia.

Tampa Electric Company [Member]

Segment Information

11. Segment Information

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 700,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for almost 350,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

	Tampa				Other &
(millions)	Electric		PGS		Eliminations			TEC
2013
Revenues - external	$	1,950.1	$	392.7	$	0.0		$	2,342.8
Sales to affiliates		0.4		0.8		(1.2	)		0.0
Total revenues		1,950.5		393.5		(1.2	)		2,342.8
Depreciation and amortization		238.8		51.5		0.0			290.3
Total interest charges		91.8		13.5		0.0			105.3
Provision for income taxes		116.9		21.9		0.0			138.8
Net income		190.9		34.7		0.0			225.6
Total assets		5,895.4		989.3		(8.9	)		6,875.8
Capital expenditures		428.6		79.0		0.0			507.6
2012
Revenues - external	$	1,980.9	$	397.1	$	0.0		$	2,378.0
Sales to affiliates		0.4		1.8		(2.2	)		0.0
Total revenues		1,981.3		398.9		(2.2	)		2,378.0
Depreciation and amortization		237.6		50.6		0.0			288.2
Total interest charges		109.8		16.0		0.0			125.8
Provision for income taxes		120.2		21.5		0.0			141.7
Net income		193.1		34.1		0.0			227.2
Total assets		5,760.4		970.9		13.3			6,744.6
Capital expenditures		361.7		97.3		0.0			459.0
2011
Revenues - external	$	2,020.1	$	450.5	$	0.0		$	2,470.6
Sales to affiliates		0.5		3.0		(3.5	)		0.0
Total revenues		2,020.6		453.5		(3.5	)		2,470.6
Depreciation and amortization		222.1		48.4		0.0			270.5
Total interest charges		121.8		17.7		0.0			139.5
Provision for income taxes		124.8		20.6		0.0			145.4
Net income		202.7		32.6		0.0			235.3
Total assets		5,678.0		888.4		(10.0	)		6,556.4
Capital expenditures		314.9		71.9		0.0			386.8

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Common Stock - Summary of Non-Vested Shares of Restricted Stock (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Number of Shares	700	1,000	800
Granted, weighted average grant date fair value	$ 17.21	$ 15.96	$ 18.44
Time-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested balance at Dec. 31, 2012, Number of Shares	592
Granted, Number of Shares	237
Vested, Number of Shares	(187)
Forfeited, Number of Shares	(4)
Nonvested balance at Dec. 31, 2013, Number of Shares	638
Nonvested balance at Dec. 31, 2012, Weighted Average Grant Date Fair Value	$ 18.04
Granted, weighted average grant date fair value	$ 17.92
Vested, Weighted Average Grant Date Fair Value	$ 16.91
Forfeited, Weighted Average Grant Date Fair Value	$ 17.99
Nonvested balance at Dec. 31, 2013, Weighted Average Grant Date Fair Value	$ 18.33
Performance-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested balance at Dec. 31, 2012, Number of Shares	1,490
Granted, Number of Shares	496
Vested, Number of Shares	(434)
Forfeited, Number of Shares	(47)
Nonvested balance at Dec. 31, 2013, Number of Shares	1,505	1,490
Nonvested balance at Dec. 31, 2012, Weighted Average Grant Date Fair Value	$ 17.04	$ 17.13
Granted, weighted average grant date fair value		$ 16.87
Vested, Weighted Average Grant Date Fair Value		$ 17.20
Forfeited, Weighted Average Grant Date Fair Value		$ 16.82
Nonvested balance at Dec. 31, 2013, Weighted Average Grant Date Fair Value		$ 17.04

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Segment Information

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

Segment Information
(millions)	Tampa Electric		PGS		TECO Coal			TECO Guatemala			Other & Eliminations			TECO Energy
2013
Revenues - external	$	1,949.6	$	392.7	$	496.2		$	0.0		$	12.8		$	2,851.3
Sales to affiliates		0.9		0.8		0.0			0.0			(1.7	)		0.0
Total revenues		1,950.5		393.5		496.2			0.0			11.1			2,851.3
Depreciation and amortization		238.8		51.5		37.7			0.0			1.5			329.5
Total interest charges (1)		91.8		13.5		5.5			0.0			56.1			166.9
Internally allocated interest (1)		0.0		0.0		6.4			0.0			(6.4	)		0.0
Provision for income taxes		116.9		21.9		(3.6	)		0.0			(26.3	)		108.9
Net income from continuing operations		190.9		34.7		9.0			0.0			(36.8	)		197.8
Discontinued operations attributable to TECO, net of tax		0.0		0.0		0.0			0.0			(0.1	)		(0.1	)
Net income attributable to TECO Energy		190.9		34.7		9.0			0.0			(36.9	)		197.7
Total assets		6,126.9		1,021.2		316.3	(3)		0.0			(16.4	)		7,448.0
Capital expenditures		428.6		79.0		22.4			0.0			2.4			532.4
2012
Revenues - external	$	1,980.7	$	396.6	$	608.9		$	0.0		$	10.4		$	2,996.6
Sales to affiliates		0.6		2.3		0.0			0.0			(2.9	)		0.0
Total revenues		1,981.3		398.9		608.9			0.0			7.5			2,996.6
Depreciation and amortization		237.6		50.6		41.0			0.0			1.4			330.6
Total interest charges (1)		109.8		16.0		7.1			0.0			50.6			183.5
Internally allocated interest (1)		0.0		0.0		6.8			0.0			(6.8	)		0.0
Provision for income taxes		120.2		21.5		15.7			0.0			(19.6	)		137.8
Net income from continuing operations		193.1		34.1		50.2			0.0			(31.4	)		246.0
Discontinued operations attributable to TECO, net of tax		0.0		0.0		0.0			(29.3	)		(4.0	)		(33.3	)
Net income attributable to TECO Energy		193.1		34.1		50.2			(29.3	)		(35.4	)		212.7
Total assets		6,042.3		1,009.9		356.6	(3)		164.9			(238.8	)		7,334.9
Capital expenditures		361.7		97.3		36.3			8.6			1.2			505.1
2011
Revenues - external	$	2,019.3	$	450.5	$	733.0		$	0.0		$	7.1		$	3,209.9
Sales to affiliates		1.3		3.0		0.0			0.0			(4.3	)		0.0
Total revenues		2,020.6		453.5		733.0			0.0			2.8			3,209.9
Depreciation and amortization		222.1		48.4		45.3			0.0			1.4			317.2
Total interest charges (1)		121.8		17.7		6.9			0.0			51.0			197.4
Internally allocated interest (1)		0.0		0.0		6.7			0.0			(6.7	)		0.0
Provision for income taxes		124.8		20.6		15.4			0.0			(18.1	)		142.7
Net income from continuing operations		202.7		32.6		51.5			0.0			(36.0	)		250.8
Discontinued operations attributable to TECO, net of tax (2)		0.0		0.0		0.0			22.4			(0.6	)		21.8
Net income attributable to TECO Energy		202.7		32.6		51.5			22.4			(36.6	)		272.6
Goodwill		0.0		0.0		0.0			55.4			0.0			55.4
Total assets		5,925.9		932.0		385.2	(3)		304.1			(240.0	)		7,307.2
Capital expenditures		314.9		71.9		56.6			7.2			3.5			454.1

(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 2013 and 2012 were at a pretax rate of 6.00%, and for 2011 were at a pretax rate of 6.25%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala. See Note 19.

(3) The carrying value of mineral rights as of Dec. 31, 2013, 2012 and 2011 was $12.1 million, $13.4 million and $15.0 million, respectively.

Tampa Electric Company [Member]

Schedule of Segment Information

	Tampa				Other &
(millions)	Electric		PGS		Eliminations			TEC
2013
Revenues - external	$	1,950.1	$	392.7	$	0.0		$	2,342.8
Sales to affiliates		0.4		0.8		(1.2	)		0.0
Total revenues		1,950.5		393.5		(1.2	)		2,342.8
Depreciation and amortization		238.8		51.5		0.0			290.3
Total interest charges		91.8		13.5		0.0			105.3
Provision for income taxes		116.9		21.9		0.0			138.8
Net income		190.9		34.7		0.0			225.6
Total assets		5,895.4		989.3		(8.9	)		6,875.8
Capital expenditures		428.6		79.0		0.0			507.6
2012
Revenues - external	$	1,980.9	$	397.1	$	0.0		$	2,378.0
Sales to affiliates		0.4		1.8		(2.2	)		0.0
Total revenues		1,981.3		398.9		(2.2	)		2,378.0
Depreciation and amortization		237.6		50.6		0.0			288.2
Total interest charges		109.8		16.0		0.0			125.8
Provision for income taxes		120.2		21.5		0.0			141.7
Net income		193.1		34.1		0.0			227.2
Total assets		5,760.4		970.9		13.3			6,744.6
Capital expenditures		361.7		97.3		0.0			459.0
2011
Revenues - external	$	2,020.1	$	450.5	$	0.0		$	2,470.6
Sales to affiliates		0.5		3.0		(3.5	)		0.0
Total revenues		2,020.6		453.5		(3.5	)		2,470.6
Depreciation and amortization		222.1		48.4		0.0			270.5
Total interest charges		121.8		17.7		0.0			139.5
Provision for income taxes		124.8		20.6		0.0			145.4
Net income		202.7		32.6		0.0			235.3
Total assets		5,678.0		888.4		(10.0	)		6,556.4
Capital expenditures		314.9		71.9		0.0			386.8

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Commitments and Contingencies - Schedule of Future Minimum Lease Payments (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Long Term Commitments [Line Items]
Future Minimum Lease and Capacity Payments, 2014	$ 19.8
Future Minimum Lease and Capacity Payments, 2015	18.8
Future Minimum Lease and Capacity Payments, 2016	17.2
Future Minimum Lease and Capacity Payments, 2017	12.3
Future Minimum Lease and Capacity Payments, 2018	12.3
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	93.8
Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Future Minimum Lease and Capacity Payments, 2014	17.1
Future Minimum Lease and Capacity Payments, 2015	17.2
Future Minimum Lease and Capacity Payments, 2016	16.8
Future Minimum Lease and Capacity Payments, 2017	12.1
Future Minimum Lease and Capacity Payments, 2018	12.3
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	88.9
Capacity Payments [Member]
Long Term Commitments [Line Items]
Future Minimum Lease and Capacity Payments, 2014	14.8
Future Minimum Lease and Capacity Payments, 2015	14.9
Future Minimum Lease and Capacity Payments, 2016	14.6
Future Minimum Lease and Capacity Payments, 2017	9.9
Future Minimum Lease and Capacity Payments, 2018	10.1
Future Minimum Lease and Capacity Payments, Thereafter	0
Total future minimum payments	64.3
Capacity Payments [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Future Minimum Lease and Capacity Payments, 2014	14.8
Future Minimum Lease and Capacity Payments, 2015	14.9
Future Minimum Lease and Capacity Payments, 2016	14.6
Future Minimum Lease and Capacity Payments, 2017	9.9
Future Minimum Lease and Capacity Payments, 2018	10.1
Future Minimum Lease and Capacity Payments, Thereafter	0
Total future minimum payments	64.3
Operating Leases [Member]
Long Term Commitments [Line Items]
Future Minimum Lease and Capacity Payments, 2014	5.0
Future Minimum Lease and Capacity Payments, 2015	3.9
Future Minimum Lease and Capacity Payments, 2016	2.6
Future Minimum Lease and Capacity Payments, 2017	2.4
Future Minimum Lease and Capacity Payments, 2018	2.2
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	29.5
Operating Leases [Member] | Tampa Electric Company [Member]
Long Term Commitments [Line Items]
Future Minimum Lease and Capacity Payments, 2014	2.3
Future Minimum Lease and Capacity Payments, 2015	2.3
Future Minimum Lease and Capacity Payments, 2016	2.2
Future Minimum Lease and Capacity Payments, 2017	2.2
Future Minimum Lease and Capacity Payments, 2018	2.2
Future Minimum Lease and Capacity Payments, Thereafter	13.4
Total future minimum payments	$ 24.6

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Schedule of Income Tax Expense

Income tax expense consists of the following:

Income Tax Expense (Benefit)
(millions) For the year ended Dec. 31,	2013			2012			2011
Continuing Operations
Current income taxes
Federal	$	2.2		$	15.7		$	0.0
State		(3.5	)		1.1			0.9
Deferred income taxes
Federal		98.6			102.9			124.0
State		11.9			18.4			18.2
Amortization of investment tax credits		(0.3	)		(0.3	)		(0.4	)
Income tax expense from continuing operations	$	108.9		$	137.8		$	142.7
Discontinued Operations
Current income taxes
Federal	$	0.0		$	0.0		$	0.0
Foreign		0.0			6.8			7.4
State		0.0			0.0			0.0
Deferred income taxes
Federal		(0.1	)		14.9			4.4
Foreign		0.0			0.0			(0.3	)
State		0.0			0.7			(0.3	)
Income tax expense from discontinued operations		(0.1	)		22.4			11.2
Total income tax expense	$	108.8		$	160.2		$	153.9

Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes

The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:

Effective Income Tax Rate
(millions) For the year ended Dec. 31,	2013			2012			2011
Income tax expense at the federal statutory rate of 35%	$	107.3		$	134.3		$	137.7
Increase (decrease) due to:
State income tax, net of federal income tax		5.5			12.7			12.4
Equity portion of AFUDC		(2.2	)		(0.9	)		(0.4	)
Valuation allowance		0.0			1.1			0.0
Depletion		(3.7	)		(8.5	)		(9.1	)
Other		2.0			(0.9	)		2.1
Total income tax expense from continuing operations	$	108.9		$	137.8		$	142.7
Income tax expense as a percent of income from continuing operations, before income taxes		35.5	%		35.9	%		36.3	%

Schedule of Deferred Tax Assets and Liabilities

The major components of the company’s deferred tax assets and liabilities recognized are as follows:

Deferred Income Taxes
(millions)
As of Dec. 31,	2013			2012
Deferred tax liabilities (1)
Property related	$	1,164.2		$	1,023.3
Deferred fuel		1.6			11.3
Pension		52.8			43.0
Total deferred tax liabilities		1,218.6			1,077.6
Deferred tax assets (1)
Alternative minimum tax credit carryforward		213.0			211.8
Loss and credit carryforwards (2)		479.8			473.2
Other postretirement benefits		68.9			68.0
Other		113.2			113.0
Total deferred tax assets		874.9			866.0
Valuation allowance		0.0			(3.0	)
Total deferred tax assets, net of valuation allowance		874.9			863.0
Total deferred tax liability, net		343.7			214.6
Less: Current portion of deferred tax asset		(100.3	)		(63.3	)
Long-term portion of deferred tax liability, net	$	444.0		$	277.9

(1) Certain property related assets and liabilities have been netted.

(2) As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2013 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $1.1 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.

Schedule of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Unrecognized Tax Benefits
(millions)	2013			2012
Balance at Jan. 1,	$	2.9		$	4.1
Decreases due to tax positions related to prior years		0.0			0.0
Decreases due to settlements with taxing authorities		0.0			0.0
Decreases due to expiration of statute of limitations		(2.9	)		0.0
Dispositions		0.0			(1.2	)
Balance at Dec. 31,	$	0.0		$	2.9

Tampa Electric Company [Member]

Schedule of Income Tax Expense

Income tax expense consists of the following components:

Income Tax Expense (Benefit)
(millions) For the year ending Dec. 31,	2013			2012			2011
Current income taxes
Federal	$	19.4		$	(19.5	)	$	(30.7	)
State		1.3			5.6			2.9
Deferred income taxes
Federal		99.8			141.2			155.6
State		18.6			14.7			18.0
Amortization of investment tax credits		(0.3	)		(0.3	)		(0.4	)
Total income tax expense	$	138.8		$	141.7		$	145.4

Schedule of Income Taxes Calculated on Income before Income Taxes and Provision for Income Taxes

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:

Effective Income Tax Rate
(millions) For the years ended Dec. 31,	2013			2012			2011
Income tax expense at the federal statutory rate of 35%	$	127.5		$	129.1		$	133.2
Increase (decrease) due to
State income tax, net of federal income tax		13.0			13.2			13.6
Equity portion of AFUDC		(2.2	)		(0.9	)		(0.4	)
Domestic production deduction		(0.6	)		(0.4	)		(1.5	)
Other		1.1			0.7			0.5
Total income tax expense on consolidated statements of income	$	138.8		$	141.7		$	145.4
Income tax expense as a percent of income from continuing operations, before income taxes		38.1	%		38.4	%		38.2	%

Schedule of Deferred Tax Assets and Liabilities

The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

Deferred Income Taxes
(millions) As of Dec. 31,	2013			2012
Deferred tax liabilities (1)
Property related	$	1,166.4		$	1,016.2
Deferred fuel		1.6			11.3
Pension and postretirement benefits		70.5			106.6
Pension		43.2			36.7
Other		0.0			22.2
Total deferred tax liabilities		1,281.7			1,193.0
Deferred tax assets (1)
Medical benefits		50.9			49.0
Insurance reserves		29.1			31.1
Investment tax credits		5.3			5.5
Hedging activities		4.9			5.5
Pension and postretirement benefits		70.5			106.6
Unbilled revenue		12.1			14.8
Capitalized energy conservation assistance costs		19.6			19.6
Other		4.4			0.0
Total deferred tax assets		196.8			232.1
Total deferred tax liability, net		1,084.9			960.9
Less: Current portion of deferred tax asset		(29.4	)		(20.0	)
Long-term portion of deferred tax liability, net	$	1,114.3		$	980.9

(1) Certain property related assets and liabilities have been netted.

XML

Related Parties - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Legal fees	$ 1.7	$ 1.3	$ 1.3
Tampa Electric Company [Member]
Related Party Transaction [Line Items]
Legal fees	$ 1.7	$ 1.2	$ 1.3

XML

Consolidated Statements of Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
Franchise fees and gross receipts taxes	$ 108.5	$ 111.5	$ 109.3

XML

Long Term Debt - Schedule of Maturities of Long-Term Debt (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Maturities Of Long Term Debt [Line Items]
Total Long-Term Debt	$ 2,923.8	$ 2,975.4
TECO Finance [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Total Long-Term Debt	1,041.2	1,041.2
Tampa Electric Company [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2014	83.3
2015	83.3
2016	83.4
2017	0
2018	254.2
Thereafter	1,146.7
Total Long-Term Debt	1,650.9	1,702.5
PGS [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
Total Long-Term Debt	231.7	231.7
Debt Maturities [Member] | TECO Finance [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2014	0
2015	191.2
2016	250.0
2017	300.0
2018	0
Thereafter	300.0
Total Long-Term Debt	1,041.2
Debt Maturities [Member] | Tampa Electric Company [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2014	83.3
2015	83.3
2016	83.4
2017	0
2018	254.2
Thereafter	1,146.7
Total Long-Term Debt	1,650.9
Debt Maturities [Member] | PGS [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2014	0
2015	0
2016	0
2017	0
2018	50.0
Thereafter	181.7
Total Long-Term Debt	231.7
Debt Maturities [Member] | TECO Energy [Member]
Schedule Of Maturities Of Long Term Debt [Line Items]
2014	83.3
2015	274.5
2016	333.4
2017	300.0
2018	304.2
Thereafter	1,628.4
Total Long-Term Debt	$ 2,923.8

XML

Consolidated Statements of Income and Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues
Total revenues	$ 2,851.3	$ 2,996.6	$ 3,209.9
Expenses
Total expenses	2,387.6	2,440.1	2,626.7
Fuel	680.2	694.7	731.4
Purchased power	64.7	105.3	125.9
Cost of natural gas sold	142.2	155.7	210.4
Other	524.4	462.5	436.9
Depreciation and amortization	329.5	330.6	317.2
Taxes, other than income	215.1	222.3	223.7
Income from operations	463.7	556.5	583.2
Other income
Allowance for other funds used during construction	6.3	2.6	1.0
Total other income	9.9	10.8	7.7
Interest charges
Interest on long-term debt	170.5	185.0	198.0
Allowance for borrowed funds used during construction	(3.6)	(1.5)	(0.6)
Total interest charges	166.9	183.5	197.4
Income from continuing operations before provision for income taxes	306.7	383.8	393.5
Provision for income taxes	108.9	137.8	142.7
Net income attributable to TECO Energy	197.7	212.7	272.6
Other comprehensive income, net of tax
Net unrealized (loss) gain on cash flow hedges	1.4	(4.2)	(0.8)
Other comprehensive income (loss), net of tax	17.8	(9.0)	(4.8)
Comprehensive income	215.5	203.7	267.8
Tampa Electric Company [Member]
Revenues
Electric (includes franchise fees and gross receipts taxes of $88.0 in 2013, $91.1 in 2012 and $85.6 in 2011)	1,950.1	1,981.0	2,020.1
Gas (includes franchise fees and gross receipts taxes of $20.5 in 2013, $20.4 in 2012 and $23.7 in 2011)	392.7	397.0	450.5
Total revenues	2,342.8	2,378.0	2,470.6
Expenses
Total expenses	1,884.5	1,890.0	1,954.3
Fuel	680.2	694.7	731.4
Purchased power	64.7	105.3	125.9
Cost of natural gas sold	142.6	155.8	210.4
Other	523.6	462.0	436.4
Depreciation and amortization	290.3	288.2	270.5
Taxes, other than income	183.1	184.0	179.7
Income from operations	458.3	488.0	516.3
Other income
Allowance for other funds used during construction	6.3	2.6	1.0
Other income, net	5.1	4.1	2.9
Total other income	11.4	6.7	3.9
Interest charges
Interest on long-term debt	105.0	119.6	128.6
Other interest	3.9	7.7	11.5
Allowance for borrowed funds used during construction	(3.6)	(1.5)	(0.6)
Total interest charges	105.3	125.8	139.5
Income from continuing operations before provision for income taxes	364.4	368.9	380.7
Provision for income taxes	138.8	141.7	145.4
Net income attributable to TECO Energy	225.6	227.2	235.3
Other comprehensive income, net of tax
Net unrealized (loss) gain on cash flow hedges	0.9	(4.1)	0.7
Other comprehensive income (loss), net of tax	0.9	(4.1)	0.7
Comprehensive income	$ 226.5	$ 223.1	$ 236.0

XML

Significant Accounting Policies - Estimated Useful Lives of Depreciable Property (Detail)	12 Months Ended
	Dec. 31, 2013
Minimum [Member] | Building and Improvements [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	5 years
Minimum [Member] | Office Equipment and Furniture [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	3 years
Minimum [Member] | Vehicles, Mining and Other Equipment [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	2 years
Minimum [Member] | Coal Processing Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	7 years
Minimum [Member] | Computer Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	2 years
Maximum [Member] | Building and Improvements [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	40 years
Maximum [Member] | Office Equipment and Furniture [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	30 years
Maximum [Member] | Vehicles, Mining and Other Equipment [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	15 years
Maximum [Member] | Coal Processing Facilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	20 years
Maximum [Member] | Computer Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciable property estimated useful lives	15 years

XML

Employee Postretirement Benefits - Schedule of Fair Value Hierarchy Plan's Investments (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 593,000,000	$ 529,100,000
Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		214,800,000
Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,700,000	64,800,000
Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(40,800,000)	(72,800,000)
Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18,900,000	35,300,000
Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,900,000	9,000,000
Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300,000	600,000
Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,800,000	23,100,000
Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	900,000
Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500,000	600,000
Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1,100,000
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	319,700,000	287,700,000
Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91,600,000	125,300,000
Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,000,000	6,200,000
Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,700,000	2,000,000
Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	800,000	800,000
Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	172,600,000	153,400,000
Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,000,000
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	251,200,000	63,700,000
Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	94,100,000
Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,300,000	8,000,000
Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,700,000	53,000,000
Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,600,000	19,800,000
Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	500,000
Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,700,000	17,600,000
Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,300,000	2,500,000
Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85,100,000
Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		300,000
Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(800,000)
Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000
Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(500,000)
Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(400,000)	(400,000)
Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		49,400,000
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	280,700,000	287,900,000
Level 1 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 1 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,700,000	64,800,000
Level 1 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(40,800,000)	(72,800,000)
Level 1 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,900,000	9,000,000
Level 1 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,900,000	9,000,000
Level 1 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 1 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	268,900,000	286,900,000
Level 1 [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91,600,000	125,300,000
Level 1 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,000,000	6,200,000
Level 1 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,700,000	2,000,000
Level 1 [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	172,600,000	153,400,000
Level 1 [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 1 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 1 [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 1 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 1 [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 1 [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	312,300,000	241,200,000
Level 2 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		214,800,000
Level 2 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	11,000,000	26,300,000
Level 2 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300,000	600,000
Level 2 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,800,000	23,100,000
Level 2 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	900,000
Level 2 [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500,000	600,000
Level 2 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1,100,000
Level 2 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,800,000	800,000
Level 2 [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	800,000	800,000
Level 2 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,000,000
Level 2 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	251,200,000	63,700,000
Level 2 [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	94,100,000
Level 2 [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,300,000	8,000,000
Level 2 [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,700,000	53,000,000
Level 2 [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,600,000	19,800,000
Level 2 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	500,000
Level 2 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,700,000	17,600,000
Level 2 [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,300,000	2,500,000
Level 2 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85,100,000
Level 2 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		300,000
Level 2 [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(800,000)
Level 2 [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000
Level 2 [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(500,000)
Level 2 [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Level 2 [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(400,000)	(400,000)
Level 2 [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Level 2 [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		49,400,000
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 3 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 3 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 3 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 3 [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 3 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 3 [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 3 [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Tampa Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	593,000,000	529,100,000
Tampa Electric Company [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,700,000	64,800,000
Tampa Electric Company [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(40,800,000)	(72,800,000)
Tampa Electric Company [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18,900,000	35,300,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,900,000	9,000,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300,000	600,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,800,000	23,100,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	900,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500,000	600,000
Tampa Electric Company [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1,100,000
Tampa Electric Company [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	319,700,000	287,700,000
Tampa Electric Company [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91,600,000	125,300,000
Tampa Electric Company [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,000,000	6,200,000
Tampa Electric Company [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,700,000	2,000,000
Tampa Electric Company [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	800,000	800,000
Tampa Electric Company [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	172,600,000	153,400,000
Tampa Electric Company [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,000,000
Tampa Electric Company [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	251,200,000	214,800,000
Tampa Electric Company [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	94,100,000	49,400,000
Tampa Electric Company [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,300,000	8,000,000
Tampa Electric Company [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,700,000	53,000,000
Tampa Electric Company [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,600,000	19,800,000
Tampa Electric Company [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	500,000
Tampa Electric Company [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,700,000	17,600,000
Tampa Electric Company [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,300,000	2,500,000
Tampa Electric Company [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85,100,000	63,700,000
Tampa Electric Company [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		300,000
Tampa Electric Company [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(800,000)
Tampa Electric Company [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000
Tampa Electric Company [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(500,000)
Tampa Electric Company [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(400,000)	(400,000)
Tampa Electric Company [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	280,700,000	287,900,000
Tampa Electric Company [Member] | Level 1 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,700,000	64,800,000
Tampa Electric Company [Member] | Level 1 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(40,800,000)	(72,800,000)
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,900,000	9,000,000
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,900,000	9,000,000
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	268,900,000	286,900,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91,600,000	125,300,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,000,000	6,200,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,700,000	2,000,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	172,600,000	153,400,000
Tampa Electric Company [Member] | Level 1 [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 1 [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	312,300,000	241,200,000
Tampa Electric Company [Member] | Level 2 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	11,000,000	26,300,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	300,000	600,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8,800,000	23,100,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	900,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,500,000	600,000
Tampa Electric Company [Member] | Level 2 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1,100,000
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,800,000	800,000
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	800,000	800,000
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 2 [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,000,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	251,200,000	214,800,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	94,100,000	49,400,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,300,000	8,000,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,700,000	53,000,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,600,000	19,800,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	400,000	500,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,700,000	17,600,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,300,000	2,500,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85,100,000	63,700,000
Tampa Electric Company [Member] | Level 2 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		300,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(800,000)
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(900,000)	(500,000)
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Level 2 [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(400,000)	(400,000)
Tampa Electric Company [Member] | Level 2 [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200,000	100,000
Tampa Electric Company [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Accounts Receivable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Accounts Payable [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Short Term Investment Fund (STIF) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Treasury Bills (T bills) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Repurchase Agreements [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Money Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Cash Equivalents [Member] | Certificates of Deposit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | American Depository Receipt (ADR) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Real Estate Investment Trust (REIT) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Preferred Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Equity Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Equity Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Commingled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Asset Backed Securities (ABS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Mortgage Back Securities (MBS) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | CMO [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Fixed Income Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Debt Securities [Member] | Commercial Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Short Term Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Swaps [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Purchased Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Derivative [Member] | Written Options [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Tampa Electric Company [Member] | Level 3 [Member] | Miscellaneous [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0

XML

Commitments and Contingencies - Letters of Credit and Guarantees (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Guarantor Obligations [Line Items]
2014	$ 10.8
2015-2018	5.7
After 2018	95.8
Total	112.3
Liabilities Recognized at Dec. 31, 2013	6.6
2014	10.8
2015-2018	5.7
After 2018	95.8
Total	112.3
Liabilities Recognized at Dec. 31, 2013	6.6
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 Dec. 31, 2013	0.1
2014	0
2015-2018	0
After 2018	0.7
Total	0.7
Liabilities Recognized at Dec. 31, 2013	0.1
TECO Coal [Member] | Fuel Purchase Related [Member]
Guarantor Obligations [Line Items]
2014	0.8
2015-2018	0.7
After 2018	4.0
Total	5.5
Liabilities Recognized at Dec. 31, 2013	1.5
2014	0.8
2015-2018	0.7
After 2018	4.0
Total	5.5
Liabilities Recognized at Dec. 31, 2013	1.5
Other Subsidiaries [Member] | Guaranty Under Sale Agreement [Member]
Guarantor Obligations [Line Items]
2014	0
2015-2018	5.0
After 2018	0
Total	5.0
Liabilities Recognized at Dec. 31, 2013	5.0
2014	0
2015-2018	5.0
After 2018	0
Total	5.0
Liabilities Recognized at Dec. 31, 2013	5.0
Other Subsidiaries [Member] | Fuel Sales And Transportation [Member]
Guarantor Obligations [Line Items]
2014	10.0
2015-2018	0
After 2018	91.8
Total	101.8
Liabilities Recognized at Dec. 31, 2013	0.1
2014	10.0
2015-2018	0
After 2018	91.8
Total	101.8
Liabilities Recognized at Dec. 31, 2013	$ 0.1

XML

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Stockholder's equity increment	$ 1.1

XML

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations

15. Asset Retirement Obligations

TECO Energy accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

TECO Energy has recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2013 and 2012, these obligations totaled $23.8 million and $23.6 million, respectively.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31, 2013 and 2012, these obligations totaled $4.8 million and $5.0 million, respectively.

For the years ended Dec. 31, 2013, 2012 and 2011, TECO Energy recognized $1.4 million annually of accretion expense associated with AROs in “Depreciation and amortization” on the Consolidated Statements of Income. For the year ended Dec. 31, 2013, $1.4 million of liabilities settled resulted primarily from reclamation costs related to mine closures. For the year ended Dec. 31, 2012, $29.1 million of liabilities settled resulted primarily from asbestos abatement and other dismantling at the generating stations at Tampa Electric.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:
	Dec. 31,
(millions)	2013			2012
Beginning balance	$	28.6		$	53.8
Additional liabilities		0.1			0.7
Liabilities settled		(1.4	)		(29.1	)
Accretion expense		1.4			1.4
Revisions to estimated cash flows		(0.3	)		0.0
Other (1)		0.2			1.8
Ending balance	$	28.6		$	28.6

(1) Accretion recorded as a deferred regulatory asset.

Tampa Electric Company [Member]

Asset Retirement Obligations

12. Asset Retirement Obligations

TEC accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

For the year ended Dec. 31, 2012, $27.6 million of liabilities settled resulted primarily from asbestos abatement and other dismantling at the generating stations at Tampa Electric.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:
	Dec. 31,
(millions)	2013			2012
Beginning balance	$	5.0		$	30.8
Additional liabilities		0.1			0.0
Liabilities settled		(0.2	)		(27.6	)
Revisions to estimated cash flows		(0.3	)		0.0
Other (1)		0.2			1.8
Ending balance	$	4.8		$	5.0

(1) Accretion recorded as a deferred regulatory asset.

XML

Accounting for Derivative Instruments and Hedging Activities - Derivatives Designated as Hedging Instruments (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Current liabilities	$ 0.1	$ 14.6
Long-term derivative liabilities	0.2	0.6
Total liabilities	0.3	15.2
Current assets	9.7	0
Long-term derivative assets	0.3	0.2
Total assets	10.0	0.2
Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0.1	0.5
Long-term derivative liabilities	0	0.4
Total liabilities	0.1	0.9
Current assets	0.2	0
Long-term derivative assets	0	0
Total assets	0.2	0
Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0	14.1
Long-term derivative liabilities	0.2	0.2
Total liabilities	0.2	14.3
Current assets	9.5	0
Long-term derivative assets	0.3	0.2
Total assets	9.8	0.2
Derivatives Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Total liabilities	0.3	15.2
Total assets	10.0	0.2
Derivatives Designated as Hedging Instruments [Member] | Diesel Fuel Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0.1	0.5
Long-term derivative liabilities	0	0.4
Current assets	0.2	0
Long-term derivative assets	0	0
Derivatives Designated as Hedging Instruments [Member] | Natural Gas Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current liabilities	0	14.1
Long-term derivative liabilities	0.2	0.2
Current assets	9.5	0
Long-term derivative assets	$ 0.3	$ 0.2

XML

Dispositions - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	2 Months Ended	12 Months Ended
	Mar. 01, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 27, 2012
Subsidiary or Equity Method Investee [Line Items]
Proceeds from sale					$ 227.5
Repayment of debt	75.0	51.6	650.4	153.6
Sale resulted after-tax charge associated with foreign tax credits			22.9
San Jos And Alborada Power Stations [Member]
Subsidiary or Equity Method Investee [Line Items]
Proceeds from sale					227.5
TECO Guatemala [Member]
Subsidiary or Equity Method Investee [Line Items]
Net proceeds from sale		197.0
Repayment of debt		25.3
San Jose Power Station [Member]
Subsidiary or Equity Method Investee [Line Items]
Sale after tax book loss		28.6
Sale resulted after-tax charge associated with foreign tax credits		$ 22.9

XML

Discontinued Operations - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended		12 Months Ended
	Dec. 19, 2013	Sep. 27, 2012	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group		$ 227.5
Percentage of ownership in TCAE by TPS GO		96.06%
Foreign tax credits			22.9
Awarded damages	21.1
Prime interest rate	2.00%
Reimburse costs incurred	7.5
TPS GO [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group		12.5
TPS SJI [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group		213.5
TGS [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of ownership interests, Disposal Group		$ 1.5

XML

Employee Postretirement Benefits - Schedule of Funded Status (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 593,000,000	$ 529,100,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	593,000,000	529,100,000	467,600,000
Less: Benefit obligation (PBO/APBO)	666,000,000	715,000,000	646,400,000
Funded status at end of year	(73,000,000)	(185,900,000)
Unrecognized net actuarial loss	173,100,000	270,300,000
Unrecognized prior service (benefit) cost	(400,000)	(700,000)
Net amount required to be recognized at end of year	99,700,000	83,700,000
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0	0
Less: Benefit obligation (PBO/APBO)	208,100,000	230,300,000	216,500,000
Funded status at end of year	(208,100,000)	(230,300,000)
Unrecognized net actuarial loss	19,700,000	42,700,000
Unrecognized prior service (benefit) cost	(700,000)	(1,000,000)
Net amount required to be recognized at end of year	(189,100,000)	(188,600,000)
TECO Energy [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	593,000,000	529,100,000	467,600,000
Less: Benefit obligation (PBO/APBO)	666,000,000	715,000,000	646,400,000
Funded status at end of year	(73,000,000)	(185,900,000)
Unrecognized net actuarial loss	173,100,000	270,300,000
Unrecognized prior service (benefit) cost	(400,000)	(700,000)
Net amount required to be recognized at end of year	99,700,000	83,700,000
Unrecognized net transition obligation	0	0
TECO Energy [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0	0
Less: Benefit obligation (PBO/APBO)	208,100,000	230,300,000	216,500,000
Funded status at end of year	(208,100,000)	(230,300,000)
Unrecognized net actuarial loss	19,700,000	42,700,000
Unrecognized prior service (benefit) cost	(700,000)	(1,000,000)
Net amount required to be recognized at end of year	(189,100,000)	(188,600,000)
Unrecognized net transition obligation	$ 0	$ 0

XML

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Principles of Consolidation and Basis of Presentation

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiaries do not have majority ownership or exercise control.

For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).

Use of Estimates

Use of Estimates

The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.

Restricted Cash

Restricted Cash

Restricted cash of $8.7 million related to cash held in escrow for the 2003 sale of HPP, was released from escrow in 2012 upon maturity of debt financing that was held by the purchaser of HPP. There was no restricted cash at Dec. 31, 2013.

Cash Equivalents

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Planned Major Maintenance

Planned Major Maintenance

Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed as incurred. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.

Tampa Electric and PGS expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

Depreciation

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:

Asset	Estimated Useful Lives
Building and improvements	5 - 40 years
Office equipment and furniture	3 - 30 years
Vehicles, mining and other equipment	2 - 15 years
Coal processing facilities	7 - 20 years
Computer software	2 - 15 years

Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $316.5 million, $309.3 million and $306.6 million, respectively.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.

Inventory

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business. TECO Coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories are stated at the lower of cost or market on an average cost basis.

Fuel Inventory (millions)	Dec. 31, 2013		Dec. 31, 2012
TEC	$	93.7	$	89.1
TECO Coal		25.0		34.5
Total	$	118.7	$	123.6

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Tampa Electric and PGS are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).

Deferred Income Taxes

Deferred Income Taxes

TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).

Investment Tax Credits

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Revenue Recognition

Revenue Recognition

TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues for TECO Coal shipments, both domestic and international, are recognized when title and risk of loss transfer to the customer.

Revenues for energy marketing operations at TECO Energy Source are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2013, 2012 and 2011 were $23.1 million, $13.8 million and $2.5 million, respectively.

Shipping and Handling

Shipping and Handling

TECO Coal includes the costs to ship product to customers in “Operation & maintenance other expense - Mining related costs” on the Consolidated Statements of Income which for the years ended Dec. 31, 2013, 2012 and 2011 were $8.2 million, $9.0 million and $16.6 million, respectively.

Cash Flows Related to Derivatives and Hedging Activities

Cash Flows Related to Derivatives and Hedging Activities

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

Revenues and Cost Recovery

Revenues and Cost Recovery

Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.

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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

Deferred Charges and Other Assets

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of mining development costs amortized on a per ton basis and offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and includes them in “Deferred charges and other assets” on TECO Energy’s Consolidated Balance Sheet and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.

Deferred Credits and Other Liabilities

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities, and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2013 and 2012 ranged from 3.51% to 4.86% and 2.60% to 4.00%, respectively.

Stock-Based Compensation

Stock-Based Compensation

TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.

Receivables and Allowance for Uncollectible Accounts

Receivables and Allowance for Uncollectible Accounts

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on Tampa Electric’s and PGS’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. TECO Coal’s receivables consist of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts is established based on TECO Coal’s collection experience. Circumstances that could affect TECO Coal’s estimates of uncollectable receivables include customer credit issues and general economic conditions. Accounts are written off once they are determined to be uncollectible.

Reclassifications

Reclassifications

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

Tampa Electric Company [Member]

Cash Equivalents

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Planned Major Maintenance

Planned Major Maintenance

Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with FPSC and FERC regulations.

Depreciation

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

• the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

• the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2013 and 3.8% for 2012 and 3.6% for 2011. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2013, 2012 and 2011 was $284.2 million, $275.1 million and $263.7 million, respectively.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between TEC and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric will begin using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. Total AFUDC for the years ended Dec. 31, 2013, 2012 and 2011 was $9.9 million, $4.1 million and $1.6 million, respectively.

Inventory

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

Deferred Income Taxes

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

Investment Tax Credits

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Revenue Recognition

Revenue Recognition

TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

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, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows.

Revenues and Cost Recovery

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2013 and 2012, unbilled revenues of $46.7 million and $49.0 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $64.7 million, $105.3 million and $125.9 million, for the years ended Dec. 31, 2013, 2012 and 2011, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TEC is 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 Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $108.5 million, $111.5 million and $109.3 million for the years ended Dec. 31, 2013, 2012 and 2011, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.

Reclassifications

Reclassifications

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

Basis of Accounting

Basis of Accounting

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with GAAP in all material respects.

The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance.

TEC’s retail and wholesale businesses are regulated by the FPSC and related FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Principles of Consolidation

Principles of Consolidation

TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the preparation of financial statements in accordance with GAAP. Actual results could differ from these estimates.

For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).

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Preferred Stock

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Preferred Stock

8. Preferred Stock

Preferred stock of TECO Energy – $1 par

10 million shares authorized, none outstanding.

Preference stock (subordinated preferred stock) of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – $100 par

1.5 million shares authorized, none outstanding.

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Other Comprehensive Income - Accumulated Other Comprehensive Loss (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	$ (7.8)	$ (9.2)
Total accumulated other comprehensive loss	(13.2)	(31.0)
Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit gains, prior service costs and transition obligations	(20.5)	(32.9)
Other Postretirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized other benefit gains, prior service costs and transition obligations	15.1	11.1
Tampa Electric Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses from cash flow hedges	(7.8)	(8.7)
Total accumulated other comprehensive loss	$ (7.8)	$ (8.7)